SANDRIDGE ENERGY INC, 10-K filed on 3/5/2026
Annual Report
v3.25.4
Cover - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Feb. 26, 2026
Jun. 30, 2025
Document Information [Line Items]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2025    
Current Fiscal Year End Date --12-31    
Document Transition Report false    
Entity File Number 001-33784    
Entity Registrant Name SANDRIDGE ENERGY, INC.    
Entity Incorporation, State or Country Code DE    
Entity Tax Identification Number 20-8084793    
Entity Address, Address Line One 1 E. Sheridan Ave    
Entity Address, Address Line Two Suite 500    
Entity Address, City or Town Oklahoma City    
Entity Address, State or Province OK    
Entity Address, Postal Zip Code 73104    
City Area Code 405    
Local Phone Number 429-5500    
Entity Well-known Seasoned Issuer No    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
ICFR Auditor Attestation Flag true    
Document Financial Statement Error Correction false    
Entity Shell Company false    
Entity Public Float     $ 340.1
Entity Common Stock, Shares Outstanding   36,825,163  
Documents Incorporated by Reference
Portions of the Company’s definitive proxy statement for the 2026 Annual Meeting of Stockholders, which will be filed with the SEC within 120 days of December 31, 2025, are incorporated by reference in Part III.
    
Document Fiscal Year Focus 2025    
Document Fiscal Period Focus FY    
Amendment Flag false    
Entity Central Index Key 0001349436    
Common Stock      
Document Information [Line Items]      
Title of 12(b) Security Common Stock, $0.001 par value    
Trading Symbol SD    
Security Exchange Name NYSE    
Preferred Stock      
Document Information [Line Items]      
Title of 12(b) Security Preferred Stock Purchase Rights    
No Trading Symbol Flag true    
Security Exchange Name NYSE    
v3.25.4
Audit Information
 12 Months Ended
Dec. 31, 2025
Audit Information [Abstract]  
Auditor Firm ID 248
Auditor Name GRANT THORNTON LLP
Auditor Location Oklahoma City, Oklahoma
v3.25.4
Consolidated Balance Sheets - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Current assets    
Cash and cash equivalents $ 110,998 $ 98,128
Restricted cash 1,347 1,383
Accounts receivable, net 26,186 23,878
Derivative contracts 2,773 114
Prepaid expenses 748 3,370
Other current assets 5,806 780
Total current assets 147,858 127,653
Oil and natural gas properties, using full cost method of accounting    
Proved 1,759,943 1,689,807
Unproved 27,520 23,504
Less: accumulated depreciation, depletion and impairment (1,446,824) (1,415,110)
Net oil and natural gas properties capitalized costs 340,639 298,201
Other property, plant and equipment, net 75,649 80,689
Derivative contracts 0 86
Other assets 1,539 2,081
Deferred tax assets, net of valuation allowance 78,336 72,801
Total assets 644,021 581,511
Current liabilities    
Accounts payable and accrued expenses 59,037 50,625
Asset retirement obligations 8,098 9,131
Other current liabilities 905 839
Total current liabilities 68,040 60,595
Asset retirement obligations 64,293 59,449
Other long-term obligations 817 936
Total liabilities 133,150 120,980
Commitments and contingencies
Stockholders’ equity    
Common stock, $0.001 par value; 250,000 shares authorized; 36,825 issued and outstanding at December 31, 2025 and 37,203 issued and outstanding at December 31, 2024 37 37
Additional paid-in capital 980,592 1,000,455
Accumulated deficit (469,758) (539,961)
Total stockholders’ equity 510,871 460,531
Total liabilities and stockholders’ equity $ 644,021 $ 581,511
v3.25.4
Consolidated Balance Sheets (Parenthetical) - $ / shares
Dec. 31, 2025
Dec. 31, 2024
Statement of Financial Position [Abstract]    
Common stock, par value (in dollars per share) $ 0.001 $ 0.001
Common stock, authorized (in shares) 250,000,000 250,000,000
Common stock, issued (in shares) 36,825,000 37,203,000
Common stock, outstanding (in shares) 36,825,000 37,203,000
v3.25.4
Consolidated Statements of Operations - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Revenues      
Total revenues $ 156,357 $ 125,290 $ 148,641
Expenses      
Lease operating expenses 36,191 40,012 41,862
Production, ad valorem, and other taxes 9,846 6,780 10,870
Depreciation and depletion—oil and natural gas 36,439 25,976 15,657
Depreciation and amortization—other 6,433 6,503 6,518
General and administrative 13,201 11,695 10,735
Restructuring expenses 1,060 474 406
Employee termination benefits 0 0 19
(Gain) loss on derivative contracts (7,763) (748) (1,447)
Other operating (income) expense 0 1,372 (157)
Total expenses 95,407 92,064 84,463
Income (loss) from operations 60,950 33,226 64,178
Other income (expense)      
Interest income (expense), net 3,687 7,744 10,552
Other income (expense), net 31 (216) 87
Total other income (expense) 3,718 7,528 10,639
Income (loss) before income taxes 64,668 40,754 74,817
Income tax (benefit) (5,535) (22,232) 13,960
Net income (loss) $ 70,203 $ 62,986 $ 60,857
Net income (loss) per share      
Basic (in dollars per share) $ 1.91 $ 1.70 $ 1.65
Diluted (in dollars per share) $ 1.90 $ 1.69 $ 1.64
Weighted average number of common shares outstanding      
Basic (in shares) 36,773 37,106 36,939
Diluted (in shares) 36,908 37,188 37,134
v3.25.4
Consolidated Statements of Changes in Stockholders Equity - USD ($)
$ in Thousands
Total
Common Stock
Additional Paid-In Capital
Accumulated Deficit
Beginning Balance (in shares) at Dec. 31, 2022   36,868,000    
Beginning Balance at Dec. 31, 2022 $ 487,922 $ 37 $ 1,151,689 $ (663,804)
Increase (Decrease) in Stockholders' Equity        
Issuance of stock awards, net of cancellations (in shares)   223,000    
Stock-based compensation 2,039   2,039  
Tax withholdings paid in exchange for shares withheld on employee vested stock awards (929)   (929)  
Dividends paid to stockholders (81,778)   (81,778)  
Net income 60,857     60,857
Ending Balance (in shares) at Dec. 31, 2023   37,091,000    
Ending Balance at Dec. 31, 2023 468,111 $ 37 1,071,021 (602,947)
Increase (Decrease) in Stockholders' Equity        
Issuance of stock awards, net of cancellations (in shares)   133,000    
Stock-based compensation 2,354   2,354  
Tax withholdings paid in exchange for shares withheld on employee vested stock awards (393)   (393)  
Dividends paid to stockholders $ (72,294)   (72,294)  
Repurchases of common stock (in shares) (21,308) (21,000)    
Repurchases of common stock $ (233)   (233)  
Net income $ 62,986     62,986
Ending Balance (in shares) at Dec. 31, 2024 37,203,000 37,203,000    
Ending Balance at Dec. 31, 2024 $ 460,531 $ 37 1,000,455 (539,961)
Increase (Decrease) in Stockholders' Equity        
Issuance of stock awards, net of cancellations (in shares)   125,000    
Stock-based compensation 2,744   2,744  
Tax withholdings paid in exchange for shares withheld on employee vested stock awards (290)   (290)  
Dividends paid to stockholders $ (15,862)   (15,862)  
Dividend reinvestments (in shares)   92,733    
Repurchases of common stock (in shares) (595,635) (596,000)    
Repurchases of common stock $ (6,400)      
Repurchases of common stock (6,455)   (6,455)  
Net income $ 70,203     70,203
Ending Balance (in shares) at Dec. 31, 2025 36,825,000 36,825,000    
Ending Balance at Dec. 31, 2025 $ 510,871 $ 37 $ 980,592 $ (469,758)
v3.25.4
Consolidated Statements of Cash Flows - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
CASH FLOWS FROM OPERATING ACTIVITIES      
Net income $ 70,203 $ 62,986 $ 60,857
Adjustments to reconcile net income to net cash provided by operating activities      
Depreciation, depletion and amortization 42,872 32,479 22,176
Deferred income taxes (5,535) (22,232) 13,960
(Gain) loss on derivative contracts (7,763) (748) (1,447)
Settlement gains (losses) on derivative contracts 5,189 548 5,876
Stock-based compensation 2,744 2,354 1,945
Other 412 1,517 159
Changes in operating assets and liabilities increasing (decreasing) cash      
Receivables (3,462) (842) 12,130
Prepaid expenses 2,622 (2,940) 93
Other current assets (5,029) 375 2,203
Other assets and liabilities, net 304 (1,501) (56)
Accounts payable and accrued expenses (1,419) 2,812 (1,409)
Asset retirement obligations (998) (875) (909)
Net cash provided by operating activities 100,140 73,933 115,578
CASH FLOWS FROM INVESTING ACTIVITIES      
Capital expenditures for property, plant and equipment (58,611) (26,404) (26,375)
Acquisitions of assets (8,514) (129,664) (11,232)
Purchase of other property and equipment (562) (1) (29)
Sales tax refund on capitalized predecessor completion costs 2,800 0 0
Proceeds from sale of assets 876 1,373 1,472
Net used in investing activities (64,011) (154,696) (36,164)
CASH FLOWS FROM FINANCING ACTIVITIES      
Dividends paid to stockholders (15,864) (72,336) (81,515)
Reduction of financing lease liability (738) (708) (588)
Proceeds from exercise of stock options 0 0 94
Tax withholdings paid in exchange for shares withheld on employee vested stock awards (290) (393) (929)
Common stock repurchases (6,403) (233) 0
Net cash used in financing activities (23,295) (73,670) (82,938)
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS and RESTRICTED CASH 12,834 (154,433) (3,524)
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year 99,511 253,944 257,468
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of year $ 112,345 $ 99,511 $ 253,944
v3.25.4
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Summary of Significant Accounting Policies Summary of Significant Accounting Policies
Nature of Business. SandRidge Energy, Inc. is an oil and natural gas acquisition, development and production company headquartered in Oklahoma City, Oklahoma with a principal focus on developing and producing hydrocarbon resources in the United States.
Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries, including its proportionate share of the Royalty Trusts. All intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and NGL reserves; impairment tests of long-lived assets; the carrying value of unproved oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; determinations of significant additions or alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to acquired or divested properties, as necessary; valuation allowances for deferred tax assets; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly from those estimates.

Going Concern Consideration. The accompanying consolidated financial statements are prepared in accordance with generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period. Additionally, the Company considers demand deposits or accounts that have the general characteristics of demand deposits where we may deposit additional funds at any time and also effectively withdraw funds at any time without prior notice or penalty to be cash equivalents. As of December 31, 2025, 2024, and 2023, the Company had $111.0 million, $98.1 million, and $252.4 million in cash and cash equivalents, respectively.

Restricted Cash. The Company maintains funds related to collateralized letters of credit and secured credit cards. As of December 31, 2025, 2024, and 2023, the Company had $1.3 million, $1.4 million, and $1.5 million in restricted cash, respectively.

Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the drilling, completion, and production of oil and natural gas, which have a contractual maturity of one year or less. An allowance for expected credit losses has been established based on management’s review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 5 for further information on the Company’s accounts receivable and allowance for expected credit losses.

Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, restricted cash, prepaid expenses, receivables, and payables and accrued expenses. The carrying values of cash, restricted cash, trade receivables, trade payables and accrued expenses are considered to reflect fair values due to the short-term maturity of these instruments. See Note 4 for further discussion of the Company’s fair value measurements.
Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances.

Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows, third-party offers or prices of comparable assets with consideration of current market conditions to fair value its non-financial assets and liabilities when necessary.

Derivative Financial Instruments. The Company enters into oil and natural gas derivative contracts to manage risks related to fluctuations in prices of its expected oil and natural gas production. The Company considers current and anticipated market conditions, planned capital expenditures, and any debt service requirements when determining whether to enter into oil and gas derivative contracts. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 6 for further discussion of the Company’s derivatives.

Other Assets. Other assets consist of capitalized operating leases and production equipment inventories not placed in service. See Note 7 for discussion of the Company’s leases. Production equipment inventories are stated at the lower of cost or net realizable value as of December 31, 2025, and 2024. The Company’s production equipment inventory primarily comprises oil and natural gas drilling or repair items such as tubing, casing and pumping units. Inventory expected to be placed in service within one year is reflected in other current assets on the accompanying consolidated balance sheets, while inventory expected to be place in service beyond one year is reflected in other assets on the accompanying consolidated balance sheets. For the year ended December 31, 2025, the Company recorded no impairment in other operating (income) expense on the accompanying consolidated statements of operations to reflect production equipment inventory at the lower of cost or net realizable value. For the year ended December 31, 2024, the Company recorded a $1.3 impairment in other operating (income) expense on the accompanying consolidated statements of operations to reflect production equipment inventory at the lower of cost or net realizable value. There were no inventory impairments recorded for the year ended December 31, 2023.

Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, development, and exploration activities and capitalized interest. The Company capitalized gross internal costs of $0.7 million, $0.2 million and $0.2 million during the years ended December 31, 2025, 2024 and 2023, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
Costs associated with unproved properties are excluded from the amortizable cost base until it has been determined that proved reserves exist or a lease is impaired. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and amortized. The costs associated with unproved properties are primarily the costs to acquire unproved acreage. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and whether the proved reserves can be developed economically. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes and electrical infrastructure costs may not exceed the ceiling limitation. A ceiling limitation calculation is performed at the end of each quarter. If the ceiling limitation is exceeded, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.

The ceiling limitation calculation is prepared using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If applicable, these prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation.

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center, unless it results in a greater than 10% change to the depletion rate.

Property, Plant and Equipment, Net. Other capitalized costs, including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or fair value established on the Emergence Date less applicable depreciation. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 7 to 39 years for buildings and 1 to 27 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations.

Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that estimated future net operating cash flows directly related to the asset or asset group including disposal value is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value.

Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. The Company did not capitalize any interest on unproved properties during the years ended December 31, 2025 or 2024.

Debt Issuance Costs. The Company includes unamortized debt issuance costs, if any, in other assets in the consolidated balance sheets. Other debt issuance costs related to long-term debt, if any, are presented in the balance sheets as a direct deduction from the associated debt liability, if material. Debt issuance costs are amortized to interest expense over the term of the related debt. When debt is retired, any unamortized costs, if material are written off and included in gain or loss on extinguishment of debt.
Asset Retirement Obligations. The Company owns oil and natural gas assets that require expenditures to plug, abandon and remediate associated property at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded at the estimated present value at the time the wells are drilled or acquired, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the asset is sold and the liability is removed. Both the accretion and the depreciation are included in the consolidated statements of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 10 for further discussion of the Company’s asset retirement obligations.

Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable. Additionally, the Company deducts transportation costs from oil, natural gas and NGL revenues. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production, ad valorem and other taxes in the consolidated statements of operations. See Note 14 for further information on the Company's accounting policies related to revenues.

The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has not recorded a liability for natural gas imbalance positions as of December 31, 2025 or 2024. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.

Allocation of Share-Based Compensation. Equity compensation provided to employees directly involved in exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses, production expenses, and other operating expense in the accompanying consolidated statements of operations.

Restructuring expenses. Restructuring expenses represent fees and costs associated with our outsourcing and relocation of certain corporate specific functions that are of a non-recurring nature, expenses related to our predecessor company's 2016 bankruptcy, and our exit from North Park Basin in Colorado.

Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.

The Company has elected an accounting policy in which interest and penalties on income taxes resulting from the underpayment or late payment of income taxes due to a taxing authority or relating to income tax contingencies are presented as a component of the income tax provision, rather than as interest expense.

Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and units, performance share units, warrants, and stock options using the treasury method.

Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the warrants were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 17 for the Company’s earnings per share calculation.
Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Environmental liabilities related to future costs are recorded on an undiscounted basis when assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 11 for discussion of the Company’s commitments and contingencies.

Concentration of Risk. We regularly maintain cash in excess of federally insured limits at financial institutions. Additionally, all of the Company’s commodity derivative transactions have been carried out in the over-the-counter market, which involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparty for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors the credit ratings of its commodity derivative counterparties on an ongoing basis and considers their credit default risk ratings in determining the fair value of its commodity derivative contracts. Historically, the Company’s commodity derivative contracts have been with multiple counterparties to minimize exposure to any individual counterparty.

The Company enters into master netting agreements with all of its commodity derivative counterparties, which allows the Company to net its commodity derivative assets and liabilities for like commodities and derivative instruments with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under commodity derivative transactions due to credit risk was limited to the net amounts due from the counterparties under the commodity derivative contracts.

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners are primarily independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.

Purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, large oil and natural gas companies and gas pipeline companies. The number of available purchasers and markets in the areas where we sell our production reduces the risk that the loss of a single downstream customer would materially affect our sales. We do not have any material commitments to deliver fixed and determinable quantities of oil and natural gas in the future under existing sales contracts or sales agreements.

The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):
Sales% of Revenue
As of December 31, 2025
Targa Pipeline Mid-Continent West OK LLC$50,896 32.6 %
Plains Marketing, L.P.$33,551 21.5 %
Valero Marketing and Supply Co$21,600 13.8 %
As of December 31, 2024
Plains Marketing, L.P.$50,465 40.3 %
Targa Pipeline Mid-Continent West OK LLC$46,248 36.9 %
As of December 31, 2023
Plains Marketing, L.P.$71,832 48.3 %
Targa Pipeline Mid-Continent West OK LLC$69,743 46.9 %
Out-of-Period Correction. The Company’s December 31, 2025 accounts payable and other accrued expenses balance reflects $5.1 million of non-recurring, non-cash adjustments of operating accruals dating as far back as the Company’s emergence from bankruptcy, of which $2.1 million and $3.0 million were recorded in the second and fourth quarter of 2025, respectively. The adjustments reduced our lease operating expenses for the year ended December 31, 2025 and are not material to the current period or prior periods.

Recently Adopted Accounting Pronouncements. The FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which require greater disaggregation of income tax disclosures. The amendments in this update improve the transparency of income tax disclosures by requiring (1) consistent categories and greater disaggregation of information in the rate reconciliation and (2) income taxes paid disaggregated by jurisdiction. This update improves the effectiveness and comparability of disclosures by requiring disaggregation by jurisdiction of disclosures of pretax income (or loss) and income tax expense (or benefit). This ASU was applied on a retrospective basis. The guidance in this update is effective for fiscal years beginning after December 15, 2024. The adoption of this ASU did not have an impact on our consolidated financial statements. See Note 12 for the Company's income tax disclosures.

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued Accounting Standards Update 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) (“ASU 2024-03”). The objective of ASU 2024-03 is to improve disclosures about a public entity's expenses, primarily through additional disaggregation of income statement expenses. The new standard is effective for annual periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted and may be applied either on a prospective or retrospective basis. The Company is currently evaluating the impact ASU 2024-03 will have on its consolidated financial statement disclosures and does not expect an impact to our consolidated financial statements.
v3.25.4
Supplemental Cash Flow Information
 12 Months Ended
Dec. 31, 2025
Supplemental Cash Flow Information [Abstract]  
Supplemental Cash Flow Information Supplemental Cash Flow Information
Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands):
 Year Ended December 31,
 202520242023
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized$(295)$(131)$(104)
Supplemental Disclosure of Noncash Investing and Financing Activities
Capital expenditures for property, plant and equipment in accounts payables and accrued expenses$11,554 $1,182 $919 
Non-cash acquisition purchase price adjustments$241 $8,819 $(651)
Right-of-use assets obtained in exchange for financing lease obligations$821 $790 $760 
Inventory material transfers to oil and natural gas properties$3 $141 $1,289 
Asset retirement obligation capitalized$57 $353 $113 
Asset retirement obligation removed due to divestiture$(357)$— $(1,413)
Asset retirement obligation revisions$29 $31 $(939)
Change in accrued excise tax on repurchases of common stock$(52)$— $— 
Change in dividends payable$2 $42 $(263)

Cash paid for income taxes for the years ended December 31, 2025, 2024 and 2023 were de minimis.
v3.25.4
Acquisitions of Assets and Oil and Gas Properties
 12 Months Ended
Dec. 31, 2025
Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]  
Acquisitions of Assets and Oil and Gas Properties Acquisitions of Assets and Oil and Gas Properties
2024 Acquisitions

On August 30, 2024, the Company closed the acquisition of oil and natural gas properties in the Cherokee Play of the Western Anadarko Basin, pursuant to the Purchase and Sale Agreement signed on July 29, 2024, as amended on August 30, 2024 (the “Cherokee Play Acquisition”). The Company funded the acquisition with cash on hand. The Cherokee Play Acquisition has been accounted for as an asset acquisition in accordance with ASC 805. The fair value of the consideration paid by the Company and allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on the Company’s books as of the date of the closing. Determining the fair value of the assets acquired and liabilities assumed requires judgment and certain assumptions to be made, the most significant of these being related to the valuation of oil and natural gas properties. The inputs and assumptions related to the oil and natural gas properties are categorized as Level 3 in the fair value hierarchy.

The following table represents the allocation of the total cost of the Cherokee Play Acquisition to the assets acquired and liabilities assumed after customary post-closing adjustments:

(in thousands)
Total Consideration
Cash paid$121,908 
Allocation of Total Consideration
Assets
Oil and natural gas properties$129,825 
Total Assets$129,825 
Liabilities(1)
Accounts payable and accrued expenses$7,917 
Total liabilities assumed7,917 
Net Assets Acquired and Liabilities Assumed$121,908 
____________________

(1)    Asset retirement obligations assumed were de minimis.

On December 13, 2024, the Company closed an acquisition that increased its ownership interest in proved and unproved oil and gas properties within the Cherokee Play for $5.2 million, before customary post-closing adjustments. The Company used its cash on hand to fund the acquisition.

On June 13, 2024, the Company closed an acquisition that increased its ownership interest in twenty-nine producing wells and five saltwater disposal wells for $2.1 million, before customary post-closing adjustments. The Company used its cash on hand to fund the acquisition.

2023 Acquisitions

On July 11, 2023, the Company closed an acquisition that increased its ownership interest in twenty-six producing wells operated by the Company within the Northwest Stack play for $10.6 million, after customary post-closing adjustments, with an effective date of April 1, 2023. The Company used its cash on hand to fund the acquisition.
v3.25.4
Fair Value Measurements
 12 Months Ended
Dec. 31, 2025
Fair Value Disclosures [Abstract]  
Fair Value Measurements Fair Value Measurements
The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, restricted cash, accounts receivable, prepaid expenses, certain other current assets, accounts payable and accrued expenses and other current liabilities and other long-term obligations included in the consolidated balance sheets approximated fair value at December 31, 2025 and December 31, 2024.

Level 1  Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2  Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3  
Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company's financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company had assets classified in Level 2 and 3 of the hierarchy as of December 31, 2025 and 2024.

Level 2 Fair Value Measurements

Commodity Derivative Contracts. As applicable, the fair values of the Company’s oil, natural gas and NGL fixed price swaps are based upon inputs that are either readily available in the public market, such as oil, natural gas and NGL futures prices, volatility factors and discount rates, or can be corroborated from active markets. As applicable, if the Company has a commodity derivative contract in place, the fair value is determined through the use of a discounted cash flow model or option pricing model using the applicable inputs discussed above. The Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit default risk rating, as applicable, in determining the fair value of these derivative contracts. Credit default risk ratings are based on current published credit default swap rates.

Level 3 Fair Value Measurements

Acquisitions. The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its oil and gas properties acquired. The Company recognized the assets acquired in our acquisitions at cost at a relative fair value basis (See “Note 3 — Acquisitions” for additional information). 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 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 assumptions independently prepared by Cawley, Gillespie & Associates for the estimates of production from the oil and natural gas properties, future operating expenses, development costs and income taxes of the acquired properties and risk adjusted discount rates.
Fair Value - Recurring Measurement Basis

As of December 31, 2025, the following table summarizes the Company’s assets measured at fair value on a recurring basis by the fair value hierarchy (in thousands):

Fair Value MeasurementsNetting(1)Assets at Fair Value
Level 1Level 2Level 3
Assets
Commodity derivative contracts$— $3,130 $— $357 $2,773 
Total$— $3,130 $— $357 $2,773 
____________________

(1)Represents the impact of netting assets and liabilities with counterparties where the right of offset exists.

As of December 31, 2024, the following table summarizes the Company’s assets measured at fair value on a recurring basis by the fair value hierarchy (in thousands):
Fair Value MeasurementsNetting(1)Assets at Fair Value
Level 1Level 2Level 3
Assets
Commodity derivative contracts$— $830 $— $630 $200 
$— $830 $— $630 $200 
____________________

(1)Represents the impact of netting assets and liabilities with counterparties where the right of offset exists.
Transfers. During the years ended December 31, 2025, 2024 and 2023, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.
v3.25.4
Accounts Receivable
 12 Months Ended
Dec. 31, 2025
Receivables [Abstract]  
Accounts Receivable Accounts Receivable
A summary of accounts receivable is as follows (in thousands):
 December 31,
 20252024
Oil, natural gas and NGL sales$16,740 $15,320 
Joint interest billing11,138 9,957 
Other788 628 
Total accounts receivable28,666 25,905 
Less: allowance for expected credit losses(2,480)(2,027)
Total accounts receivable, net$26,186 $23,878 
The following table represents the balance in the allowance for expected credit losses:

Year Ended December 31,
20252024
Beginning balance$(2,027)$(2,027)
Additional allowance(453)— 
Deductions (1)— — 
Ending balance$(2,480)$(2,027)
__________________
(1)Deductions represent collections of amounts for which an allowance had previously been established.
v3.25.4
Derivatives
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivatives Derivatives
Commodity Derivatives 

The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil, natural gas and NGL. On occasion, the Company has attempted to manage this risk on a portion of its forecasted oil, natural gas or NGL production sales through the use of commodity derivative contracts.

