SilverBow Resources (SBOW) 10-Q 4 May 23 2023 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2023	Apr. 28, 2023
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Mar. 31, 2023
Entity File Number	1-8754
Entity Registrant Name	SILVERBOW RESOURCES, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	20-3940661
Entity Address, Address Line One	920 Memorial City Way
Entity Address, Address Line Two	Suite 850
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77024
City Area Code	281
Local Phone Number	874-2700
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	SBOW
Security Exchange Name	NYSE
Entity 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	2023
Document Fiscal Period Focus	Q1
Entity Common Stock, Shares Outstanding		22,616,736

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 2,167	$ 792
Accounts receivable, net	63,940	89,714
Fair value of commodity derivatives	79,979	52,549
Other current assets	2,672	2,671
Total Current Assets	148,758	145,726
Property and Equipment:
Property and Equipment, full cost method	2,638,716	2,529,223
Less - Accumulated depreciation, depletion, and amortization	(1,048,062)	(1,004,044)
Net Furniture, Fixtures and other equipment	1,590,654	1,525,179
Capitalized Costs, unproved property balance	18,196	16,272
Right of Use Assets	10,229	12,077
Fair value of long-term commodity derivatives	26,645	24,172
Other Long-Term Assets	8,646	9,208
Total Assets	1,784,932	1,716,362
Current Liabilities:
Accounts payable and accrued liabilities	51,599	60,200
Fair value of commodity derivatives	13,450	40,796
Accrued capital costs	45,264	56,465
Accrued interest	2,225	2,665
Current lease liability	7,165	8,553
Undistributed oil and gas revenues	16,743	27,160
Total Current Liabilities	136,446	195,839
Long-Term Debt	705,715	688,531
Non-current Lease Liability	3,303	3,775
Deferred Tax Liabilities	42,753	16,141
Asset Retirement Obligation	9,451	9,171
Fair value of long-term commodity derivatives	2,394	7,738
Other Long-Term Liabilities	565	3,588
Stockholders' Equity:
Preferred Stock, Value, Outstanding	0	0
Common stock, $0.01 par value	231	227
Additional paid-in capital	577,293	576,118
Treasury stock held, at cost	(10,479)	(7,534)
Retained earnings (Accumulated deficit)	317,260	222,768
Total Stockholders' Equity (Deficit)	884,305	791,579
Total Liabilities and Stockholders' Equity	$ 1,784,932	$ 1,716,362
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	23,081,653	22,663,135
Common Stock, Shares, Outstanding	22,602,018	22,309,740
Treasury Stock, Shares	479,635	353,395

Condensed Consolidated Balanc_2

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

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Income Statement [Abstract]
Oil and gas sales	$ 139,954	$ 129,656
Costs and Expenses [Abstract]
General and administrative, net	7,664	4,786
Depreciation, depletion, and amortization	43,998	21,154
Accretion of asset retirement obligation	224	99
Lease operating costs	20,560	9,125
Workovers	779	647
Transportation and gas processing	11,520	6,352
Severance and other taxes	9,385	7,764
Operating Expenses	94,130	49,927
Operating Income (Loss)	45,824	79,729
Net gain (loss) on commodity derivatives	92,249	(140,242)
Interest expense, net	(16,745)	(6,557)
Other Nonoperating Income (Expense)	(24)	61
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	121,304	(67,009)
Provision (Benefit) for Income Taxes	26,812	(2,754)
Net Income (Loss)	$ 94,492	$ (64,255)
Per Share Amounts-
Earnings Per Share, Basic	$ 4.21	$ (3.84)
Earnings Per Share, Diluted	$ 4.17	$ (3.84)
Weighted Average Shares Outstanding - Basic	22,440	16,719
Weighted Average Shares Outstanding - Diluted	22,634	16,719

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, 2021	$ 292,532	$ 168	$ 413,017	$ (2,984)	$ (117,669)
Purchase of treasury shares	(2,462)	0	0	(2,462)	0
Treasury Stock, Value, Acquired Pursuant to Purchase Price Adjustment	(1,146)	0	0	(1,146)	0
Vesting of share-based compensation	0	3	(3)	0	0
Issuance pursuant to acquisition	12	0	12	0	0
Amortization of share-based compensation	1,101	0	1,101	0	0
Net Income (Loss)	(64,255)	0	0	0	(64,255)
Ending Balance at Mar. 31, 2022	$ 225,782	171	414,127	(6,592)	(181,924)
Purchase of treasury stock (shares)	96,012
Vesting of share-based compensation (shares)	318,390
Treasury Shares Pursuant to Purchase Price Adjustment (shares)	41,191
Issuance pursuant to acquisition (shares)	489
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

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021
Cash Flows from Operating Activities:
Net Income (Loss)	$ 94,492	$ (64,255)
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion, and amortization	43,998	21,154
Accretion of asset retirement obligation	224	99	$ 534
Deferred income taxes	26,612	(2,902)
Stock-based compensation expenses	1,124	1,047
Loss (gain) on derivatives	(92,249)	140,242
Cash settlements on derivatives	18,699	(24,554)
Settlements of asset retirement obligations	(3)	(38)
Other Noncash Income (Expense)	756	1,138
(Increase) decrease in accounts receivable and other current assets	30,687	2,794
Increase (decrease) in accounts payable and accrued liabilities	(24,504)	(10,144)
Increase (Decrease) in Income Taxes Payable	300	149
Increase (decrease) in accrued interest	(441)	165
Net Cash Provided by (Used in) Operating Activities	99,695	64,895
Cash Flows from Investing Activities:
Additions to property and equipment	(111,285)	(35,228)
Acquisition of oil and gas properties	(1,090)	436
Net Cash Provided by (Used in) Investing Activities	(112,375)	(34,792)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	121,000	122,000
Payments of bank borrowings	(104,000)	(149,000)
Purchase of treasury shares	(2,945)	(2,462)
Payments of Debt Issuance Costs	0	(117)
Net Cash Provided by (Used in) Financing Activities	14,055	(29,579)
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash	1,375	524
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	2,167	1,645	$ 792	$ 1,121
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	16,434	5,816
Changes in capital accounts payable and capital accruals	(3,097)	5,037
Non-cash equity consideration for acquisitions	$ 0	$ 1,134

General Information

General Information	3 Months Ended
	Mar. 31, 2023
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, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested. The condensed consolidated financial statements included herein are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2023
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. Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. Through April 28, 2023, 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, 2023: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2024 Contracts 3Q24 920 $ 71.60 Collar Contracts 2023 Contracts 3Q23 46,000 $ 72.00 $ 82.83 4Q23 46,000 $ 71.00 $ 80.65 2025 Contracts 1Q25 193,500 $ 64.47 $ 75.84 Natural Gas Derivative Contracts Total Volumes Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Collar Contracts 2025 Contracts 1Q25 3,330,000 $ 4.00 $ 5.27 There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements. Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation, • estimates related to the collectability of accounts receivable and the creditworthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”), • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, including the valuation of our deferred tax assets, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, • estimates 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, 2023 and 2022, such internal costs when capitalized totaled $1.4 million and $1.0 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, 2023 and 2022. 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, 2023 December 31, 2022 Property and Equipment Proved oil and gas properties $ 2,614,332 $ 2,506,853 Unproved oil and gas properties 18,196 16,272 Furniture, fixtures and other equipment 6,188 6,098 Less – Accumulated depreciation, depletion, amortization & impairment (1,048,062) (1,004,044) Property and Equipment, Net $ 1,590,654 $ 1,525,179 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and 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, 2023 and 2022. If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods. Accounts Receivable, Net. We assess the collectability of accounts receivable based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's credit losses based on these assessments are considered immaterial. At both March 31, 2023 and December 31, 2022, we had an allowance of less than $0.1 million. The allowance has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets. At March 31, 2023, our “Accounts receivable, net” balance included $44.3 million for oil and gas sales, $1.2 million due from joint interest owners, $5.7 million for severance tax credit receivables and $12.7 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 due from 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, 2023 and 2022 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $2.7 million and $1.6 million for the three months ended March 31, 2023 and 2022, 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 was approximately 22% and (4)% for three months ended March 31, 2023 and 2022, respectively. The Company recorded an income tax provision of $26.8 million for the three months ended March 31, 2023 and an income tax benefit of $2.8 million for the three months ended March 31, 2022. The effective tax rate for the three months ended March 31, 2023 primarily related to the statutory federal tax rate plus the impact of the Texas Margin Tax. The effective tax rate for the three months ended March 31, 2022 related to the effects of a valuation allowance previously established against the Company’s net federal deferred tax assets in excess of deferred tax liabilities. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income or loss. 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, 2023 and December 31, 2022, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. Revenue Recognition . Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended March 31, 2023 and 2022 (in thousands): Three Months Ended March 31, 2023 Three Months Ended March 31, 2022 Oil, natural gas and NGLs sales: Oil $ 74,655 $ 39,741 Natural gas 52,922 77,372 NGLs 12,377 12,543 Total $ 139,954 $ 129,656 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, 2023 December 31, 2022 Trade accounts payable $ 20,254 $ 23,660 Accrued operating expenses 13,735 10,572 Accrued compensation costs 1,510 4,814 Asset retirement obligations – current portion 1,598 1,284 Accrued non-income based taxes 5,836 4,849 Accrued corporate and legal fees 306 388 WTI contingency payouts - current portion 2,023 1,600 Payable for settled derivatives 984 6,026 Other payables 5,353 7,007 Total accounts payable and accrued liabilities $ 51,599 $ 60,200 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. 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, 2023, we purchased 126,240 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. For the three months ended March 31, 2022, we purchased 96,012 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares and received 41,191 shares in conjunction with our post-closing settlement for a previously disclosed acquisition. New Accounting Pronouncements . In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures. In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. As of March 31, 2023, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01.