Historically, the Company has not designated any of its derivative contracts as hedges for accounting purposes. As applicable, if the Company has open derivative contracts, the Company has recorded such contracts at fair value with changes in derivative contract fair values recognized as a gain or loss on derivative contracts in the condensed consolidated income statements. Commodity derivative contracts were settled on a monthly basis, and the commodity derivative contract valuations were adjusted on a mark-to-market valuation basis quarterly.

The following table summarizes derivative activity (in thousands):
Year Ended December 31,
202520242023
(Gain) loss on derivative contracts$(7,763)$(748)$(1,447)
Realized settlement gains (losses) on derivative contracts$5,189 $548 $5,876 

Master Netting Agreements and the Right of Offset. As applicable, the Company historically has had master netting agreements with all of its commodity derivative counterparties and has presented its derivative assets and liabilities with the same counterparty on a net basis in the unaudited condensed consolidated balance sheets. As a result of the netting provisions, the Company's maximum amount of loss under commodity derivative transactions due to credit risk was limited to the net amounts due from its counterparties. As of December 31, 2025, the Company’s open commodity derivative contracts were held with one counterparty.
The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative asset positions (in thousands):

As of December 31, 2025Gross AmountsGross Amounts OffsetAmounts Net of OffsetFinancial CollateralNet Amount
Assets
Derivative contracts - current
$3,130 $357 $2,773 $— $2,773 
Total$3,130 $357 $2,773 $— $2773 


At December 31, 2024Gross AmountsGross Amounts OffsetAmounts Net of OffsetFinancial CollateralNet Amount
Assets
Derivative contracts - current$744 $630 $114 $— $114 
Derivative contracts - non-current86 — 86 — 86 
Total$830 $630 $200 $— $200 

Because we did not designate any of our derivative contracts as hedges for accounting purposes, changes in the fair value of our derivative contracts were recognized as gains and losses in the earnings of the relevant period. As a result, and as applicable, our current period earnings could have been significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value were principally measured based on a comparison of future prices to the contract price at the end of the period.

As of December 31, 2025, the Company's open derivative contracts consisted of oil and natural gas commodity derivative contracts under which we will receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume. These commodity derivative contracts consisted of the following:

PeriodIndexDaily Volume
Weighted Average Price
Oil (Bbl)
Fixed Price SwapsJanuary 2026 - June 2026NYMEX WTI300$68.67
Natural Gas (MMBtu)
Fixed Price SwapsJanuary 2026 - December 2026NYMEX Henry Hub11,797$4.16
Producer Costless CollarsJanuary 2026 - December 2026NYMEX Henry Hub4,500
$3.35 Put / $5.35 Call

As of December 31, 2024, the Company's open derivative contracts consisted of oil and NGL commodity derivative contracts under which we will receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume. These commodity derivative contracts consisted of the following:
PeriodIndexDaily VolumeWeighted Average Price
Oil (Bbl)
Fixed Price Swaps
January 2025 - December 2025NYMEX WTI500$71.60
January 2026 - June 2026NYMEX WTI300$68.67
NGL (Bbl)
Fixed Price SwapsJanuary 2025 - December 2025
Mont Belvieu OPIS (1)
300$39.69
(1) NGL swaps exclude ethane


Fair Value of Derivatives 

The following table presents the fair value of the Company’s derivative contracts on a net basis with same counterparty netting (in thousands):
Type of ContractBalance Sheet ClassificationDecember 31, 2025
Oil and natural gas price swaps and collarsCurrent assets - Derivative Contracts$2,773 
Total net derivative contracts$2,773 

Type of ContractBalance Sheet ClassificationDecember 31, 2024
Oil and NGL price swapsCurrent assets - Derivative Contracts$114 
Oil and NGL price swapsNon-current assets - Derivative Contracts86 
Total net derivative contracts$200 

See Note 4 for additional discussion of the fair value measurement of the Company’s derivative contracts.
v3.25.4
Leases
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Leases Leases
The Company determines if an arrangement is or contains a lease at inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. As most of the Company's leases do not provide an implicit rate, the Company's incremental borrowing rate was used as the discount rate when determining the present value of future payments. Lease assets are recognized based on the lease liability plus any prepaid lease payments and excluding lease incentives and initial direct costs incurred for the same periods. The Company's lease terms may include options to extend or terminate the lease when it is reasonably certain that option will be exercised. The Company recognizes right-of-use assets and current and non-current lease liabilities on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.

Capitalized operating leases are included in other assets, other current liabilities and other long-term obligations, and finance leases are included in other property, plant and equipment, other current liabilities and other long-term obligations on the accompanying consolidated balance sheet as of December 31, 2025 and 2024.

The Company had operating and financing leases for vehicles, office space and equipment outstanding during the year ended December 31, 2025, 2024 and 2023 which were not significant to the consolidated financial statements.
The components of lease costs recognized for the Company's right-of-use leases are shown below (in thousands):
Year Ended December 31,
202520242023
Short-term lease cost (1)$2,303 $1,815 $3,139 
Financing lease cost861 904 874 
Operating lease cost161 167 167 
Total lease cost$3,325 $2,886 $4,180 
___________________
(1)During the year ended December 31, 2025, there were $8.0 million in short-term lease costs capitalized associated with our drilling rig lease. During the years ended December 31, 2024, there were no short-term lease costs capitalized associated with drilling rig leases. During the year ended December 31, 2023, there were $1.6 million in short-term lease costs capitalized associated with our drilling rig lease. Portions of these costs were reimbursed to the Company by other working interest owners.

As of December 31, 2025, the Company's weighted average remaining lease term and discount rate for its finance leases were 2.2 years and 7.69%, respectively. At December 31, 2025, the Company's operating lease had a term of one year remaining and a discount rate of 7.38%.
Leases Leases
The Company determines if an arrangement is or contains a lease at inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. As most of the Company's leases do not provide an implicit rate, the Company's incremental borrowing rate was used as the discount rate when determining the present value of future payments. Lease assets are recognized based on the lease liability plus any prepaid lease payments and excluding lease incentives and initial direct costs incurred for the same periods. The Company's lease terms may include options to extend or terminate the lease when it is reasonably certain that option will be exercised. The Company recognizes right-of-use assets and current and non-current lease liabilities on the balance sheet for all leases with lease terms of greater than one year. Short-term leases that have an initial term of one year or less are not capitalized. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.

Capitalized operating leases are included in other assets, other current liabilities and other long-term obligations, and finance leases are included in other property, plant and equipment, other current liabilities and other long-term obligations on the accompanying consolidated balance sheet as of December 31, 2025 and 2024.

The Company had operating and financing leases for vehicles, office space and equipment outstanding during the year ended December 31, 2025, 2024 and 2023 which were not significant to the consolidated financial statements.
The components of lease costs recognized for the Company's right-of-use leases are shown below (in thousands):
Year Ended December 31,
202520242023
Short-term lease cost (1)$2,303 $1,815 $3,139 
Financing lease cost861 904 874 
Operating lease cost161 167 167 
Total lease cost$3,325 $2,886 $4,180 
___________________
(1)During the year ended December 31, 2025, there were $8.0 million in short-term lease costs capitalized associated with our drilling rig lease. During the years ended December 31, 2024, there were no short-term lease costs capitalized associated with drilling rig leases. During the year ended December 31, 2023, there were $1.6 million in short-term lease costs capitalized associated with our drilling rig lease. Portions of these costs were reimbursed to the Company by other working interest owners.

As of December 31, 2025, the Company's weighted average remaining lease term and discount rate for its finance leases were 2.2 years and 7.69%, respectively. At December 31, 2025, the Company's operating lease had a term of one year remaining and a discount rate of 7.38%.
v3.25.4
Property, Plant and Equipment
 12 Months Ended
Dec. 31, 2025
Property, Plant and Equipment [Abstract]  
Property, Plant and Equipment Property, Plant and Equipment
Property, plant and equipment consists of the following (in thousands):
December 31,
20252024
Oil and natural gas properties
Proved$1,759,943 $1,689,807 
Unproved27,520 23,504 
Total oil and natural gas properties1,787,463 1,713,311 
Less accumulated depreciation, depletion and impairment(1,446,824)(1,415,110)
Net oil and natural gas properties capitalized costs340,639 298,201 
Land200 200 
Electrical infrastructure122,380 121,818 
Non-oil and natural gas equipment1,626 1,634 
Buildings and structures3,603 3,603 
Financing leases1,345 1,286 
Total129,154 128,541 
Less accumulated depreciation and amortization(53,505)(47,852)
Other property, plant and equipment, net75,649 80,689 
Total property, plant and equipment, net$416,288 $378,890 

The average rates used for depreciation and depletion of oil and natural gas properties were $4.63 per Boe in 2025, $3.52 per Boe in 2024 and $1.82 per Boe in 2023.
Costs Excluded from Amortization

Costs excluded from amortization were related to unproved properties and were $27.5 million and $23.5 million, at December 31, 2025 and 2024, respectively.

For leases that do not have existing production that would otherwise extend the lease term, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a three to five year period from the original lease date. In addition, the Company’s internal engineers evaluate all properties on a quarterly basis.
v3.25.4
Accounts Payable and Accrued Expenses
 12 Months Ended
Dec. 31, 2025
Payables and Accruals [Abstract]  
Accounts Payable and Accrued Expenses Accounts Payable and Accrued Expenses
Accounts payable and accrued expenses consist of the following (in thousands):
 December 31,
 20252024
Accounts payable and other accrued expenses$25,402 $19,502 
Production payable29,221 27,557 
Payroll and benefits3,211 2,912 
Taxes payable1,203 654 
Total accounts payable and accrued expenses$59,037 $50,625 
v3.25.4
Asset Retirement Obligations
 12 Months Ended
Dec. 31, 2025
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations Asset Retirement Obligations
The following table presents the balance and activity of the Company’s asset retirement obligations (in thousands):
Year Ended December 31,
202520242023
Beginning balance$68,580 $64,404 $63,709 
Liability incurred upon acquiring and drilling wells57 353 113 
Revisions in estimated cash flows (1)29 31 (939)
Liability settled or disposed in current period (1,377)(889)(2,927)
Accretion (2)5,102 4,681 4,448 
Ending balance72,391 68,580 64,404 
Less: current portion8,098 9,131 9,851 
Asset retirement obligations, net of current$64,293 $59,449 $54,553 
____________________

(1)    Revisions for the year ended December 31, 2023 relate primarily to changes in working interest and estimated well lives.
(2)    Included on the Depreciation and depletion - oil and natural gas line item on the Consolidated Statements of Operations.
v3.25.4
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Commitments and Contingencies    
Included below is a discussion of the Company's various future commitments and contingencies as of December 31, 2025. The Company has provided accruals where necessary for contingent liabilities, based on ASC 450, Contingencies, when it has determined that a liability is probable and reasonably estimable. The Company continuously assesses the potential liability related to the Company's pending litigation and revises its estimates when additional information becomes available. Additionally, the Company currently expenses all legal costs as they are incurred.
Legal Proceedings. As previously disclosed, on May 16, 2016, the Company and certain of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court confirmed the joint plan of reorganization (the “Plan”) of the Debtors on September 9, 2016, and the Debtors subsequently emerged from bankruptcy on October 4, 2016.

Pursuant to the Plan, claims against the Company were discharged without recovery in each of the following consolidated cases:

• In re SandRidge Energy, Inc. Securities Litigation, Case No. 5:12-cv-01341-LRW, USDC, Western District of Oklahoma (“In re SandRidge Energy, Inc. Securities Litigation”); and

• Ivan Nibur, Lawrence Ross, Jase Luna, Matthew Willenbucher, and the Duane & Virginia Lanier Trust v. SandRidge Mississippian Trust I, et al., Case No. 5:15-cv-00634-SLP, USDC, Western District of Oklahoma (“Lanier Trust”)

Both cases were settled with all defendants except the SandRidge Mississippian Trust I (“the Trust”) in Lanier Trust, which is being sued by a class of purchasers of units under the remaining claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder, based on allegations that the Trust made misrepresentations or omissions concerning various topics including the performance of wells operated by the Company. On September 11, 2025, the Federal District Court (Western District of Oklahoma) issued summary judgment in favor of the Trust with respect to all claims and dismissed, with prejudice, all claims against the Company, and the plaintiffs' right to appeal has expired.

Separately, the Company had received a demand by two of the settling individual defendants to fund a proposed settlement of $17.0 million with those defendants. The insurance carriers funded the $17.0 million settlement and then requested indemnification from the Company. The Company refused and filed an action in Oklahoma state court seeking a declaratory judgment that the insurers were not entitled to indemnification; the insurers counterclaimed. Subsequently, the Company voluntarily dismissed its action. In line with the Company's position regarding the insurers’ claims, the Company filed motions in the United States Bankruptcy Court for the Southern District of Texas seeking to reopen the bankruptcy case and to obtain a declaration that the insurers’ claims were discharged under the September 2016 plan. The motions were denied and the Company appealed the bankruptcy court’s decision to the Southern District of the United States District Court of Texas; the appeal was denied in December of 2025 and the Company has appealed the District Court's decision to the United States Court of Appeals for the Fifth Circuit. Independent of the Company’s appeal to reopen the bankruptcy case, the insurers’ Oklahoma counterclaim is stayed, with no further development. The Company disputes any liability, as it believes it has meritorious defenses, and intends to continue to vigorously defend against this claim. Considering the status of this matter, and the facts, circumstances and legal theories thereto, the Company is not able to determine the likelihood of an outcome. The Company has not established any liabilities relating to this matter.

In addition to the matters described above, the Company is involved in various lawsuits, claims and proceedings, which are being handled and defended by the Company in the ordinary course of business.
v3.25.4
Income Taxes
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Income Taxes Income Taxes
On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act ("OBBBA"). The OBBBA makes permanent key elements of the Tax Cuts and Jobs Act, including 100% bonus depreciation, domestic research cost expensing, and the business interest expense limitation. ASC 740, "Income Taxes", requires the effects of changes in tax rates and laws on deferred tax balances to be recognized in the period in which the legislation is enacted. The Company has completed its initial assessment of the OBBBA corporate tax provisions which were enacted on July 4, 2025 and estimated its impact on the consolidated financial statements to be immaterial.

The Company’s income tax (benefit) provision consisted of the following components (in thousands):
Year Ended December 31,
202520242023
Current
Federal$— $— $— 
State— — — 
— — — 
Deferred
Federal(4,755)(19,370)12,002 
State(780)(2,862)1,958 
(5,535)(22,232)13,960 
Total (benefit) provision $(5,535)$(22,232)$13,960 

A reconciliation of the (benefit) provision for income taxes at the statutory federal tax rate to the Company’s actual income tax (benefit) provision is as follows (in thousands):
Year Ended December 31, 2025Year Ended December 31, 2024Year Ended December 31, 2023
$ AmountPercent$ AmountPercent$ AmountPercent
Provision for income taxes at U.S. Federal statutory rate$13,580 21.0 %$8,559 21.0 %$15,712 21.0 %
State and local income taxes, net of federal benefit (1)(780)(1.2)%(2,862)(7.0)%1,958 2.6 %
Effect of changes in tax laws or rates enacted in the current period— — %— — %— — %
Changes in the valuation allowance(18,380)(28.4)%(27,930)(68.5)%(3,699)(4.9)%
Nontaxable or nondeductible items45 0.1 %1 — %(69)(0.1)%
Other adjustments— — %— — %58 0.1 %
Total$(5,535)(8.5)%$(22,232)(54.5)%$13,960 18.7%
____________________

(1) The state that contributes to the majority (greater than 50%) of the tax effect in this category is Oklahoma.

Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. In assessing the realizability of the deferred tax assets, we consider whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized. In prior years, we determined that the deferred tax assets did not meet the more likely than not threshold of being utilized and thus recorded a valuation allowance. As of December 31, 2025, we partially released our valuation allowance on our deferred tax assets by $78.3 million. We anticipate being able to utilize these deferred tax assets based on the generation of future income. A change in the estimate of future income could cause the valuation allowance to be adjusted in subsequent periods. Our partial valuation allowance release of $72.8 million as of December 31, 2024 was increased by $5.5 million due to changes in expected future income, resulting in net deferred tax assets of $78.3 million as of December 31, 2025.
Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):
 Year Ended December 31,
20252024
Deferred tax liabilities
Investments (1)$— $— 
Derivative contracts— — 
Total deferred tax liabilities— — 
Deferred tax assets
Property, plant and equipment50,421 57,061 
Net operating loss carryforwards363,807 373,506 
Tax credits and other carryforwards33,851 33,851 
Asset retirement obligations13,091 13,327 
Investments (1)98 97 
Other1,935 1,454 
Total deferred tax assets463,203 479,296 
Valuation allowance(384,867)(406,495)
Net deferred tax asset$78,336 $72,801 
____________________

(1) Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts.

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 during 2016 that subjected certain of the Company’s tax attributes, including net operating losses ("NOLs"), to an IRC Section 382 limitation. This limitation has not resulted in cash taxes for any period subsequent to the ownership change. Since the 2016 ownership change, the Company has generated additional NOLs and other tax attributes that are not currently subject to an IRC Section 382 limitation. The Company's ability to use NOLs and other tax attributes to reduce taxable income and income taxes could be materially impacted by a future IRC 382 ownership change. Future transactions involving the Company's stock including those outside of the Company's control could cause an IRC 382 ownership change resulting in a limitation on tax attributes currently not limited and a more restrictive limitation on tax attributes currently subject to the previous IRC 382 limitation.

As of December 31, 2025, the Company had approximately $1.6 billion of federal NOL carryforwards, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation. Of the $1.6 billion of federal NOL carryforwards, $0.7 billion expire during the years 2028 through 2037, while $0.9 billion do not have an expiration date. In addition, the Company had approximately $1.0 billion of state NOL carryforwards, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation. Of the $1.0 billion in state NOL carryforwards, approximately $199.0 million are derived from states the Company currently does not operate in. Of the remaining state NOL carryforwards, $645.0 million do not have an expiration date and $176.0 million expire during the years 2025 through 2037. Additionally, the Company had federal tax credits in excess of $33.5 million, which begin expiring in 2029.

The Company did not have any unrecognized tax benefits at December 31, 2025, 2024 or 2023.
The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2022 to present remain open for federal examination. Additionally, tax years 2005 through 2021 remain subject to examination for the purpose of determining the amount of federal NOL and other carryforwards. The number of years open for state tax audits varies, depending on the state, but is generally from three to five years.
v3.25.4
Equity
 12 Months Ended
Dec. 31, 2025
Equity [Abstract]  
Equity Equity
Capital Stock and Equity Awards. Our authorized capital stock consists of 300.0 million shares, which include 250.0 million shares of common stock, $0.001 par value per share and 50.0 million shares of preferred stock, par value $0.001 per share. At December 31, 2025, the Company had 36.8 million shares of common stock issued and outstanding, including 0.1 million of shares of unvested restricted stock awards. The Company also has 0.2 million of unvested restricted stock units, an immaterial amount of unvested performance share units and 0.1 million of unvested stock options outstanding at December 31, 2025 as discussed further in Note 15. At December 31, 2024, the Company had 37.2 million shares of common stock issued and outstanding, including 0.1 million of shares of unvested restricted stock awards. The Company also has 0.2 million of unvested restricted stock units, an immaterial amount of performance share units and 0.1 million stock options outstanding at December 31, 2024 as discussed further in Note 15.

Share Repurchase Program. In May 2023, the Board approved a share repurchase program (the “Program”) authorizing the Company to repurchase up to an aggregate of $75.0 million of the Company’s outstanding common stock with the Company’s cash on hand. The Program replaced the prior share repurchase program previously approved by the Board in August 2021 of $25.0 million. Purchases under the Program are intended to meet the requirements of Rule 10b5-1 of the Exchange Act. The Program does not require any specific number of shares to be acquired, can be modified or discontinued by the Board at any time and does not have an expiration date. For the year ended December 31, 2025, the Company repurchased 595,635 shares for $6.4 million. For the year ended December 31, 2024, the Company repurchased 21,308 shares for $0.2 million.

Dividends. On August 5, 2025, the Board approved a dividend reinvestment plan (the “Dividend Reinvestment Plan”), pursuant to which the stockholders of the Company may, at their election, reinvest any dividends declared by the Board.

In connection with the Dividend Reinvestment Plan, the Board approved a general waiver under the Company’s Tax Benefits Preservation Plan (the “Tax Benefits Preservation Plan”), by and between the Company and Equiniti (formerly known as American Stock Transfer & Trust Company, LLC). This waiver applies to any stockholders who as of the date immediately prior to the adoption of the Dividend Reinvestment Plan beneficially owned 4.9% or more of the Company’s outstanding common stock and who would otherwise trigger the rights plan, but only as a result of shares of stock they receive under the Dividend Reinvestment Plan, and not otherwise. Cash dividend payments for the year ended December 31, 2025 totaled $15.9 million. During the during ended December 31, 2025, the Company issued 92,733 shares of common stock in lieu of cash dividends under the Dividend Reinvestment Plan. Cash dividends for the year ended December 31, 2024 totaled $72.3 million, which included $0.5 million of dividends on vested stock awards.

The Tax Benefits Preservation Plan. On July 1, 2020, the Board declared a dividend distribution of one right (a “Right”) for each outstanding share of Company common stock, par value $0.001 per share to stockholders of record at the close of business on July 13, 2020. Each Right entitles its holder, under certain circumstances, to purchase from the Company one one-thousandth of a share of Series A Junior Participating Preferred Stock of the Company, par value $0.001 per share, at an exercise price of $5.00 per Right, subject to adjustment. The description and terms of the Rights are set forth in the tax benefits preservation plan, dated as of July 1, 2020, between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (and any successor rights agent, the “Rights Agent”).

The Company adopted the Tax Benefits Preservation Plan, as amended on March 16, 2021, and June 20, 2023 in order to protect stockholder value against a possible limitation on the Company’s ability to use its tax net operating losses (the “NOLs”) and certain other tax benefits to reduce potential future U.S. federal income tax obligations. The NOLs are a valuable asset to the Company, which may inure to the benefit of the Company and its stockholders. However, if the Company experiences an “ownership change,” as defined in Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), its ability to fully utilize the NOLs and certain other tax benefits will be substantially limited and the timing of the usage of the NOLs and such other benefits could be substantially delayed, which could significantly impair the value of those assets. Generally, an “ownership change” occurs if the percentage of the Company’s stock owned by one or more of its “five-percent stockholders” (as such term is defined in Section 382 of the Code) increases by more than 50 percentage points over the lowest percentage of stock owned by such stockholder or stockholders at any time over a three-year period. The Tax Benefits Preservation Plan is intended to prevent against such an “ownership change” by deterring any person or group from acquiring beneficial ownership of 4.9% or more of the Company’s securities.

Subject to certain exceptions, the Rights become exercisable and trade separately from Common Stock only upon the “Distribution Time,” which occurs upon the earlier of:
•the close of business on the tenth (10th) day after the “Stock Acquisition Date,” which is (a) the first date of public announcement that a person or group of affiliated or associated persons (with certain exceptions, an “Acquiring Person”) has acquired, or obtained the right or obligation to acquire, beneficial ownership of 4.9% or more of the outstanding shares of Common Stock (with certain exceptions) or (b) such other date, as determined by the Board, on which a person or group has become an Acquiring Person, or

•the close of business on the tenth (10th) business day (or later date as may be determined by the Board prior to such time as any person or group becomes an Acquiring Person) following the commencement of a tender offer or exchange offer which, if consummated, would result in a person or group becoming an Acquiring Person.

Any existing stockholder or group that beneficially owns 4.9% or more of Common Stock has been grandfathered at its current ownership level, but the Rights will not be exercisable if, at any time after the announcement of the Tax Benefits Preservation Plan, such stockholder or group increases its ownership of Common Stock by one share of Common Stock. Certain synthetic interests in securities created by derivative positions, whether or not such interests are considered to be ownership of the underlying Common Stock or are reportable for purposes of Regulation 13D of the Securities Exchange Act of 1934, as amended, are treated as beneficial ownership of the number of shares of Common Stock equivalent to the economic exposure created by the derivative position, to the extent actual shares of Common Stock are directly or indirectly held by counterparties to the derivatives contracts.