Leases Leases (Notes)

Leases Leases (Notes)	3 Months Ended
	Mar. 31, 2023
Leases [Abstract]
Lessee, Operating Leases	(3) Leases The Company follows the Financial Accounting Standards Board'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 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, 2023, 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, 2023, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands): As of March 31, 2023 2023 (Remaining) $ 6,742 2024 2,028 2025 1,027 2026 827 2027 57 Thereafter 478 Total undiscounted lease payments 11,159 Present value adjustment (691) Net operating lease liabilities $ 10,468

Share-Based Compensation

Share-Based Compensation	3 Months Ended
	Mar. 31, 2023
Share-Based Payment Arrangement [Abstract]
Share-Based Compensation	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 $1.1 million and $1.0 million for the three months ended March 31, 2023 and 2022, respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended March 31, 2023 and 2022. 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, 2023, 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, 2023: Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 196,162 $ 26.46 Options granted — $ — Options exercised — $ — Options outstanding, end of period 196,162 $ 26.46 Options exercisable, end of period 196,162 $ 26.46 Our outstanding stock option awards had $0.1 million measurable aggregate intrinsic value at March 31, 2023. At March 31, 2023, the weighted-average remaining contract life of stock option awards outstanding was 4.1 years and exercisable was 4.1 years. The total intrinsic value of stock option awards exercisable was $0.1 million as of March 31, 2023. Restricted Stock Units The compensation cost related to restricted stock awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one As of March 31, 2023, we had $6.6 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 2.4 years. The following table provides information regarding RSU activity for the three months ended March 31, 2023: RSUs Wtd. Avg. Grant Price RSUs outstanding, beginning of period 227,114 $ 21.18 RSUs granted 189,894 $ 23.65 RSUs forfeited (670) $ 26.66 RSUs vested (115,108) $ 15.70 RSUs outstanding, end of period 301,230 $ 24.82 Performance-Based Stock Units On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned was based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contained market conditions which allowed a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards had a cliff-vesting period of three On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of two On February 23, 2022, the Company granted 122,111 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2022 to December 31, 2024. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $36.47 per unit or 150.93% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three On February 23, 2023, the Company granted 120,749 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2023 to December 31, 2025. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $31.18 per unit or 136.28% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of three As of March 31, 2023, we had $6.4 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 2.3 years. The following table provides information regarding performance-based stock unit activity for the three months ended March 31, 2023: PSUs Wtd. Avg. Grant Price Performance based stock units outstanding, beginning of period 283,500 $ 23.18 Performance based stock units granted 120,749 $ 31.18 Performance based stock units incremental shares granted 142,021 $ 13.13 Performance based stock units vested (303,410) $ 13.13 Performance based stock units outstanding, end of period 242,860 $ 33.84

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2023
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, 2023 and 2022 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, 2023 Three Months Ended March 31, 2022 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 94,492 22,440 $ 4.21 $ (64,255) 16,719 $ (3.84) Dilutive Securities: Performance Based Stock Unit Awards 97 — RSU Awards 91 — Stock Option Awards 6 — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 94,492 22,634 $ 4.17 $ (64,255) 16,719 $ (3.84) There were 0.1 million stock options to purchase shares which were not included in the computation of Diluted EPS for the three months ended March 31, 2023 because they were antidilutive, while 0.2 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended March 31, 2022 because they were antidilutive due to the net loss. There were less than 0.1 million shares of RSUs that were not included in the computation of Diluted EPS for the three months ended March 31, 2023 because they were antidilutive while less than 0.1 million shares of RSUs were excluded from Diluted EPS for the three months ended March 31, 2022 because they were antidilutive due to the net loss.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2023
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt The Company's long-term debt consisted of the following (in thousands): March 31, 2023 December 31, 2022 Credit Facility Borrowings due 2026 (1) $ 559,000 $ 542,000 Second Lien Notes due 2026 150,000 150,000 709,000 692,000 Unamortized discount on Second Lien Notes due 2026 (835) (882) Unamortized debt issuance cost on Second Lien Notes due 2026 (2,450) (2,587) Long-Term Debt, net $ 705,715 $ 688,531 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of March 31, 2023 and December 31, 2022, we had $8.1 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $559.0 million and $542.0 million as of March 31, 2023 and December 31, 2022, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). The Credit Facility matures October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes), and provides for a maximum credit amount of $2.0 billion, subject to the current borrowing base of $775.0 million. The borrowing base is regularly redetermined in 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. In conjunction with its regularly scheduled semi-annual redeterminations, the Company reaffirmed the borrowing base and elected commitment amount under the Credit Facility at $775.0 million, effective November 22, 2022, and again on March 20, 2023. 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, 2023, and no outstanding letters of credit as of December 31, 2022. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions , changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves. Interest under the Credit Facility accrues at the Company’s option either at an Alternate 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 ranges 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, 2023, the Company's weighted average interest rate on Credit Facility borrowings was 8.13%. 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, 2023, the Company was in compliance with all financial covenants under the Credit Agreement. Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable. Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $11.9 million and $3.2 million for the three months ended March 31, 2023 and 2022, respectively. The amount of commitment fee amortization included in interest expense, net was $0.3 million for both the three months ended March 31, 2023 and 2022. Senior Secured Second Lien Notes . On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million. Effective November 12, 2021, the Company entered into the Second Amendment to the Note Purchase Agreement, which extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying down the principal amount of the Second Lien from $200.0 million to $150.0 million. The Company made the $50.0 million redemption of the Second Lien notes on November 29, 2021. Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Note Purchase Agreement. To the extent that a payment, insolvency, or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility. The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes at no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote. The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 90% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 90% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%. The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator of the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiary and in the denominator the total net indebtedness of the Company and its restricted subsidiary, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 3.25 to 1.0 as of the last day of each fiscal quarter. As of March 31, 2023, the Company was in compliance with all financial covenants under the Second Lien. The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and payable. As of March 31, 2023, total net amounts recorded for the Second Lien were $146.7 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $4.8 million and $3.4 million for the three months ended March 31, 2023 and 2022, 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, 2022, the Company capitalized $0.1 million for debt issuance costs incurred in connection with the amendments to our Credit Facility. There were no capitalized debt issuance costs during the three months ended March 31, 2023.