Until the earlier of the Distribution Time and the Expiration Time, the surrender for transfer of any shares of Common Stock will also constitute the transfer of the Rights associated with those shares. As soon as practicable after the Distribution Time, separate rights certificates will be mailed to holders of record of Common Stock as of the close of business on the Distribution Time. From and after the Distribution Time, the separate rights certificates alone will represent the Rights. Except as otherwise provided in the Tax Benefits Preservation Plan, only shares of Common Stock issued prior to the Distribution Time will be issued with Rights. The Rights are not exercisable until the Distribution Time.

The Tax Benefits Preservation Plan was approved at the 2021 annual meeting of stockholders on May 25, 2021. On June 20, 2023, the Board approved an amendment to the Tax Benefits Preservation Plan, approved by stockholders, to extend the expiration time of the Tax Benefits Preservation Plan from July 1, 2023 to July 1, 2026. This amendment was approved at the Company’s 2024 Annual Meeting.

In the event that any person or group (other than certain exempt persons) becomes an Acquiring Person (a “Flip-in Event”), each holder of a Right (other than any Acquiring Person and certain related parties, whose Rights automatically become null and void) will have the right to receive, upon exercise, shares of Common Stock having a value equal to two times the exercise price of the Right.

In the event that, at any time following the Stock Acquisition Date, any of the following occurs (each, a “Flip-over Event”):

•the Company consolidates with, or merges with and into, any other entity, and the Company is not the continuing or surviving entity

•any entity engages in a share exchange with or consolidates with, or merges with or into, the Company, and the Company is the continuing or surviving entity and, in connection with such share exchange, consolidation or merger, all or part of the outstanding shares of Common Stock are changed into or exchanged for stock or other securities of any other entity or cash or any other property; or

•the Company sells or otherwise transfers, in one transaction or a series of related transactions, fifty percent (50%) or more of the Company’s assets, cash flow or earning power, each holder of a Right (except Rights which previously have been voided as described above) will have the right to receive, upon exercise, common stock of the acquiring company having a value equal to two times the exercise price of the Right.
Shares Withheld for Taxes. The following table shows the number of shares withheld for taxes and the associated value of those shares. These shares were accounted for as treasury stock when withheld, and then immediately retired (in thousands).
Year Ended December 31,
202520242023
Number of shares withheld for taxes25 29 59 
Value of shares withheld for taxes$290 $393 $929 
v3.25.4
Revenues
 12 Months Ended
Dec. 31, 2025
Revenue from Contract with Customer [Abstract]  
Revenues Revenues
The following table disaggregates the Company’s revenue by source (in thousands):
Year Ended December 31,
202520242023
Oil $77,270 $68,231 $78,174 
Natural gas41,587 21,397 34,941 
NGL37,500 35,662 35,526 
Total revenues$156,357 $125,290 $148,641 

Oil, natural gas and NGL revenues. A majority of the Company’s revenues come from sales of oil, natural gas and NGLs. In accordance with the contracts governing these sales, performance obligations to customers are satisfied and revenues are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck. As the Company’s customers obtain control of the production prior to selling it to other end customers, the Company presents its revenues on a net basis, rather than on a gross basis.

Pricing for the Company’s oil, natural gas and NGL contracts is variable and is based on volumes sold multiplied by either an index price, net of deductions, or a percentage of the sales price obtained by the customer, which is also based on index prices. The transaction price is allocated on a pro-rata basis to each unit of oil, natural gas or NGL sold based on the terms of the contract. Oil, natural gas and NGL revenues are also recorded net of royalties, discounts and allowances, and transportation costs, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from revenues and are included in production, ad valorem, and other taxes expense in the consolidated statements of operations.

Revenues Receivable. The Company records an asset in accounts receivable, net on its consolidated balance sheet for revenues receivable from contracts with customers at the end of each period. Pricing for revenues receivable is estimated using current month crude oil, natural gas and NGL prices, net of deductions. Revenues receivable on operated properties are typically collected the month after the Company delivers the related production to its purchaser. As of December 31, 2025, 2024, and 2023 the Company had revenues receivable of $16.7 million, $15.3 million, and $14.5 million, respectively, and we did not record any credit losses on revenue receivable as of December 31, 2025, 2024 and 2023. As of December 31, 2025, five purchasers accounted for approximately 79.5% of our revenues receivable.
v3.25.4
Share Based Compensation
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Share-Based Compensation Share-Based Compensation
Share-Based Compensation    

Omnibus Incentive Plan. The Omnibus Incentive Plan became effective on October 4, 2016 and authorizes the issuance of up to 4.6 million shares of SandRidge common stock.

Persons eligible to receive awards under the Omnibus Incentive Plan include non-employee directors of the Company, employees of the Company or any of its affiliates, and certain consultants and advisors to the Company or any of its affiliates. The types of awards that may be granted under the Omnibus Incentive Plan include stock options, restricted stock, performance awards and other forms of awards granted or denominated in shares of common stock, as well as certain cash-based awards. At December 31, 2025, the Company had restricted stock awards, restricted stock units, performance share units and stock options outstanding under the Omnibus Incentive Plan. Forfeitures for these awards are recognized as they occur.
Restricted Stock Awards. The Company’s restricted stock awards are equity-classified awards and are valued based upon the market value of the Company’s common stock on the date of grant. Outstanding restricted shares at December 31, 2025 will generally vest over a one-year period with a remaining weighted average contractual period of 0.5 years and have $0.3 million of associated unrecognized compensation cost.

The following table presents a summary of the Company’s unvested restricted stock awards:
Number of
Shares
Weighted-
Average Grant
Date Fair Value
(In thousands)
Unvested restricted stock awards outstanding at January 1, 202318$18.93 
Granted54$13.85 
Vested(18)$18.93 
Forfeited / Canceled—$— 
Unvested restricted stock awards outstanding at December 31, 202354$13.85 
Granted65$13.20 
Vested(65)$13.76 
Forfeited / Canceled—$— 
Unvested restricted stock awards outstanding at December 31, 202453$13.17 
Granted67$10.94 
Vested (1)(53)$13.17 
Forfeited / Canceled—$— 
Unvested restricted stock awards outstanding at December 31, 202567$10.94 
Totals may not sum or recalculate due to rounding
____________________

(1)     The aggregate intrinsic value of restricted stock that vested during 2025 was approximately $0.6 million based on the stock price at the time of vesting.

Restricted Stock Units. The Company’s restricted stock units awards are equity-classified awards and are valued based upon the market value of the Company’s common stock on the date of grant. Outstanding restricted stock units at December 31, 2025 will generally vest over a three-year period with a remaining weighted average contractual period of 1.8 years and have $1.7 million associated unrecognized compensation cost at December 31, 2025.
The following table presents a summary of the Company’s unvested restricted stock units:
Number of
Units
Weighted-
Average Grant
Date Fair Value
(In thousands)
Unvested restricted stock units outstanding at January 1, 2023252$5.93 
Granted79$15.13 
Vested(175)$4.33 
Forfeited / Canceled(18)$11.50 
Unvested restricted stock units outstanding at December 31, 2023138$12.51 
Granted96$13.14 
Vested(81)$10.85 
Forfeited / Canceled—$— 
Unvested restricted stock units outstanding at December 31, 2024153$13.78 
Granted109$11.48 
Vested (1)(61)$13.92 
Forfeited / Canceled—$— 
Unvested restricted stock units outstanding at December 31, 2025201$12.50 
Totals may not sum or recalculate due to rounding
____________________

(1)     The aggregate intrinsic value of restricted stock units that vested during 2025 was approximately $0.7 million based on the stock price at the time of vesting.

Performance Share Units. The Company’s performance share units awards are equity-classified awards and are valued based upon the market value of the Company’s common stock on the date of grant. Outstanding performance share units at December 31, 2025 will generally vest over a one year period with a remaining weighted average contractual period of 0.2 years and an $0.1 million amount of unrecognized compensation cost at December 31, 2025.
The following table presents a summary of the Company's performance share units:
Number of
Units
Weighted-
Average Grant
Date Fair Value
(In thousands)
Unvested performance share units outstanding at January 1, 202317$13.51 
Granted19$15.31 
Vested(17)$13.51 
Forfeited / Canceled(3)$15.31 
Unvested performance share units outstanding at December 31, 202316$15.31 
Granted23$13.63 
Vested(16)$15.31 
Forfeited / Canceled—$— 
Unvested performance share units outstanding at December 31, 202423$13.63 
Granted44$11.60 
Vested (1)(23)$13.63 
Forfeited / Canceled—$— 
Unvested performance share units outstanding at December 31, 202544$11.60 
Totals may not sum or recalculate due to rounding
____________________

(1)     The aggregate intrinsic value of performance share units that vested during 2025 was approximately $0.3 million.

Stock Options

The fair value of stock options was estimated on the date of the grant using a Black-Scholes valuation model that used the weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s common stock and other factors. The Company uses historical data on the exercise of stock options, post-vesting forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant. Generally, stock options granted to employees and directors vest ratably over three years from the grant date and expire seven years from the date of grant. There were no stock options granted during the years ended December 31, 2025, 2024 or 2023.

AssumptionsYear Ended December 31, 2021
Risk-free interest rate0.79%
Expected dividend yield—%
Expected volatility78.2%
Expected term5 years
The following table presents a summary of the Company's stock option activity:
Number of SharesWeighted Average Exercise Price per ShareWeighted Average Remaining Contractual Term(years)Aggregate Intrinsic Value (in millions)
(In thousands)
Outstanding at January 1, 2023286$— 7.64$2.38 
Granted—$— — $— 
Exercised(36)$15.68 — $— 
Expired—$— — $— 
Forfeited / Canceled—$— — $— 
Outstanding at December 31, 2023250$— 7.66$1.02 
Exercisable at December 31, 2023100$— 7.66$0.41 
Outstanding at December 31, 2023250$— 7.66$1.02 
Granted—$— — $— 
Exercised—$— — $— 
Expired—$— — $— 
Forfeited / Canceled—$— — $— 
Outstanding at December 31, 2024250$— 6.65$0.53 
Exercisable at December 31, 2024150$— 6.65$0.32 
Outstanding at December 31, 2024250$— 6.65$0.53 
Granted—$— — $— 
Exercised—$— — $— 
Expired—$— — $— 
Forfeited / Canceled—$— — $— 
Outstanding at December 31, 2025250$— 5.65$1.21 
Exercisable at December 31, 2025200$— 5.65$0.97 
Totals may not sum or recalculate due to rounding
____________________

(1)     All outstanding stock options as of December 31, 2025 are expected to vest.
In August 2021, the Company granted nonqualified stock options. As of December 31, 2025, the total unrecognized compensation expense was $0.2 million and will be recognized over a weighted average period of 0.7 years. The Company issues new shares upon stock option exercises.
The following tables summarize the Company's share and incentive-based compensation (in thousands):
Recurring Compensation Expense (1)
Year Ended December 31, 2025
Equity-classified awards:
Restricted stock awards and units$1,909 
Performance share units535 
Stock options300 
Total share-based compensation expense$2,744 
Year Ended December 31, 2024
Equity-classified awards:
Restricted stock awards and units$1,790 
Performance share units264 
Stock options300 
Total share-based compensation expense$2,354 
Year Ended December 31, 2023
Equity-classified awards:
Restricted stock awards and units$1,415 
Performance share units229 
Stock options301 
Total share-based compensation expense$1,945 
____________________

(1)Included in general and administrative expense in the accompanying consolidated statements of operations.
v3.25.4
Incentive and Deferred Compensation Plans
 12 Months Ended
Dec. 31, 2025
Compensation Related Costs [Abstract]  
Incentive and Deferred Compensation Plans Incentive and Deferred Compensation Plans
Annual Incentive Plan. The Annual Incentive Plan ("AIP") incorporates quantitative performance measures, strategic qualitative goals and competitive target award levels for management and employees for the 2025 and 2024 performance years. Incentive bonus awards for 2025 will be provided based on performance measures related to health, safety and environment, production, operating expenses, capital expenditures, general and administrative expenses, among other metrics and will be paid in 2026 at the discretion of the Board. As of December 31, 2025 and 2024, the Company accrued approximately $2.9 million and $2.2 million, respectively for AIP. AIP Payments totaling $2.7 million were paid in 2025 for the 2024 performance year and $2.2 million were paid in 2024 for the 2023 performance year.