Acquisitions and Dispositions A

Acquisitions and Dispositions Acquisitions and Dispostions	3 Months Ended
	Mar. 31, 2023
Discontinued Operations and Disposal Groups [Abstract]
Acquisitions and Dispositions	(7) Acquisitions and Dispositions November 2021 Acquisition On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford. The acquired assets included wells and acreage in La Salle, McMullen, DeWitt and Lavaca counties. After consideration of closing adjustments, total aggregate consideration was approximately $77.4 million, consisting of $37.6 million in cash, 1,351,961 shares of our common stock valued at approximately $37.9 million based on the Company's share price on the closing date, and contingent consideration with an estimated fair value of $1.9 million. The contingent consideration consists of up to three earn-out payments of $1.6 million per year for each of 2022, 2023 and 2024, contingent upon the average monthly settlement price of WTI exceeding $70 per barrel for such year (the “2021 WTI Contingency Payout”). During the three months ended March 31, 2023 and 2022, the Company recorded losses of less than $0.1 million and $1.2 million, respectively, related to the 2021 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the consolidated statements of operation and recorded $1.6 million in earn-out consideration payable to the seller related to the 2022 calendar year in “Accounts payable and accrued liabilities” on the condensed consolidated balance sheet as of December 31, 2022. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 9 of these Notes to Consolidated Financial Statements. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. May 2022 Acquisition On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”). After consideration of closing adjustments, total aggregate consideration was approximately $67.5 million, consisting of $27.7 million in cash and 1,300,000 shares of our common stock valued at approximately $39.8 million based on the Company's share price on the closing date. We incurred approximately $0.5 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands): Total Cost Cash consideration $ 27,709 Equity consideration 39,767 Total Consideration 67,476 Transaction costs 466 Total Cost of Transaction $ 67,942 Allocation of Total Cost Assets Oil and gas properties $ 84,810 Total assets 84,810 Liabilities Accounts payable and accrued liabilities 199 Fair value of commodity derivatives 16,511 Asset retirement obligations 158 Total Liabilities $ 16,868 Net Assets Acquired $ 67,942 June 2022 Acquisition On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC (collectively, “Sundance”). After consideration of closing adjustments, total aggregate consideration was approximately $344.9 million, consisting of $220.9 million in cash, 4,148,472 shares of our common stock valued at approximately $117.7 million based on the Company's share price on the closing date, accrued purchase price adjustments receivable of $1.0 million and contingent consideration with an estimated fair value of $7.4 million. The contingent consideration consists of up to two earn-out payments of $7.5 million each, contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil exceeding $95 per barrel for the period from April 13, 2022 through December 31, 2022 which would trigger a payment of $7.5 million in 2023 and $85 per barrel for 2023 which would trigger a payment of $7.5 million in 2024 (the “2022 WTI Contingency Payout”). The contingent payout for the period of April 13, 2022 through December 31, 2022 did not materialize. During the three months ended March 31, 2023, the Company recorded gains of $1.0 million related to the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. For further discussion of the fair value related to the Company's contingent consideration, refer to Note 9 of these Notes to Consolidated Financial Statements. The acquisition is subject to further customary post-closing adjustments. We incurred approximately $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The following table represents the allocation of the total cost of the acquisition to the assets acquired and liabilities assumed (in thousands): Total Cost Cash consideration $ 220,866 Equity consideration 117,651 Fair value of contingent consideration 7,422 Accrued purchase price adjustments receivable (1,000) Total Consideration 344,939 Transaction costs 6,766 Total Cost of Transaction $ 351,705 Allocation of Total Cost Assets Other current assets $ 4,202 Oil and gas properties 397,401 Right of use assets 890 Total assets 402,493 Liabilities Accounts payable and accrued liabilities 13,687 Fair value of commodity derivatives 33,767 Non-current lease liability 890 Asset retirement obligations 2,444 Total Liabilities $ 50,788 Net Assets Acquired $ 351,705 August 2022 Acquisition On August 15, 2022, the Company closed the acquisition of certain oil and gas assets in Webb County, Texas. After consideration of closing adjustments, total consideration was approximately $31.2 million. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. October 2022 Acquisition On October 31, 2022, the Company closed the acquisition of certain oil and gas assets in Dewitt and Gonzales Counties, Texas. After consideration of closing adjustments, total consideration was approximately $80.1 million. The acquisition is subject to further customary post-closing adjustments. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. 2022 Non-strategic Dispositions During 2022, the Company closed on multiple dispositions of non-strategic oil and gas assets. After consideration of closing adjustments, total proceeds from the dispositions were approximately $4.3 million. The transactions are subject to further customary post-closing adjustments. There was no gain or loss recognized in connection with the dispositions.

Price-Risk Management Price-Ris

Price-Risk Management Price-Risk Management (Notes)	3 Months Ended
	Mar. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities	(8) Price-Risk Management Activities Derivatives are recorded on the 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, 2023 and 2022, the Company recorded gains of $91.2 million and losses of $139.0 million, respectively, on its commodity derivatives. During the three months ended March 31, 2023 and 2022, the Company recorded gains of $1.0 million and losses of $1.2 million, respectively, related to valuation changes on the 2021 WTI Contingency Payout and 2022 WTI Contingency Payout. The Company collected cash payments of $18.7 million and made cash payments of $24.6 million for settled derivative contracts during the three months ended March 31, 2023 and 2022, respectively. At March 31, 2023 and December 31, 2022, there was $11.8 million and $6.9 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 2023 and January 2023, respectively. At March 31, 2023 and December 31, 2022, we also had $1.0 million and $6.0 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 2023 and January 2023, respectively. The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model. At March 31, 2023, there was $80.0 million and $26.6 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $13.5 million and $2.4 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2022, there was $52.5 million and $24.2 million in current and long-term unsettled derivative assets, respectively, and $40.8 million and $7.7 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 $90.8 million net fair value asset at March 31, 2023, and a $28.2 million net fair value asset at December 31, 2022. For further discussion related to the fair value of the Company's derivatives, refer to Note 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, 2023: 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 2023 Contracts 2Q23 494,575 $ 80.75 3Q23 533,980 $ 77.36 4Q23 569,300 $ 78.26 2024 Contracts 1Q24 227,500 $ 80.78 2Q24 254,050 $ 80.24 3Q24 272,700 $ 76.91 4Q24 256,100 $ 75.98 Collar Contracts 2023 Contracts 2Q23 167,949 $ 53.91 $ 64.89 3Q23 72,847 $ 59.27 $ 66.26 4Q23 72,242 $ 58.54 $ 65.13 2024 Contracts 1Q24 137,700 $ 51.61 $ 65.86 2Q24 33,000 $ 45.00 $ 60.72 2025 Contracts 1Q25 45,000 $ 62.00 $ 69.40 3-Way Collar Contracts 2023 Contracts 2Q23 13,260 $ 44.19 $ 55.04 $ 64.53 3Q23 9,570 $ 43.08 $ 53.41 $ 63.33 4Q23 8,970 $ 43.08 $ 53.38 $ 63.35 2024 Contracts 1Q24 8,247 $ 45.00 $ 57.50 $ 67.85 2Q24 7,757 $ 45.00 $ 57.50 $ 67.85 Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Sub Floor Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2023 Contracts 2Q23 3,816,000 $ 4.55 3Q23 4,816,000 $ 4.57 4Q23 3,887,000 $ 4.71 2024 Contracts 1Q24 2,711,000 $ 5.15 2Q24 7,800,000 $ 3.95 3Q24 7,820,000 $ 4.03 4Q24 7,820,000 $ 4.35 2025 Contracts 1Q25 900,000 $ 5.01 2Q25 910,000 $ 4.12 3Q25 920,000 $ 4.27 4Q25 920,000 $ 4.70 Collar Contracts 2023 Contracts 2Q23 12,141,250 $ 3.28 $ 4.05 3Q23 11,896,400 $ 3.43 $ 4.23 4Q23 12,445,000 $ 3.87 $ 4.80 2024 Contracts 1Q24 7,841,000 $ 4.10 $ 6.19 2Q24 2,823,000 $ 4.05 $ 4.91 3Q24 2,958,000 $ 4.00 $ 5.10 4Q24 2,945,000 $ 4.24 $ 5.63 2025 Contracts 1Q25 1,800,000 $ 4.00 $ 5.41 3-Way Collar Contracts 2023 Contracts 2Q23 310,400 $ 2.04 $ 2.54 $ 3.01 3Q23 233,100 $ 2.00 $ 2.50 $ 2.95 4Q23 219,200 $ 2.00 $ 2.50 $ 2.94 2024 Contracts 1Q24 198,000 $ 2.00 $ 2.50 $ 3.37 2Q24 188,000 $ 2.00 $ 2.50 $ 3.37 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2023 Contracts 2Q23 14,560,000 $ (0.24) 3Q23 14,720,000 $ (0.21) 4Q23 13,800,000 $ (0.23) 2024 Contracts 1Q24 9,100,000 $ (0.01) 2Q24 9,100,000 $ (0.32) 3Q24 9,200,000 $ (0.28) 4Q24 9,200,000 $ (0.31) Houston Ship Channel Fixed Price Contracts 2023 Contracts 2Q23 60,000 $ 2.64 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2023 Contracts 2Q23 341,250 $ 33.12 3Q23 345,000 $ 32.87 4Q23 345,000 $ 32.87 2024 Contracts 1Q24 127,400 $ 29.39 2Q24 127,400 $ 29.39 3Q24 128,800 $ 29.39 4Q24 128,800 $ 29.39