401(k) Plan. The Company maintains a 401(k) retirement plan for its employees. Under this plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by the IRS. For the years ended December 31, 2025, 2024 and 2023, the Company made matching contributions to the plan equal to 100% on the first 10% of employee deferred wages, excluding incentive compensation, totaling $0.9 million for the year ended December 31, 2025, $0.9 million for the years ended December 31, 2024, and $0.8 million for the year ended December 31, 2023. Participants in the plan are immediately 100% vested in the discretionary employee contributions and related earnings on those contributions. The Company's matching contributions and related earnings vest based on years of service, with full vesting occurring on the fourth anniversary of employment.
v3.25.4
Earnings per Share
 12 Months Ended
Dec. 31, 2025
Earnings Per Share [Abstract]  
Earnings per Share Earnings per Share
The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings (loss) per share:
Net Income (loss)
Weighted Average SharesEarnings (Loss) Per Share
(In thousands, except per share amounts)
Year Ended December 31, 2025
Basic earnings per share$70,203 36,773 $1.91
Effect of dilutive securities
Restricted stock awards (1)— 29 
Restricted share units (1)— 63 
Performance share units (1)— 31 
Stock options (1)— 12 
Diluted earnings per share$70,203 36,908 $1.90
Year Ended December 31, 2024
Basic earnings per share$62,986 37,106 $1.70
Effect of dilutive securities
Restricted stock awards (1)— 28 
Restricted share units (1)— 32 
Performance share units (1)— 11 
Stock options (1)— 11 
Diluted earnings per share$62,986 37,188 $1.69
Year Ended December 31, 2023
Basic earnings per share$60,857 36,939 $1.65
Effect of dilutive securities
Restricted stock awards (1)— 19 
Restricted share units (1)— 120 
Performance share units (1)— 13 
Stock options (1)— 43 
Diluted earnings per share$60,857 37,134 $1.64
____________________

(1)The incremental shares of potentially dilutive restricted stock awards, restricted stock units, performance share units and stock options were included as their effect was dilutive under the treasury stock method..

See Note 15 for discussion of the Company’s share-based compensation awards.
v3.25.4
Segment Reporting
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Segment Reporting Segment Reporting
The Company operates as one operating segment, which is engaged in the acquisition, development, and production of oil, natural gas, and NGL in the U.S. Mid-Continent. The Company's chief operating decision maker ("CODM") is its Chief Executive Officer who reviews financial information on a consolidated basis and uses net income (loss) to make key operating decisions and assess financial performance. The CODM considers significant segment expenses to be those presented in the below table. Interest expense was not significant for the years ended December 31, 2025, 2024 and 2023. The CODM regularly reviews total assets, which were $644.0 million and $581.5 million as of December 31, 2025 and 2024, respectively.

The following table presents selected financial information with respect to the Company’s single operating segment (in thousands):
 Year Ended December 31,
 202520242023
Revenues
Oil$77,270 $68,231 $78,174 
Natural gas41,587 21,397 34,941 
NGL37,500 35,662 35,526 
Total revenues156,357 125,290 148,641 
Expenses
Lease operating expenses36,191 40,012 41,862 
Production, ad valorem, and other taxes9,846 6,780 10,870 
Depreciation and depletion—oil and natural gas36,439 25,976 15,657 
Depreciation and amortization—other6,433 6,503 6,518 
General and administrative13,201 11,695 10,735 
Restructuring expenses1,060 474 406 
Employee termination benefits— — 19 
(Gain) loss on derivative contracts(7,763)(748)(1,447)
Other operating (income) expense— 1,372 (157)
Total expenses95,407 92,064 84,463 
Income (loss) from operations60,950 33,226 64,178 
Other income (expense)
Interest income (expense), net3,687 7,744 10,552 
Other income (expense), net31 (216)87 
Total other income (expense)3,718 7,528 10,639 
Income (loss) before income taxes64,668 40,754 74,817 
Income tax (benefit)(5,535)(22,232)13,960 
Net income (loss)$70,203 $62,986 $60,857 
Capital expenditures, including acquisitions$77,500 $156,472 $33,664 
v3.25.4
Subsequent Events
 12 Months Ended
Dec. 31, 2025
Subsequent Events [Abstract]  
Subsequent Events Subsequent Events
On March 3, 2026, the Board declared a dividend of $0.12 per share of the Company’s common stock, which stockholders can elect to receive in cash or additional shares of common stock by enrolling in our previously announced Dividend Reinvestment Plan, payable on March 31, 2026 to stockholders of record on March 20, 2026.
Subsequent to December 31, 2025, the Company entered into the following natural gas derivative contracts:
PeriodType of Derivative InstrumentIndexDaily Volume (MMBtu)Weighted Average Price Per MMBtu
February 2026 - December 2026Fixed price swapsNYMEX Henry Hub3,750$4.20

Subsequent to December 31, 2025, the Company entered into the following oil derivative contracts:
PeriodType of Derivative InstrumentIndexDaily Volume (Bbl)Weighted Average Price Per Bbl
February 19, 2026 - December 2026Producer Costless CollarsNYMEX WTI816
$56.63 Put / $79.43 Call
March 2026 - December 2026Fixed price swapsNYMEX WTI275$70.00
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)
 12 Months Ended
Dec. 31, 2025
Extractive Industries [Abstract]  
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)
The supplemental information below includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):
 December 31,
 20252024
Oil and natural gas properties
Proved$1,759,943 $1,689,807 
Unproved27,520 23,504 
Total oil and natural gas properties1,787,463 1,713,311 
Less accumulated depreciation, depletion and impairment(1,446,824)(1,415,110)
Net oil and natural gas properties capitalized costs$340,639 $298,201 
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):
Year Ended December 31,
202520242023
Acquisitions of properties
Proved$2,331 $126,998 $11,232 
Unproved6,183 2,666 — 
Exploration(1)
5,016 11,246 (46)
Development63,970 15,562 22,478 
Total cost incurred$77,500 $156,472 $33,664 
____________________

(1)    Includes land, geological, geophysical and leasehold costs.

Costs Excluded from Amortization

The following table summarizes the costs, by year incurred, related to unproved properties, which were excluded from oil and natural gas properties subject to amortization at December 31, 2025 (in thousands):

Year Ended December 31,
Total2025202420232022 and Prior
Acquisition, exploration, and other unproved property costs$26,636 $10,589 $4,298 $(270)$12,019 
Capitalized interest884 — — 884 
Total costs incurred(1)
$27,520 $10,589 $4,298 $(270)$12,903 
____________________

(1)    Includes application of fresh start accounting in 2016 and reflects remaining balance at December 31, 2025.

Results of Operations for Oil and Natural Gas Producing Activities

The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the impact the Company’s operations have on actual net earnings.
Year Ended December 31,
202520242023
Revenues$156,357 $125,290 $148,641 
Expenses
Production costs46,629 46,832 53,099 
Depreciation and depletion36,439 25,976 15,657 
Total expenses83,068 72,808 68,756 
Income (loss) before income taxes73,289 52,482 79,885 
Income tax expense (benefit) (1)17,775 12,728 19,374 
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)$55,514 $39,754 $60,511 
____________________

(1)    Income tax (benefit) expense is hypothetical and is calculated by applying the Company’s statutory tax rate to income (loss) before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits.
Oil, Natural Gas and NGL Reserve Quantities

Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on oil, natural gas and NGL prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, production data, historical price and cost information, property ownership, well logs, geologic maps and well tests. The accuracy of the reserve estimates is dependent on many factors, including the following:

•the quality and quantity of available data and the engineering and geological interpretation of that data;

•estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

•the accuracy of mandated economic assumptions; and

•the judgment of the personnel preparing the estimates.

Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large expenditure is required for recompletion.

Approximately 97.9% of the Company’s proved reserves estimates have been prepared by independent reservoir engineers and geoscience professionals and the remaining 2.1% of proved reserves are estimated internally and are reviewed by members of the Company’s senior management to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC.

Cawley, Gillespie & Associates, independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs for approximately 97.9% and 97.5% of the Company’s net interest in oil and natural gas properties as of the years ended December 31, 2025 and 2024, respectively. Cawley, Gillespie & Associates are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. The remaining proved reserves were based on Company estimates.

The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under recent, past or historical economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.

2025 Activity. Proved reserves increased from 63.1 MMBoe at December 31, 2024 to 69.1 MMBoe at December 31, 2025, due to extensions of 7.3 MMBoe, purchases of 1.7 MMBoe, positive net revisions of 3.2 MMBoe due to an increase in year-end SEC natural gas pricing and price realizations and 4.5 MMBoe associated with other commercial improvements. These were partially offset by a decrease in SEC oil pricing, 6.8 MMBoe from the Company’s production during 2025, and 3.9 MMBoe attributable to performance, well shut-ins and other revisions.

2024 Activity. Proved reserves increased from 55.7 MMBoe at December 31, 2023 to 63.1 MMBoe at December 31, 2024, primarily due to purchases of 16.0 MMBoe, 3.5 MMBoe associated with other commercial improvements, and positive revisions of 2.3 MMBoe related to NGL Yield. These were partially offset by negative revisions including 6.6 MMBoe due to a decrease in year-end SEC commodity prices for oil and natural gas and price realizations, as well as 6.1 MMBoe from the Company’s production during 2024, and 1.7 MMBoe attributable to well performance, well shut-ins and other revisions.
2023 Activity. Proved reserves decreased from 74.3 MMBoe at December 31, 2022 to 55.7 MMBoe at December 31, 2023, primarily due to a decrease in year-end SEC commodity prices for oil and natural gas, price realizations and NGL yield which resulted in a decrease of 17.5 MMBoe, as well as 6.2 MMBoe from the Company's production during 2023, 1.4 MMBoe attributable to well shut-ins and other revisions, and 0.1 MMBoe in sales. The Company also had positive revisions including purchases of 1.8 MMBoe, extensions of 1.2 MMBoe, 1.9 MMBoe associated with well positive performance revisions, and 1.7 MMBoe associated with other commercial improvements.

The summary below presents changes in the Company’s estimated reserves.
OilNGLNatural GasTotal
 (MBbls)(MBbls)(MMcf) (1)MBoe
Proved developed and undeveloped reserves
As of December 31, 20228,421 25,433 242,822 74,324 
Revisions of previous estimates (2)(1,027)(8,200)(36,464)(15,304)
Acquisitions of new reserves453 379 5,474 1,745 
Extensions and discoveries283 357 3,431 1,211 
Sales of reserves in place(26)(49)(427)(147)
Production(1,047)(1,705)(20,403)(6,152)
As of December 31, 20237,057 16,215 194,433 55,677 
Revisions of previous estimates (2)(535)489 (14,754)(2,503)
Acquisitions of new reserves4,131 5,884 35,738 15,971 
Extensions and discoveries10 (6)(21)1 
Sales of reserves in place— — — — 
Production(918)(1,889)(19,488)(6,056)
As of December 31, 20249,745 20,693 195,908 63,090 
Revisions of previous estimates (2)(349)2,929 7,629 3,852 
Acquisitions of new reserves522 575 3,478 1,677 
Extensions and discoveries2,272 2,516 15,063 7,298 
Sales of reserves in place— — — — 
Production(1,214)(2,254)(19,802)(6,768)
As of December 31, 202510,976 24,460 202,276 69,148 
Proved developed reserves
As of December 31, 20228,421 25,433 242,822 74,324 
As of December 31, 20237,057 16,215 194,433 55,677 
As of December 31, 20247,863 18,499 183,647 56,970 
As of December 31, 20258,204 21,428 184,112 60,317
Proved undeveloped reserves
As of December 31, 2022— — — — 
As of December 31, 2023— — — — 
As of December 31, 20241,882 2,194 12,261 6,120 
As of December 31, 20252,771 3,032 18,164 8,831 
Totals may not sum or recalculate due to rounding
_________________

(1)    Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
(2)    Revisions include changes due to commodity prices, production costs, previous quantity estimates, and other commercial factors. Primary factor for revisions in years ended 2025, 2024 and 2023 were changes in SEC prices, among other factors. See Proved Reserves discussion in Part I, Item 1 of this Form 10-K for additional detail.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with ASC Topic 932, Extractive Activities—Oil and Gas, ("ASC Topic 932"). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows:
•the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions;
•pricing is applied based upon SEC prices at December 31, 2025, 2024 and 2023, adjusted for fixed or determinable contracts that are in existence at year-end.
The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:
 Year Ended December 31,
 202520242023
Oil (per Bbl)$64.15 $74.04 $76.65 
Natural gas (per Mcf)$2.07 $1.02 $1.62 
NGL (per Bbl)$17.13 $19.40 $21.53 
•future development and production costs are determined based on trailing 12 month average cost at year-end;
•the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
•a discount factor of 10% per year is applied annually to the future net cash flows.