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2023
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, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the 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 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 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, 2023 and December 31, 2022, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements. Fair Value Measurements at (in thousands) Total Quoted Prices in Significant Other Significant March 31, 2023 Assets Natural Gas Derivatives $ 73,197 $ — $ 73,197 $ — Natural Gas Basis Derivatives 4,300 — 4,300 — Oil Derivatives 19,106 — 19,106 — NGL Derivatives 10,022 — 10,022 — Liabilities Natural Gas Derivatives 1,624 — 1,624 — Natural Gas Basis Derivatives 2,999 — 2,999 — Oil Derivatives 11,177 — 11,177 — NGL Derivatives 44 — 44 — 2022 WTI Contingency Payout 1,090 — 1,090 — 2021 WTI Contingency Payout 1,498 — 1,498 — December 31, 2022 Assets Natural Gas Derivatives $ 25,960 $ — $ 25,960 $ — Natural Gas Basis Derivatives 26,023 — 26,023 — Oil Derivatives 14,604 — 14,604 — NGL Derivatives 10,134 — 10,134 — Liabilities Natural Gas Derivatives 28,579 — 28,579 — Natural Gas Basis Derivatives 409 — 409 — Oil Derivatives 19,442 — 19,442 — NGL Derivatives 104 — 104 — 2022 WTI Contingency Payout 2,135 — 2,135 — 2021 WTI Contingency Payout 1,453 — 1,453 — Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying 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, 2023
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, 2022 and the three months ended March 31, 2023 (in thousands): Asset Retirement Obligations as of December 31, 2021 $ 6,050 Accretion expense 534 Liabilities incurred for new wells, acquired wells and facilities construction 3,032 Reductions due to sold wells and facilities (57) Reductions due to plugged wells and facilities (22) Revisions in estimates 919 Asset Retirement Obligations as of December 31, 2022 $ 10,456 Accretion expense 224 Liabilities incurred for new wells, acquired wells and facilities construction 59 Reductions due to plugged wells and facilities (3) Revisions in estimates 313 Asset Retirement Obligations as of March 31, 2023 $ 11,049 At March 31, 2023 and December 31, 2022, approximately $1.6 million and $1.3 million of our asset retirement obligations, respectively, were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies	3 Months Ended
	Mar. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(11) Commitments and Contingencies In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2023
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 impairment calculation, • estimates related to the collectability of accounts receivable and the creditworthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”), • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, including the valuation of our deferred tax assets, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, • estimates 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, 2023 and 2022, such internal costs when capitalized totaled $1.4 million and $1.0 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, 2023 and 2022. 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, 2023 December 31, 2022 Property and Equipment Proved oil and gas properties $ 2,614,332 $ 2,506,853 Unproved oil and gas properties 18,196 16,272 Furniture, fixtures and other equipment 6,188 6,098 Less – Accumulated depreciation, depletion, amortization & impairment (1,048,062) (1,004,044) Property and Equipment, Net $ 1,590,654 $ 1,525,179 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and 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 both March 31, 2023 and December 31, 2022, we had an allowance of less than $0.1 million. The allowance has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.
Supervision Fees	Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations.
Income Taxes	Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. The Company's effective tax was approximately 22% and (4)% for three months ended March 31, 2023 and 2022, respectively. The Company recorded an income tax provision of $26.8 million for the three months ended March 31, 2023 and an income tax benefit of $2.8 million for the three months ended March 31, 2022. The effective tax rate for the three months ended March 31, 2023 primarily related to the statutory federal tax rate plus the impact of the Texas Margin Tax. The effective tax rate for the three months ended March 31, 2022 related to the effects of a valuation allowance previously established against the Company’s net federal deferred tax assets in excess of deferred tax liabilities. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year to date income or loss. 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, 2023 and December 31, 2022, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
Revenue Recognition	Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): March 31, 2023 December 31, 2022 Trade accounts payable $ 20,254 $ 23,660 Accrued operating expenses 13,735 10,572 Accrued compensation costs 1,510 4,814 Asset retirement obligations – current portion 1,598 1,284 Accrued non-income based taxes 5,836 4,849 Accrued corporate and legal fees 306 388 WTI contingency payouts - current portion 2,023 1,600 Payable for settled derivatives 984 6,026 Other payables 5,353 7,007 Total accounts payable and accrued liabilities $ 51,599 $ 60,200
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.
Treasury Stock	Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets.

Leases Leases (Policies)

Leases Leases (Policies)	3 Months Ended
	Mar. 31, 2023
Leases [Abstract]
Lessee, Leases [Policy Text Block]	Leases The Company follows the Financial Accounting Standards Board'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 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, 2023, 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, 2023
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, 2023
Earnings Per Share [Abstract]
Earnings Per Share, Policy	Earnings Per ShareBasic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended March 31, 2023 and 2022 are discussed below.

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Policies)	3 Months Ended
	Mar. 31, 2023
Debt Disclosure [Abstract]
Debt Issuance Costs, Policy	Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.

Price-Risk Management Price-R_2

Price-Risk Management Price-Risk Management (Policies)	3 Months Ended
	Mar. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities, Policy	Price-Risk Management ActivitiesDerivatives are recorded on the 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, 2023
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, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the 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 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 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, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations, Policy	Asset Retirement ObligationsLiabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets.

Commitments and Contingencies_2

Commitments and Contingencies Commitments and Contingencies (Policies)	3 Months Ended
	Mar. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies, Policy	Commitments and Contingencies    In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2023
Accounting Policies [Abstract]
Schedule of Subsequent Events	Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. Through April 28, 2023, 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, 2023: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2024 Contracts 3Q24 920 $ 71.60 Collar Contracts 2023 Contracts 3Q23 46,000 $ 72.00 $ 82.83 4Q23 46,000 $ 71.00 $ 80.65 2025 Contracts 1Q25 193,500 $ 64.47 $ 75.84 Natural Gas Derivative Contracts Total Volumes Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Collar Contracts 2025 Contracts 1Q25 3,330,000 $ 4.00 $ 5.27 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, 2023 December 31, 2022 Property and Equipment Proved oil and gas properties $ 2,614,332 $ 2,506,853 Unproved oil and gas properties 18,196 16,272 Furniture, fixtures and other equipment 6,188 6,098 Less – Accumulated depreciation, depletion, amortization & impairment (1,048,062) (1,004,044) Property and Equipment, Net $ 1,590,654 $ 1,525,179
Disaggregation of Revenue	The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended March 31, 2023 and 2022 (in thousands): Three Months Ended March 31, 2023 Three Months Ended March 31, 2022 Oil, natural gas and NGLs sales: Oil $ 74,655 $ 39,741 Natural gas 52,922 77,372 NGLs 12,377 12,543 Total $ 139,954 $ 129,656
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, 2023 December 31, 2022 Trade accounts payable $ 20,254 $ 23,660 Accrued operating expenses 13,735 10,572 Accrued compensation costs 1,510 4,814 Asset retirement obligations – current portion 1,598 1,284 Accrued non-income based taxes 5,836 4,849 Accrued corporate and legal fees 306 388 WTI contingency payouts - current portion 2,023 1,600 Payable for settled derivatives 984 6,026 Other payables 5,353 7,007 Total accounts payable and accrued liabilities $ 51,599 $ 60,200

Leases Leases (Tables)

Leases Leases (Tables)	3 Months Ended
	Mar. 31, 2023
Leases [Abstract]
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	As of March 31, 2023, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands): As of March 31, 2023 2023 (Remaining) $ 6,742 2024 2,028 2025 1,027 2026 827 2027 57 Thereafter 478 Total undiscounted lease payments 11,159 Present value adjustment (691) Net operating lease liabilities $ 10,468

Share-Based Compensation (Table

Share-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2023
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, 2023: Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 196,162 $ 26.46 Options granted — $ — Options exercised — $ — Options outstanding, end of period 196,162 $ 26.46 Options exercisable, end of period 196,162 $ 26.46
Restricted stock activity	The following table provides information regarding RSU activity for the three months ended March 31, 2023: RSUs Wtd. Avg. Grant Price RSUs outstanding, beginning of period 227,114 $ 21.18 RSUs granted 189,894 $ 23.65 RSUs forfeited (670) $ 26.66 RSUs vested (115,108) $ 15.70 RSUs outstanding, end of period 301,230 $ 24.82
Performance-Based Stock Units Activity	The following table provides information regarding performance-based stock unit activity for the three months ended March 31, 2023: PSUs Wtd. Avg. Grant Price Performance based stock units outstanding, beginning of period 283,500 $ 23.18 Performance based stock units granted 120,749 $ 31.18 Performance based stock units incremental shares granted 142,021 $ 13.13 Performance based stock units vested (303,410) $ 13.13 Performance based stock units outstanding, end of period 242,860 $ 33.84