The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).
Year Ended December 31,
202520242023
Future cash inflows from production$1,542,062 $1,322,371 $1,204,568 
Future production costs (1)(592,532)(584,452)(627,715)
Future development costs (2)(135,268)(108,821)(39,288)
Future income tax expenses (3)— — — 
Undiscounted future net cash flows814,262 629,098 537,565 
10% annual discount(374,694)(266,402)(241,272)
Standardized measure of discounted future net cash flows $439,568 $362,696 $296,293 
____________________

(1)    Consists of severance taxes, ad valorem taxes, and lease operating expenses.
(2)    Includes abandonment costs.
(3)    The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws, including expected tax benefits to be realized from the utilization of net operating loss carryforwards.
The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
Year Ended December 31,
202520242023
Beginning present value $362,696 $296,293 $806,865 
Changes during the year
Revenues less production(110,320)(78,497)(95,909)
Net changes in prices, production and other costs28,491 (43,115)(372,897)
Development costs incurred— — 645 
Net changes in future development costs (4,360)(6,991)(1,307)
Extensions and discoveries70,141 137 18,422 
Revisions of previous quantity estimates (1)25,851 (14,213)(171,758)
Previously estimated development costs incurred31,507 — — 
Accretion of discount36,270 29,629 81,066 
Net change in income taxes— — 3,798 
Purchases of reserves in-place22,463 168,590 14,450 
Sales of reserves in-place— — (1,394)
Timing differences and other (2)(23,171)10,863 14,312 
Net change for the year76,872 66,403 (510,572)
Ending present value (3) $439,568 $362,696 $296,293 
____________________

(1)     A significant portion of the revisions of previous quantity estimates is related to pricing, which affects well life and other economic factors. See Proved Reserves discussion.
(2)     The change in timing differences and other are related to revisions in the Company's estimated time of production and development.
(3)    Standardized Measure was determined using SEC prices, and does not reflect actual prices received or current market prices.
v3.25.4
Insider Trading Arrangements
 3 Months Ended
Dec. 31, 2025
Trading Arrangements, by Individual  
Rule 10b5-1 Arrangement Adopted false
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
v3.25.4
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.4
Cybersecurity Risk Management and Strategy Disclosure
 12 Months Ended
Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]  
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]
As SandRidge has increasingly relied on information technology ("IT") systems and networks in connection with our business activities, we recognize the critical importance of developing, implementing, and maintaining robust cybersecurity measures to safeguard our information systems and protect the confidentiality, integrity, and availability of our data.

SandRidge has strategically integrated cybersecurity risk management into our broader risk management framework to promote a company-wide culture of cybersecurity risk management. This integration ensures that cybersecurity considerations are an integral part of our decision-making processes at every level. Our management team works closely with IT professionals to continuously evaluate and address cybersecurity risks in alignment with our business objectives and operational needs. The underlying controls of our cybersecurity risk management are based on recognized best practices and standards for cybersecurity and information technology, including the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework (“CSF").

The following is a brief list of some of the cybersecurity risk management tools we employ to identify, assess and manage threat risks:
•Third party system and network scanning tools that identify or automatically block potential cybersecurity threats;
•Routine review and update of system access;
•Multi-factor authentication;
•Live 24-hour monitoring of corporate and field operations IT networks for cybersecurity threats;
•Mandatory annual employee cybersecurity awareness training program that includes phishing simulations and other microlearning courses;
•Monthly IT and cybersecurity meetings with management and IT professionals;
•Completion of annual IT network cybersecurity assessment and vulnerability scan;
•Segregation of our financial data records, that are stored on remote servers, separate and apart from our corporate office network with backups stored in different geographical regions in the United States.

Recognizing the complexity and evolving nature of cybersecurity threats, SandRidge engages with a range of external experts, including cybersecurity assessors, consultants, and auditors in evaluating and testing our risk management systems. These partnerships enable us to leverage specialized knowledge and insights, ensuring our cybersecurity strategies and processes focus on industry best practices. Our collaboration with these third parties includes regular audits, threat assessments, and consultation on security enhancements.

Because we are aware of the risks associated with relying on third-party service providers, to, among other things, estimate quantities of oil and natural gas reserves, analyze seismic and drilling information, process and record financial and operating data and communicate with employees and third parties, SandRidge implements stringent processes to oversee and manage these risks. We conduct thorough security assessments of all third-party providers before engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards. The monitoring includes assessments by our internal audit and IT professionals. This approach is designed to mitigate risks related to data breaches or other security incidents originating from third parties.
Incidents and Threats

We have in the past experienced, and expect to continue to confront, cybersecurity incidents and cybersecurity threats from hackers and other third parties. Although such prior incidents have not had a material adverse impact on our operations or financial performance, there can be no assurance that we will be successful in preventing cybersecurity incidents or successfully mitigating their effect on our Company. Any cybersecurity incident could have a material adverse effect on our reputation, competitive position, business, financial condition and results of operations.

Additionally, although out of our control, cybersecurity incidents affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery of our production to markets, which could, in turn, have a material adverse effect on our business, financial condition and results of operations.

For additional information regarding the risks we face from cybersecurity threats, please see the section entitled “Item 1A. Risk Factors—Cybersecurity incidents or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of our business operations.”
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block] SandRidge has strategically integrated cybersecurity risk management into our broader risk management framework to promote a company-wide culture of cybersecurity risk management. This integration ensures that cybersecurity considerations are an integral part of our decision-making processes at every level. Our management team works closely with IT professionals to continuously evaluate and address cybersecurity risks in alignment with our business objectives and operational needs. The underlying controls of our cybersecurity risk management are based on recognized best practices and standards for cybersecurity and information technology, including the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework (“CSF").
Cybersecurity Risk Management Third Party Engaged [Flag] true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag] false
Cybersecurity Risk Board of Directors Oversight [Text Block]
The Board is acutely aware of the critical nature of managing risks associated with cybersecurity threats. The Board has established robust oversight mechanisms to ensure effective governance in managing risks associated with cybersecurity threats because we recognize the significance of these threats to our operational integrity and stakeholder confidence.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]
The Audit Committee is central to the Board’s oversight of cybersecurity risks and bears the primary responsibility for this domain. The Audit Committee ensures effective oversight by reviewing reports on information security and cybersecurity from the Director of Internal Audit at least annually.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]
The Audit Committee is central to the Board’s oversight of cybersecurity risks and bears the primary responsibility for this domain. The Audit Committee ensures effective oversight by reviewing reports on information security and cybersecurity from the Director of Internal Audit at least annually.

Primary responsibility for assessing and integrating within enterprise risk management of our cybersecurity risks rests with our Director of Internal Audit, who oversees our governance programs, tests our compliance with standards, remediates known risks, and coordinates our employee training program. The Director of Internal Audit is a Certified Fraud Examiner with over 20 years of planning and managing information technology audits, including information technology general controls for the Sarbanes-Oxley Act ("SOX"), and cybersecurity breach protocols, policies and assessments.

The Director of Internal Audit, in their capacity, regularly informs the Chief Executive Officer (“CEO”), the Chair of the Audit Committee, and other members of management of aspects related to cybersecurity risks and incidents. This ensures that the appropriate levels of management are kept abreast of the cybersecurity posture and potential risks facing SandRidge. Furthermore, significant cybersecurity matters, and strategic risk management decisions are escalated to the Board, ensuring that they have comprehensive oversight and can provide guidance on critical cybersecurity issues.
Cybersecurity Risk Role of Management [Text Block]
The Audit Committee is central to the Board’s oversight of cybersecurity risks and bears the primary responsibility for this domain. The Audit Committee ensures effective oversight by reviewing reports on information security and cybersecurity from the Director of Internal Audit at least annually.

Primary responsibility for assessing and integrating within enterprise risk management of our cybersecurity risks rests with our Director of Internal Audit, who oversees our governance programs, tests our compliance with standards, remediates known risks, and coordinates our employee training program. The Director of Internal Audit is a Certified Fraud Examiner with over 20 years of planning and managing information technology audits, including information technology general controls for the Sarbanes-Oxley Act ("SOX"), and cybersecurity breach protocols, policies and assessments.

The Director of Internal Audit, in their capacity, regularly informs the Chief Executive Officer (“CEO”), the Chair of the Audit Committee, and other members of management of aspects related to cybersecurity risks and incidents. This ensures that the appropriate levels of management are kept abreast of the cybersecurity posture and potential risks facing SandRidge. Furthermore, significant cybersecurity matters, and strategic risk management decisions are escalated to the Board, ensuring that they have comprehensive oversight and can provide guidance on critical cybersecurity issues.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block] Primary responsibility for assessing and integrating within enterprise risk management of our cybersecurity risks rests with our Director of Internal Audit, who oversees our governance programs, tests our compliance with standards, remediates known risks, and coordinates our employee training program. The Director of Internal Audit is a Certified Fraud Examiner with over 20 years of planning and managing information technology audits, including information technology general controls for the Sarbanes-Oxley Act ("SOX"), and cybersecurity breach protocols, policies and assessments.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] The Director of Internal Audit is a Certified Fraud Examiner with over 20 years of planning and managing information technology audits, including information technology general controls for the Sarbanes-Oxley Act ("SOX"), and cybersecurity breach protocols, policies and assessments.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]
The Director of Internal Audit, in their capacity, regularly informs the Chief Executive Officer (“CEO”), the Chair of the Audit Committee, and other members of management of aspects related to cybersecurity risks and incidents. This ensures that the appropriate levels of management are kept abreast of the cybersecurity posture and potential risks facing SandRidge. Furthermore, significant cybersecurity matters, and strategic risk management decisions are escalated to the Board, ensuring that they have comprehensive oversight and can provide guidance on critical cybersecurity issues.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.4
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Nature of Business
Nature of Business. SandRidge Energy, Inc. is an oil and natural gas acquisition, development and production company headquartered in Oklahoma City, Oklahoma with a principal focus on developing and producing hydrocarbon resources in the United States.
Principles of Consolidation Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries, including its proportionate share of the Royalty Trusts. All intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and NGL reserves; impairment tests of long-lived assets; the carrying value of unproved oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; determinations of significant additions or alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to acquired or divested properties, as necessary; valuation allowances for deferred tax assets; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly from those estimates.
Going Concern Consideration
Going Concern Consideration. The accompanying consolidated financial statements are prepared in accordance with generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.
Cash and Cash Equivalents Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period. Additionally, the Company considers demand deposits or accounts that have the general characteristics of demand deposits where we may deposit additional funds at any time and also effectively withdraw funds at any time without prior notice or penalty to be cash equivalents.
Restricted Cash Restricted Cash. The Company maintains funds related to collateralized letters of credit and secured credit cards.
Accounts Receivable, Net
Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the drilling, completion, and production of oil and natural gas, which have a contractual maturity of one year or less. An allowance for expected credit losses has been established based on management’s review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 5 for further information on the Company’s accounts receivable and allowance for expected credit losses.
Fair Value of Financial Instruments
Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, restricted cash, prepaid expenses, receivables, and payables and accrued expenses. The carrying values of cash, restricted cash, trade receivables, trade payables and accrued expenses are considered to reflect fair values due to the short-term maturity of these instruments. See Note 4 for further discussion of the Company’s fair value measurements.
Fair Value of Non-financial Assets and Liabilities
Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances.
Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows, third-party offers or prices of comparable assets with consideration of current market conditions to fair value its non-financial assets and liabilities when necessary.
Derivative Financial Instruments
Derivative Financial Instruments. The Company enters into oil and natural gas derivative contracts to manage risks related to fluctuations in prices of its expected oil and natural gas production. The Company considers current and anticipated market conditions, planned capital expenditures, and any debt service requirements when determining whether to enter into oil and gas derivative contracts. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 6 for further discussion of the Company’s derivatives.
Other Assets
Other Assets. Other assets consist of capitalized operating leases and production equipment inventories not placed in service. See Note 7 for discussion of the Company’s leases. Production equipment inventories are stated at the lower of cost or net realizable value as of December 31, 2025, and 2024. The Company’s production equipment inventory primarily comprises oil and natural gas drilling or repair items such as tubing, casing and pumping units. Inventory expected to be placed in service within one year is reflected in other current assets on the accompanying consolidated balance sheets, while inventory expected to be place in service beyond one year is reflected in other assets on the accompanying consolidated balance sheets. For the year ended December 31, 2025, the Company recorded no impairment in other operating (income) expense on the accompanying consolidated statements of operations to reflect production equipment inventory at the lower of cost or net realizable value. For the year ended December 31, 2024, the Company recorded a $1.3 impairment in other operating (income) expense on the accompanying consolidated statements of operations to reflect production equipment inventory at the lower of cost or net realizable value. There were no inventory impairments recorded for the year ended December 31, 2023.
Oil and Natural Gas Operations
Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, development, and exploration activities and capitalized interest. The Company capitalized gross internal costs of $0.7 million, $0.2 million and $0.2 million during the years ended December 31, 2025, 2024 and 2023, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
Costs associated with unproved properties are excluded from the amortizable cost base until it has been determined that proved reserves exist or a lease is impaired. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and amortized. The costs associated with unproved properties are primarily the costs to acquire unproved acreage. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and whether the proved reserves can be developed economically. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes and electrical infrastructure costs may not exceed the ceiling limitation. A ceiling limitation calculation is performed at the end of each quarter. If the ceiling limitation is exceeded, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.