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2023
Earnings Per Share [Abstract]
Reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS	The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended March 31, 2023 Three Months Ended March 31, 2022 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 94,492 22,440 $ 4.21 $ (64,255) 16,719 $ (3.84) Dilutive Securities: Performance Based Stock Unit Awards 97 — RSU Awards 91 — Stock Option Awards 6 — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 94,492 22,634 $ 4.17 $ (64,255) 16,719 $ (3.84)

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2023
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	The Company's long-term debt consisted of the following (in thousands): March 31, 2023 December 31, 2022 Credit Facility Borrowings due 2026 (1) $ 559,000 $ 542,000 Second Lien Notes due 2026 150,000 150,000 709,000 692,000 Unamortized discount on Second Lien Notes due 2026 (835) (882) Unamortized debt issuance cost on Second Lien Notes due 2026 (2,450) (2,587) Long-Term Debt, net $ 705,715 $ 688,531 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of March 31, 2023 and December 31, 2022, we had $8.1 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Business Combinations and Asset

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

Price-Risk Management Price-R_3

Price-Risk Management Price-Risk Management (Tables)	3 Months Ended
	Mar. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments [Table Text Block]	The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of March 31, 2023: 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 2023 Contracts 2Q23 494,575 $ 80.75 3Q23 533,980 $ 77.36 4Q23 569,300 $ 78.26 2024 Contracts 1Q24 227,500 $ 80.78 2Q24 254,050 $ 80.24 3Q24 272,700 $ 76.91 4Q24 256,100 $ 75.98 Collar Contracts 2023 Contracts 2Q23 167,949 $ 53.91 $ 64.89 3Q23 72,847 $ 59.27 $ 66.26 4Q23 72,242 $ 58.54 $ 65.13 2024 Contracts 1Q24 137,700 $ 51.61 $ 65.86 2Q24 33,000 $ 45.00 $ 60.72 2025 Contracts 1Q25 45,000 $ 62.00 $ 69.40 3-Way Collar Contracts 2023 Contracts 2Q23 13,260 $ 44.19 $ 55.04 $ 64.53 3Q23 9,570 $ 43.08 $ 53.41 $ 63.33 4Q23 8,970 $ 43.08 $ 53.38 $ 63.35 2024 Contracts 1Q24 8,247 $ 45.00 $ 57.50 $ 67.85 2Q24 7,757 $ 45.00 $ 57.50 $ 67.85 Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Sub Floor Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2023 Contracts 2Q23 3,816,000 $ 4.55 3Q23 4,816,000 $ 4.57 4Q23 3,887,000 $ 4.71 2024 Contracts 1Q24 2,711,000 $ 5.15 2Q24 7,800,000 $ 3.95 3Q24 7,820,000 $ 4.03 4Q24 7,820,000 $ 4.35 2025 Contracts 1Q25 900,000 $ 5.01 2Q25 910,000 $ 4.12 3Q25 920,000 $ 4.27 4Q25 920,000 $ 4.70 Collar Contracts 2023 Contracts 2Q23 12,141,250 $ 3.28 $ 4.05 3Q23 11,896,400 $ 3.43 $ 4.23 4Q23 12,445,000 $ 3.87 $ 4.80 2024 Contracts 1Q24 7,841,000 $ 4.10 $ 6.19 2Q24 2,823,000 $ 4.05 $ 4.91 3Q24 2,958,000 $ 4.00 $ 5.10 4Q24 2,945,000 $ 4.24 $ 5.63 2025 Contracts 1Q25 1,800,000 $ 4.00 $ 5.41 3-Way Collar Contracts 2023 Contracts 2Q23 310,400 $ 2.04 $ 2.54 $ 3.01 3Q23 233,100 $ 2.00 $ 2.50 $ 2.95 4Q23 219,200 $ 2.00 $ 2.50 $ 2.94 2024 Contracts 1Q24 198,000 $ 2.00 $ 2.50 $ 3.37 2Q24 188,000 $ 2.00 $ 2.50 $ 3.37 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2023 Contracts 2Q23 14,560,000 $ (0.24) 3Q23 14,720,000 $ (0.21) 4Q23 13,800,000 $ (0.23) 2024 Contracts 1Q24 9,100,000 $ (0.01) 2Q24 9,100,000 $ (0.32) 3Q24 9,200,000 $ (0.28) 4Q24 9,200,000 $ (0.31) Houston Ship Channel Fixed Price Contracts 2023 Contracts 2Q23 60,000 $ 2.64 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2023 Contracts 2Q23 341,250 $ 33.12 3Q23 345,000 $ 32.87 4Q23 345,000 $ 32.87 2024 Contracts 1Q24 127,400 $ 29.39 2Q24 127,400 $ 29.39 3Q24 128,800 $ 29.39 4Q24 128,800 $ 29.39

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2023
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, 2023 and December 31, 2022, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements. Fair Value Measurements at (in thousands) Total Quoted Prices in Significant Other Significant March 31, 2023 Assets Natural Gas Derivatives $ 73,197 $ — $ 73,197 $ — Natural Gas Basis Derivatives 4,300 — 4,300 — Oil Derivatives 19,106 — 19,106 — NGL Derivatives 10,022 — 10,022 — Liabilities Natural Gas Derivatives 1,624 — 1,624 — Natural Gas Basis Derivatives 2,999 — 2,999 — Oil Derivatives 11,177 — 11,177 — NGL Derivatives 44 — 44 — 2022 WTI Contingency Payout 1,090 — 1,090 — 2021 WTI Contingency Payout 1,498 — 1,498 — December 31, 2022 Assets Natural Gas Derivatives $ 25,960 $ — $ 25,960 $ — Natural Gas Basis Derivatives 26,023 — 26,023 — Oil Derivatives 14,604 — 14,604 — NGL Derivatives 10,134 — 10,134 — Liabilities Natural Gas Derivatives 28,579 — 28,579 — Natural Gas Basis Derivatives 409 — 409 — Oil Derivatives 19,442 — 19,442 — NGL Derivatives 104 — 104 — 2022 WTI Contingency Payout 2,135 — 2,135 — 2021 WTI Contingency Payout 1,453 — 1,453 —

Asset Retirement Obligations _3

Asset Retirement Obligations Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Roll-forward of our asset retirement obligations	The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2022 and the three months ended March 31, 2023 (in thousands): Asset Retirement Obligations as of December 31, 2021 $ 6,050 Accretion expense 534 Liabilities incurred for new wells, acquired wells and facilities construction 3,032 Reductions due to sold wells and facilities (57) Reductions due to plugged wells and facilities (22) Revisions in estimates 919 Asset Retirement Obligations as of December 31, 2022 $ 10,456 Accretion expense 224 Liabilities incurred for new wells, acquired wells and facilities construction 59 Reductions due to plugged wells and facilities (3) Revisions in estimates 313 Asset Retirement Obligations as of March 31, 2023 $ 11,049

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe	Mar. 31, 2022 USD ($)	Apr. 28, 2023 MMBTU bbl $ / MMBTU $ / Boe	Dec. 31, 2022 USD ($)
Property and Equipment
Proved oil and gas properties | $	$ 2,614,332			$ 2,506,853
Unproved oil and gas properties | $	18,196			16,272
Furniture, fixtures, and other equipment | $	6,188			6,098
Less - Accumulated depreciation, depletion, and amortization | $	(1,048,062)			(1,004,044)
Net Furniture, Fixtures and other equipment | $	1,590,654			1,525,179
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	139,954	$ 129,656
Accounts Payable and Accrued Liabilities
Trade accounts payable | $	20,254			23,660
Accrued operating expenses | $	13,735			10,572
Accrued compensation costs | $	1,510			4,814
Asset retirement obligation - current portion | $	1,598			1,284
Accrued non-income based taxes | $	5,836			4,849
Accrued corporate and legal fees | $	306			388
WTI contingency payouts - current portion | $	2,023			1,600
Payables for Settled Derivatives | $	984			6,026
Other payables | $	5,353			7,007
Total Accounts payable and accrued liabilities | $	51,599			$ 60,200
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	74,655	39,741
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	52,922	77,372
NGL sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	$ 12,377	$ 12,543
Swap [Member] | Third Quarter 2023 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	533,980
Derivative, Swap Type, Fixed Price | $ / Boe	77.36
Swap [Member] | Third Quarter 2023 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,816,000
Derivative, Swap Type, Fixed Price	4.57
Swap [Member] | Fourth Quarter 2023 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	569,300
Derivative, Swap Type, Fixed Price | $ / Boe	78.26
Swap [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,887,000
Derivative, Swap Type, Fixed Price	4.71
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	272,700
Derivative, Swap Type, Fixed Price | $ / Boe	76.91
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			920
Derivative, Swap Type, Fixed Price | $ / Boe			71.60
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,820,000
Derivative, Swap Type, Fixed Price	4.03
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	900,000
Derivative, Swap Type, Fixed Price	5.01
Collar Contracts [Member] | Third Quarter 2023 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	72,847
Derivative, Average Floor Price	59.27
Derivative, Average Cap Price	66.26
Collar Contracts [Member] | Third Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			46,000
Derivative, Average Floor Price			72
Derivative, Average Cap Price			82.83
Collar Contracts [Member] | Third Quarter 2023 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,896,400
Derivative, Average Floor Price	3.43
Derivative, Average Cap Price	4.23
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	72,242
Derivative, Average Floor Price	58.54
Derivative, Average Cap Price	65.13
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			46,000
Derivative, Average Floor Price			71
Derivative, Average Cap Price			80.65
Collar Contracts [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,445,000
Derivative, Average Floor Price	3.87
Derivative, Average Cap Price	4.80
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,958,000
Derivative, Average Floor Price	4
Derivative, Average Cap Price	5.10
Collar Contracts [Member] | First Quarter 2025 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	45,000
Derivative, Average Floor Price	62
Derivative, Average Cap Price	69.40
Collar Contracts [Member] | First Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			193,500
Derivative, Average Floor Price			64.47
Derivative, Average Cap Price			75.84
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	1,800,000
Derivative, Average Floor Price	4
Derivative, Average Cap Price	5.41
Collar Contracts [Member] | First Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			3,330,000
Derivative, Average Floor Price			4
Derivative, Average Cap Price			5.27

Summary of Significant Accoun_5

Summary of Significant Accounting Policies (Details Textual) $ in Thousands	3 Months Ended
	Mar. 31, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe shares	Mar. 31, 2022 USD ($) shares	Apr. 28, 2023 MMBTU bbl $ / MMBTU $ / Boe	Dec. 31, 2022 USD ($)
Summary of Significant Accounting Policies
Proved oil and gas properties	$ 2,614,332			$ 2,506,853
Unproved oil and gas properties	18,196			16,272
Furniture, fixtures, and other equipment	6,188			6,098
Less - Accumulated depreciation, depletion, and amortization	(1,048,062)			(1,004,044)
Net Furniture, Fixtures and other equipment	$ 1,590,654			1,525,179
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
Accounts receivable, gross	44,300			70,900
Accounts receivable related to joint interest owners	1,200			5,600
Severance tax receivable	5,700			4,300
Other receivables	$ 12,700			8,900
Percentage of working interest in wells	100%
Total amount of supervision fees charged to wells	$ 2,700	$ 1,600
Effective Income Tax Rate Reconciliation, Percent	22%	(4.00%)
Oil and gas sales	$ 139,954	$ 129,656
Trade accounts payable	20,254			23,660
Accrued operating expenses	13,735			10,572
Accrued payroll costs	1,510			4,814
Asset retirement obligation - current portion	1,598			1,284
Accrued non-income based taxes	5,836			4,849
Accrued corporate and legal fees	306			388
WTI contingency payouts - current portion	2,023			1,600
Payables for Settled Derivatives	984			6,026
Other payables	5,353			7,007
Accounts payable and accrued liabilities	$ 51,599			$ 60,200
Purchase of treasury stock (shares) | shares	126,240	96,012
Treasury Shares Pursuant to Purchase Price Adjustment (shares) | shares		41,191
Capitalized Costs Oil and Gas Producing Activities	$ 1,400	$ 1,000
Oil sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales	74,655	39,741
Natural gas sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales	52,922	77,372
NGL sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales	$ 12,377	$ 12,543
Collar Contracts [Member] | Third Quarter 2023 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	72,847
Derivative, Average Floor Price | $ / MMBTU	59.27
Derivative, Average Cap Price | $ / MMBTU	66.26
Collar Contracts [Member] | Third Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU			46,000
Derivative, Average Floor Price | $ / MMBTU			72
Derivative, Average Cap Price | $ / MMBTU			82.83
Collar Contracts [Member] | Third Quarter 2023 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	11,896,400
Derivative, Average Floor Price | $ / MMBTU	3.43
Derivative, Average Cap Price | $ / MMBTU	4.23
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	72,242
Derivative, Average Floor Price | $ / MMBTU	58.54
Derivative, Average Cap Price | $ / MMBTU	65.13
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU			46,000
Derivative, Average Floor Price | $ / MMBTU			71
Derivative, Average Cap Price | $ / MMBTU			80.65
Collar Contracts [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	12,445,000
Derivative, Average Floor Price | $ / MMBTU	3.87
Derivative, Average Cap Price | $ / MMBTU	4.80
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	2,958,000
Derivative, Average Floor Price | $ / MMBTU	4
Derivative, Average Cap Price | $ / MMBTU	5.10
Collar Contracts [Member] | First Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	45,000
Derivative, Average Floor Price | $ / MMBTU	62
Derivative, Average Cap Price | $ / MMBTU	69.40
Collar Contracts [Member] | First Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU			193,500
Derivative, Average Floor Price | $ / MMBTU			64.47
Derivative, Average Cap Price | $ / MMBTU			75.84
Collar Contracts [Member] | First Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	1,800,000
Derivative, Average Floor Price | $ / MMBTU	4
Derivative, Average Cap Price | $ / MMBTU	5.41
Collar Contracts [Member] | First Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU			3,330,000
Derivative, Average Floor Price | $ / MMBTU			4
Derivative, Average Cap Price | $ / MMBTU			5.27
Swap [Member] | Third Quarter 2023 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	533,980
Derivative, Swap Type, Fixed Price | $ / Boe	77.36
Swap [Member] | Third Quarter 2023 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	4,816,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.57
Swap [Member] | Fourth Quarter 2023 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	569,300
Derivative, Swap Type, Fixed Price | $ / Boe	78.26
Swap [Member] | Fourth Quarter 2023 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	3,887,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.71
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	272,700
Derivative, Swap Type, Fixed Price | $ / Boe	76.91
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			920
Derivative, Swap Type, Fixed Price | $ / Boe			71.60
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	7,820,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	4.03
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	900,000
Derivative, Swap Type, Fixed Price | $ / MMBTU	5.01
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, 2023 USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 6,742
Lessee, Operating Lease, Liability, Payments, Due Year Two	2,028
Lessee, Operating Lease, Liability, Payments, Due Year Three	1,027
Lessee, Operating Lease, Liability, Payments, Due Year Four	827
Lessee, Operating Lease, Liability, Payments, Due Year Five	57
Lessee, Operating Lease, Liability, Payments, Due after Year Five	478
Lessee, Operating Lease, Liability, Payments, Due	11,159
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(691)
Operating Lease, Liability	$ 10,468

Share-Based Compensation (Detai

Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands								3 Months Ended
	Mar. 31, 2023	Feb. 23, 2023	Feb. 22, 2023	Jun. 30, 2022	Feb. 23, 2022	Feb. 24, 2021	May 21, 2019	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Share-based Compensation (Details Textual)
Share-based Payment Arrangement, Noncash Expense								$ 1,124	$ 1,047
Share-based compensation (capitalized)								100	100
General and Administrative Expense [Member]
Share-based Compensation (Details Textual)
Share-based Payment Arrangement, Noncash Expense								1,100	$ 1,000
Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 0							0
Stock option award outstanding aggregate intrinsic value	$ 100							100
Remaining contract life of outstanding stock options.	4 years 1 month 6 days
Remaining contract life of exercisable stock option	4 years 1 month 6 days
Stock option award exercisable aggregate intrinsic value								$ 100
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	$ 6,600							$ 6,600
Unrecognized compensation expense weighted-average period								2 years 4 months 24 days
Restricted stock activity
Restricted shares outstanding, beginning of period, shares								227,114
Restricted shares outstanding, beginning of period, weighted average price								$ 21.18
Restricted shares granted, shares								189,894
Restricted shares granted, weighted average price								$ 23.65
Restricted shares forfeited								(670)
Restricted shares forfeited, weighted average price								$ 26.66
Restricted shares vested, shares								(115,108)
Restricted shares vested, weighted average price								$ 15.70
Restricted shares outstanding, end of period, shares	301,230							301,230
Restricted shares outstanding, end of period, weighted average price	$ 24.82							$ 24.82
Performance Shares [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 6,400							$ 6,400
Unrecognized compensation expense weighted-average period				2 years 3 months 18 days
Share-based Compensation, Expected Term		3 years			3 years	2 years	3 years
Restricted stock activity
Restricted shares outstanding, beginning of period, shares								283,500
Restricted shares outstanding, beginning of period, weighted average price								$ 23.18
Restricted shares granted, shares		120,749			122,111	161,389	99,500
Restricted shares granted, weighted average price		$ 31.18			$ 36.47	$ 13.13	$ 18.86
Performance based stock units, incremental shares vested					142,021
Performance based stock units, incremental shares vested, Weighted Average Grant Date Fair Value					$ 13.13
Restricted shares vested, shares			(303,410)		(97,812)			(303,410)
Restricted shares vested, weighted average price								$ 13.13
Restricted shares outstanding, end of period, shares	242,860							242,860
Restricted shares outstanding, end of period, weighted average price	$ 33.84							$ 33.84
Percent of payout for performance based stock units	100%	136.28%			150.93%	157.60%	112.90%	100%
Approved payout for performance based stock units			188%		117%
Minimum [Member] | Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period								1 year
Minimum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Share-based Compensation, Expected Term								1 year
Minimum [Member] | Performance Shares [Member]
Restricted stock activity
Percent of payout for performance based stock units		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)
Share-based Compensation, Expected Term								5 years
Maximum [Member] | Performance Shares [Member]
Restricted stock activity
Percent of payout for performance based stock units		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, 2023	Mar. 31, 2022
Basic EPS:
Net Income (Loss)	$ 94,492	$ (64,255)
Income, share amounts	22,440	16,719
Earnings Per Share, Basic	$ 4.21	$ (3.84)
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ 94,492	$ (64,255)
Weighted Average Shares Outstanding - Diluted	22,634	16,719
Earnings Per Share, Diluted	$ 4.17	$ (3.84)
Share-based Payment Arrangement, Option [Member]
Dilutive Securities:
Dilutive Securities	6	0
Diluted EPS:
Antidilutive shares excluded from EPS, shares	100	200
Restricted Stock Units (RSUs) [Member]
Dilutive Securities:
Dilutive Securities	91	0
Diluted EPS:
Antidilutive shares excluded from EPS, shares	100	100
Performance Shares [Member]
Dilutive Securities:
Dilutive Securities	97	0
Diluted EPS:
Antidilutive shares excluded from EPS, shares	100	100

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands				3 Months Ended
	Mar. 20, 2023 USD ($)	Nov. 29, 2021 USD ($)	Nov. 12, 2021 USD ($)	Mar. 31, 2023 USD ($)	Mar. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)	Jun. 22, 2022	Dec. 15, 2017 USD ($)
Bank Borrowings
Long-term Debt, excluding current maturities				$ 705,715		$ 688,531
Payments of Debt Issuance Costs				0	$ 117
Second Lien [Abstract]
Long-term debt, gross				$ 709,000		692,000
Discount Rate for Estimated Future Net Revenues from Proved Properties				10%
Gross interest expense including amortization of debt issuance costs				$ 16,745	6,557
New Credit Facility [Member]
Bank Borrowings
Debt Issuance Costs, Net				8,100		8,700
Second Lien Notes [Member]
Bank Borrowings
Debt Issuance Costs, Net				2,450		2,587
Long-term Debt, excluding current maturities				150,000		150,000		$ 198,000
Second Lien [Abstract]
Long-term debt, gross			$ 150,000					200,000
Debt Instrument, Unamortized Discount				(835)		(882)		$ (2,000)
Repayments of Long-Term Debt		$ 50,000
Additional interest in the event of default			0.020
Second Lien, Required Security Interest on Proved Reserves			90%
Second Lien, Required Security Interest on Oil and Gas Properties			90%
Discount Rate for Estimated Future Net Revenues for Proved Properties at 9%			9%
Second Lien, Asset Coverage Ratio, Minimum			1.25
Second Lien, Debt to EBITDA Ratio, after March 31, 2022			3.25
Long-term debt, net				146,700
Gross interest expense including amortization of debt issuance costs				4,800	3,400
Second Lien Notes [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate			0.065
Second Lien Notes [Member] | London Interbank Offered Rate LIBOR [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate			0.075
Line of Credit [Member] | New Credit Facility [Member]
Bank Borrowings
Long-term Debt, excluding current maturities				559,000		542,000
Line of Credit Facility, Maximum Borrowing Capacity				2,000,000
Line of Credit Facility, Current Borrowing Capacity				775,000
Line of Credit, Letters of Credit Issuable	$ 25,000
Letters of Credit Outstanding, Amount				$ 0		$ 0
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				8.13%
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				$ 300	300
Payments of Debt Issuance Costs				0	100
Second Lien [Abstract]
Gross interest expense including amortization of debt issuance costs				$ 11,900	$ 3,200
Line of Credit [Member] | New Credit Facility [Member] | Minimum [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Bank Borrowings
Debt instrument escalating basis spread on base rate	0.0175
Debt Instrument Escalating Rates for Eurodollar Rate Loans	0.0275
Line of Credit [Member] | New Credit Facility [Member] | Maximum [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Bank Borrowings
Debt instrument escalating basis spread on base rate	0.0275
Debt Instrument Escalating Rates for Eurodollar Rate Loans	0.0375

Acquisitions and Dispositions_2

Acquisitions and Dispositions Acquisitions and Dispositions (Details) $ in Thousands						3 Months Ended		12 Months Ended
	Oct. 31, 2022 USD ($)	Aug. 15, 2022 USD ($)	Jun. 30, 2022 USD ($) shares	May 10, 2022 USD ($) shares	Nov. 19, 2021 USD ($) shares	Mar. 31, 2023 USD ($)	Mar. 31, 2022 USD ($) shares	Dec. 31, 2022 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock Issued During Period, Shares, Acquisitions | shares							489
Other current assets						$ 2,672		$ 2,671
Right of Use Assets						10,229		12,077
Derivative, Fair Value, Net						90,800		28,200
Non-current Lease Liability						3,303		3,775
Asset Retirement Obligations, Noncurrent						9,451		9,171
WTI Contingency Payout Fair Value					$ 1,900
Proceeds from the sale of property and equipment								4,300
Gain (Loss) on WTI Contingency Payout						1,000	$ (1,200)
Teal Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition of oil and gas properties					37,600
Asset Acquisition, Consideration Transferred					77,400
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable					37,900
WTI Annual Earn Out Payment					$ 1,600
WTI Annual Earn Out, Average Monthly Settlement Price					70
2021 WTI Contingency Payable								1,600
Gain (Loss) on WTI Contingency Payout						100	$ 1,200
Teal Acquisition | Asset Acquisition, Shares Issuable
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock Issued During Period, Shares, Acquisitions | shares					1,351,961
SandPoint Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition of oil and gas properties				$ 27,709
Asset Acquisition, Consideration Transferred				67,476
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable				$ 39,767
Asset Acquisition, Transaction Costs								466
Asset Acquisition, Total Cost of Transaction								67,942
Allocation of Total Cost, Oil and gas properties								84,810
Allocation of Total cost, Total assets								84,810
Accounts Payable and Accrued Liabilities, Current								199
Derivative, Fair Value, Net								16,511
Asset Retirement Obligations, Noncurrent								158
Allocation of Total Cost, Total Liabilities								16,868
SandPoint Acquisition | Asset Acquisition, Shares Issuable
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock Issued During Period, Shares, Acquisitions | shares				1,300,000
Sundance Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisition of oil and gas properties			$ 220,866
Asset Acquisition, Consideration Transferred			344,939
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable			117,651
Asset Acquisition, Transaction Costs			6,766					6,800
Asset Acquisition, Total Cost of Transaction			351,705
Other current assets			4,202
Allocation of Total Cost, Oil and gas properties			397,401
Right of Use Assets			890
Allocation of Total cost, Total assets			402,493
Accounts Payable and Accrued Liabilities, Current			13,687
Derivative, Fair Value, Net			33,767
Non-current Lease Liability			890
Asset Retirement Obligations, Noncurrent			2,444
Allocation of Total Cost, Total Liabilities			50,788
2022 WTI Contingency Payout Fair Value			7,422
WTI Annual Earn Out Payment			7,500
Account Receivable for purchase price adjustments			$ (1,000)
WTI Annual Earn Out, Average Monthly Settlement 2022			95
2023 WTI Annual Earn Out Payment								$ 7,500
WTI Annual Earn Out, Average Monthly Settlement Price 2023			85
2024 WTI Annual Earn Out Payment			$ 7,500
Gain (Loss) on WTI Contingency Payout						$ 1,000
Sundance Acquisition | Asset Acquisition, Shares Issuable
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock Issued During Period, Shares, Acquisitions | shares			4,148,472
Arkoma Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Acquisition, Consideration Transferred		$ 31,200
Dewitt and Gonzalez Counties Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Acquisition, Consideration Transferred	$ 80,100

Price-Risk Management Price-R_4

Price-Risk Management Price-Risk Management (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2023 USD ($) MMBTU bbl $ / MMBTU $ / Boe	Mar. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Price Risk Derivatives, Net | $	$ 91,200	$ (139,000)
Gain (Loss) on WTI Contingency Payout | $	1,000	(1,200)
Cash settlements on derivatives | $	18,699	$ (24,554)
Receivables for Settled Derivatives | $	11,800		$ 6,900
Payables for Settled Derivatives | $	984		6,026
Derivative, Fair Value, Net | $	90,800		28,200
Other Current Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	80,000		52,500
Other Noncurrent Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	26,600		24,200
Other Current Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	13,500		40,800
Other Noncurrent Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	$ 2,400		$ 7,700
Swap [Member] | Oil Derivative Swaps | Second Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	494,575
Derivative, Swap Type, Fixed Price | $ / Boe	80.75
Swap [Member] | Oil Derivative Swaps | Third Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	533,980
Derivative, Swap Type, Fixed Price | $ / Boe	77.36
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	569,300
Derivative, Swap Type, Fixed Price | $ / Boe	78.26
Swap [Member] | Oil Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	227,500
Derivative, Swap Type, Fixed Price | $ / Boe	80.78
Swap [Member] | Oil Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	254,050
Derivative, Swap Type, Fixed Price | $ / Boe	80.24
Swap [Member] | Oil Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	272,700
Derivative, Swap Type, Fixed Price | $ / Boe	76.91
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	256,100
Derivative, Swap Type, Fixed Price | $ / Boe	75.98
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,816,000
Derivative, Swap Type, Fixed Price	4.55
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,816,000
Derivative, Swap Type, Fixed Price	4.57
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,887,000
Derivative, Swap Type, Fixed Price	4.71
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,711,000
Derivative, Swap Type, Fixed Price	5.15
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,800,000
Derivative, Swap Type, Fixed Price	3.95
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,820,000
Derivative, Swap Type, Fixed Price	4.03
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,820,000
Derivative, Swap Type, Fixed Price	4.35
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	900,000
Derivative, Swap Type, Fixed Price	5.01
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	910,000
Derivative, Swap Type, Fixed Price	4.12
Swap [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, Swap Type, Fixed Price	4.27
Swap [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, Swap Type, Fixed Price	4.70
Swap [Member] | NGL Derivative | Second Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	341,250
Derivative, Swap Type, Fixed Price	33.12
Swap [Member] | NGL Derivative | Third Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	345,000
Derivative, Swap Type, Fixed Price	32.87
Swap [Member] | NGL Derivative | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	345,000
Derivative, Swap Type, Fixed Price	32.87
Swap [Member] | NGL Derivative | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	127,400
Derivative, Swap Type, Fixed Price	29.39
Swap [Member] | NGL Derivative | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	127,400
Derivative, Swap Type, Fixed Price	29.39
Swap [Member] | NGL Derivative | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	128,800
Derivative, Swap Type, Fixed Price	29.39
Swap [Member] | NGL Derivative | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	128,800
Derivative, Swap Type, Fixed Price	29.39
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	167,949
Derivative, Average Floor Price	53.91
Derivative, Average Cap Price	64.89
Collar Contracts [Member] | Oil Derivative Swaps | Third Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	72,847
Derivative, Average Floor Price	59.27
Derivative, Average Cap Price	66.26
Collar Contracts [Member] | Oil Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	72,242
Derivative, Average Floor Price	58.54
Derivative, Average Cap Price	65.13
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	137,700
Derivative, Average Floor Price	51.61
Derivative, Average Cap Price	65.86
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	33,000
Derivative, Average Floor Price	45
Derivative, Average Cap Price	60.72
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	45,000
Derivative, Average Floor Price	62
Derivative, Average Cap Price	69.40
Collar Contracts [Member] | Natural Gas Derivative Swaps | Second Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,141,250
Derivative, Average Floor Price	3.28
Derivative, Average Cap Price	4.05
Collar Contracts [Member] | Natural Gas Derivative Swaps | Third Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,896,400
Derivative, Average Floor Price	3.43
Derivative, Average Cap Price	4.23
Collar Contracts [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,445,000
Derivative, Average Floor Price	3.87
Derivative, Average Cap Price	4.80
Collar Contracts [Member] | Natural Gas Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,841,000
Derivative, Average Floor Price	4.10
Derivative, Average Cap Price	6.19
Collar Contracts [Member] | Natural Gas Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,823,000
Derivative, Average Floor Price	4.05
Derivative, Average Cap Price	4.91
Collar Contracts [Member] | Natural Gas Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,958,000
Derivative, Average Floor Price	4
Derivative, Average Cap Price	5.10
Collar Contracts [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,945,000
Derivative, Average Floor Price	4.24
Derivative, Average Cap Price	5.63
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	1,800,000
Derivative, Average Floor Price	4
Derivative, Average Cap Price	5.41
3-Way Collar | Oil Derivative Swaps | Second Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	13,260
Derivative, Average Sub Floor Price	44.19
Derivative, Average Floor Price	55.04
Derivative, Average Cap Price	64.53
3-Way Collar | Oil Derivative Swaps | Third Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,570
Derivative, Average Sub Floor Price	43.08
Derivative, Average Floor Price	53.41
Derivative, Average Cap Price	63.33
3-Way Collar | Oil Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,970
Derivative, Average Sub Floor Price	43.08
Derivative, Average Floor Price	53.38
Derivative, Average Cap Price	63.35
3-Way Collar | Oil Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,247
Derivative, Average Sub Floor Price	45
Derivative, Average Floor Price	57.50
Derivative, Average Cap Price	67.85
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 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	310,400
Derivative, Average Sub Floor Price	2.04
Derivative, Average Floor Price	2.54
Derivative, Average Cap Price	3.01
3-Way Collar | Natural Gas Derivative Swaps | Third Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	233,100
Derivative, Average Sub Floor Price	2
Derivative, Average Floor Price	2.50
Derivative, Average Cap Price	2.95
3-Way Collar | Natural Gas Derivative Swaps | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	219,200
Derivative, Average Sub Floor Price	2
Derivative, Average Floor Price	2.50
Derivative, Average Cap Price	2.94
3-Way Collar | Natural Gas Derivative Swaps | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	198,000
Derivative, Average Sub Floor Price	2
Derivative, Average Floor Price	2.50
Derivative, Average Cap Price	3.37
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] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	14,560,000
Derivative, Swap Type, Fixed Price	(0.24)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	14,720,000
Derivative, Swap Type, Fixed Price	(0.21)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	13,800,000
Derivative, Swap Type, Fixed Price	(0.23)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,100,000
Derivative, Swap Type, Fixed Price	(0.01)
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	9,100,000
Derivative, Swap Type, Fixed Price	(0.32)
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	9,200,000
Derivative, Swap Type, Fixed Price	(0.28)
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	9,200,000
Derivative, Swap Type, Fixed Price	(0.31)
Basis Swap [Member] | Houston Ship Channel Fixed Price Derivative | Second Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	60,000
Derivative, Swap Type, Fixed Price	2.64

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value, Recurring [Member] - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 73,197	$ 25,960
Derivative Liability	1,624	28,579
Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	4,300	26,023
Derivative Liability	2,999	409
Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	19,106	14,604
Derivative Liability	11,177	19,442
2022 WTI Contingency Payout Fair Value	1,090	2,135
2021 WTI Contingency Payout	1,498	1,453
NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	10,022	10,134
Derivative Liability	44	104
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
2022 WTI Contingency Payout Fair Value	0	0
2021 WTI Contingency Payout	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	73,197	25,960
Derivative Liability	1,624	28,579
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	4,300	26,023
Derivative Liability	2,999	409
Fair Value, Inputs, Level 2 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	19,106	14,604
Derivative Liability	11,177	19,442
2022 WTI Contingency Payout Fair Value	1,090	2,135
2021 WTI Contingency Payout	1,498	1,453
Fair Value, Inputs, Level 2 [Member] | NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	10,022	10,134
Derivative Liability	44	104
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
2022 WTI Contingency Payout Fair Value	0	0
2021 WTI Contingency Payout	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, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 11,049		$ 10,456	$ 6,050
Accretion expense	224	$ 99	534
Liabilities incurred for new wells and facilities construction	59		3,032
Reduction due to sold wells and facilities			(57)
Reductions due to plugged wells and facilities	(3)		(22)
Revisions in estimates	313		919
Asset retirement obligation - current portion	$ 1,598		$ 1,284