The ceiling limitation calculation is prepared using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If applicable, these prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation.

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center, unless it results in a greater than 10% change to the depletion rate.
Property, Plant and Equipment, Net
Property, Plant and Equipment, Net. Other capitalized costs, including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or fair value established on the Emergence Date less applicable depreciation. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 7 to 39 years for buildings and 1 to 27 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations.

Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that estimated future net operating cash flows directly related to the asset or asset group including disposal value is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value.
Capitalized Interest Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time.
Debt Issuance Costs Debt Issuance Costs. The Company includes unamortized debt issuance costs, if any, in other assets in the consolidated balance sheets. Other debt issuance costs related to long-term debt, if any, are presented in the balance sheets as a direct deduction from the associated debt liability, if material. Debt issuance costs are amortized to interest expense over the term of the related debt. When debt is retired, any unamortized costs, if material are written off and included in gain or loss on extinguishment of debt.
Asset Retirement Obligations Asset Retirement Obligations. The Company owns oil and natural gas assets that require expenditures to plug, abandon and remediate associated property at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded at the estimated present value at the time the wells are drilled or acquired, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the asset is sold and the liability is removed. Both the accretion and the depreciation are included in the consolidated statements of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 10 for further discussion of the Company’s asset retirement obligations.
Revenue Recognition and Natural Gas Balancing
Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable. Additionally, the Company deducts transportation costs from oil, natural gas and NGL revenues. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production, ad valorem and other taxes in the consolidated statements of operations. See Note 14 for further information on the Company's accounting policies related to revenues.

The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has not recorded a liability for natural gas imbalance positions as of December 31, 2025 or 2024. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.
Oil, natural gas and NGL revenues. A majority of the Company’s revenues come from sales of oil, natural gas and NGLs. In accordance with the contracts governing these sales, performance obligations to customers are satisfied and revenues are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck. As the Company’s customers obtain control of the production prior to selling it to other end customers, the Company presents its revenues on a net basis, rather than on a gross basis.

Pricing for the Company’s oil, natural gas and NGL contracts is variable and is based on volumes sold multiplied by either an index price, net of deductions, or a percentage of the sales price obtained by the customer, which is also based on index prices. The transaction price is allocated on a pro-rata basis to each unit of oil, natural gas or NGL sold based on the terms of the contract. Oil, natural gas and NGL revenues are also recorded net of royalties, discounts and allowances, and transportation costs, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from revenues and are included in production, ad valorem, and other taxes expense in the consolidated statements of operations.
Revenues Receivable. The Company records an asset in accounts receivable, net on its consolidated balance sheet for revenues receivable from contracts with customers at the end of each period. Pricing for revenues receivable is estimated using current month crude oil, natural gas and NGL prices, net of deductions. Revenues receivable on operated properties are typically collected the month after the Company delivers the related production to its purchaser.
Allocation of Share-Based Compensation
Allocation of Share-Based Compensation. Equity compensation provided to employees directly involved in exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses, production expenses, and other operating expense in the accompanying consolidated statements of operations.
Restructuring expenses
Restructuring expenses. Restructuring expenses represent fees and costs associated with our outsourcing and relocation of certain corporate specific functions that are of a non-recurring nature, expenses related to our predecessor company's 2016 bankruptcy, and our exit from North Park Basin in Colorado.
Income Taxes
Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.

The Company has elected an accounting policy in which interest and penalties on income taxes resulting from the underpayment or late payment of income taxes due to a taxing authority or relating to income tax contingencies are presented as a component of the income tax provision, rather than as interest expense.
Earnings per Share
Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and units, performance share units, warrants, and stock options using the treasury method.

Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the warrants were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 17 for the Company’s earnings per share calculation.
Commitments and Contingencies
Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Environmental liabilities related to future costs are recorded on an undiscounted basis when assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 11 for discussion of the Company’s commitments and contingencies.
Concentration of Risk
Concentration of Risk. We regularly maintain cash in excess of federally insured limits at financial institutions. Additionally, all of the Company’s commodity derivative transactions have been carried out in the over-the-counter market, which involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparty for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors the credit ratings of its commodity derivative counterparties on an ongoing basis and considers their credit default risk ratings in determining the fair value of its commodity derivative contracts. Historically, the Company’s commodity derivative contracts have been with multiple counterparties to minimize exposure to any individual counterparty.

The Company enters into master netting agreements with all of its commodity derivative counterparties, which allows the Company to net its commodity derivative assets and liabilities for like commodities and derivative instruments with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under commodity derivative transactions due to credit risk was limited to the net amounts due from the counterparties under the commodity derivative contracts.

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners are primarily independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.

Purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, large oil and natural gas companies and gas pipeline companies. The number of available purchasers and markets in the areas where we sell our production reduces the risk that the loss of a single downstream customer would materially affect our sales. We do not have any material commitments to deliver fixed and determinable quantities of oil and natural gas in the future under existing sales contracts or sales agreements.

The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):
Sales% of Revenue
As of December 31, 2025
Targa Pipeline Mid-Continent West OK LLC$50,896 32.6 %
Plains Marketing, L.P.$33,551 21.5 %
Valero Marketing and Supply Co$21,600 13.8 %
As of December 31, 2024
Plains Marketing, L.P.$50,465 40.3 %
Targa Pipeline Mid-Continent West OK LLC$46,248 36.9 %
As of December 31, 2023
Plains Marketing, L.P.$71,832 48.3 %
Targa Pipeline Mid-Continent West OK LLC$69,743 46.9 %
Recently Adopted Accounting Pronouncements and Recent Accounting Pronouncements Not Yet Adopted
Recently Adopted Accounting Pronouncements. The FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which require greater disaggregation of income tax disclosures. The amendments in this update improve the transparency of income tax disclosures by requiring (1) consistent categories and greater disaggregation of information in the rate reconciliation and (2) income taxes paid disaggregated by jurisdiction. This update improves the effectiveness and comparability of disclosures by requiring disaggregation by jurisdiction of disclosures of pretax income (or loss) and income tax expense (or benefit). This ASU was applied on a retrospective basis. The guidance in this update is effective for fiscal years beginning after December 15, 2024. The adoption of this ASU did not have an impact on our consolidated financial statements. See Note 12 for the Company's income tax disclosures.

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued Accounting Standards Update 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) (“ASU 2024-03”). The objective of ASU 2024-03 is to improve disclosures about a public entity's expenses, primarily through additional disaggregation of income statement expenses. The new standard is effective for annual periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted and may be applied either on a prospective or retrospective basis. The Company is currently evaluating the impact ASU 2024-03 will have on its consolidated financial statement disclosures and does not expect an impact to our consolidated financial statements.
v3.25.4
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Schedules of Concentration of Risk
The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):
Sales% of Revenue
As of December 31, 2025
Targa Pipeline Mid-Continent West OK LLC$50,896 32.6 %
Plains Marketing, L.P.$33,551 21.5 %
Valero Marketing and Supply Co$21,600 13.8 %
As of December 31, 2024
Plains Marketing, L.P.$50,465 40.3 %
Targa Pipeline Mid-Continent West OK LLC$46,248 36.9 %
As of December 31, 2023
Plains Marketing, L.P.$71,832 48.3 %
Targa Pipeline Mid-Continent West OK LLC$69,743 46.9 %
v3.25.4
Supplemental Cash Flow Information (Tables)
 12 Months Ended
Dec. 31, 2025
Supplemental Cash Flow Information [Abstract]  
Schedule of Supplemental Cash Flow Information
Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands):
 Year Ended December 31,
 202520242023
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized$(295)$(131)$(104)
Supplemental Disclosure of Noncash Investing and Financing Activities
Capital expenditures for property, plant and equipment in accounts payables and accrued expenses$11,554 $1,182 $919 
Non-cash acquisition purchase price adjustments$241 $8,819 $(651)
Right-of-use assets obtained in exchange for financing lease obligations$821 $790 $760 
Inventory material transfers to oil and natural gas properties$3 $141 $1,289 
Asset retirement obligation capitalized$57 $353 $113 
Asset retirement obligation removed due to divestiture$(357)$— $(1,413)
Asset retirement obligation revisions$29 $31 $(939)
Change in accrued excise tax on repurchases of common stock$(52)$— $— 
Change in dividends payable$2 $42 $(263)
v3.25.4
Acquisitions of Assets and Oil and Gas Properties (Tables)
 12 Months Ended
Dec. 31, 2025
Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]  
Schedule of Preliminary Allocation of Total Cost to the Assets Acquired and Liabilities Assumed
The following table represents the allocation of the total cost of the Cherokee Play Acquisition to the assets acquired and liabilities assumed after customary post-closing adjustments:

(in thousands)
Total Consideration
Cash paid$121,908 
Allocation of Total Consideration
Assets
Oil and natural gas properties$129,825 
Total Assets$129,825 
Liabilities(1)
Accounts payable and accrued expenses$7,917 
Total liabilities assumed7,917 
Net Assets Acquired and Liabilities Assumed$121,908 
____________________

(1)    Asset retirement obligations assumed were de minimis.
v3.25.4
Fair Value Measurements (Tables)
 12 Months Ended
Dec. 31, 2025
Fair Value Disclosures [Abstract]  
Schedule of Assets and Liabilities Measured on Recurring Basis
As of December 31, 2025, the following table summarizes the Company’s assets measured at fair value on a recurring basis by the fair value hierarchy (in thousands):

Fair Value MeasurementsNetting(1)Assets at Fair Value
Level 1Level 2Level 3
Assets
Commodity derivative contracts$— $3,130 $— $357 $2,773 
Total$— $3,130 $— $357 $2,773 
____________________

(1)Represents the impact of netting assets and liabilities with counterparties where the right of offset exists.

As of December 31, 2024, the following table summarizes the Company’s assets measured at fair value on a recurring basis by the fair value hierarchy (in thousands):
Fair Value MeasurementsNetting(1)Assets at Fair Value
Level 1Level 2Level 3
Assets
Commodity derivative contracts$— $830 $— $630 $200 
$— $830 $— $630 $200 
____________________

(1)Represents the impact of netting assets and liabilities with counterparties where the right of offset exists.
v3.25.4
Accounts Receivable (Tables)
 12 Months Ended
Dec. 31, 2025
Receivables [Abstract]  
Schedule of Accounts Receivable
A summary of accounts receivable is as follows (in thousands):
 December 31,
 20252024
Oil, natural gas and NGL sales$16,740 $15,320 
Joint interest billing11,138 9,957 
Other788 628 
Total accounts receivable28,666 25,905 
Less: allowance for expected credit losses(2,480)(2,027)
Total accounts receivable, net$26,186 $23,878 
Schedule of Allowance for Credit Loss
The following table represents the balance in the allowance for expected credit losses:

Year Ended December 31,
20252024
Beginning balance$(2,027)$(2,027)
Additional allowance(453)— 
Deductions (1)— — 
Ending balance$(2,480)$(2,027)
__________________
(1)Deductions represent collections of amounts for which an allowance had previously been established.
v3.25.4
Derivatives (Tables)
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Derivative Instruments, Gain (Loss)
The following table summarizes derivative activity (in thousands):
Year Ended December 31,
202520242023
(Gain) loss on derivative contracts$(7,763)$(748)$(1,447)
Realized settlement gains (losses) on derivative contracts$5,189 $548 $5,876 
Schedule of Offsetting Assets
The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative asset positions (in thousands):

As of December 31, 2025Gross AmountsGross Amounts OffsetAmounts Net of OffsetFinancial CollateralNet Amount
Assets
Derivative contracts - current
$3,130 $357 $2,773 $— $2,773 
Total$3,130 $357 $2,773 $— $2773 


At December 31, 2024Gross AmountsGross Amounts OffsetAmounts Net of OffsetFinancial CollateralNet Amount
Assets
Derivative contracts - current$744 $630 $114 $— $114 
Derivative contracts - non-current86 — 86 — 86 
Total$830 $630 $200 $— $200 
Schedule of Derivative Contracts These commodity derivative contracts consisted of the following:
PeriodIndexDaily Volume
Weighted Average Price
Oil (Bbl)
Fixed Price SwapsJanuary 2026 - June 2026NYMEX WTI300$68.67
Natural Gas (MMBtu)
Fixed Price SwapsJanuary 2026 - December 2026NYMEX Henry Hub11,797$4.16
Producer Costless CollarsJanuary 2026 - December 2026NYMEX Henry Hub4,500
$3.35 Put / $5.35 Call

As of December 31, 2024, the Company's open derivative contracts consisted of oil and NGL commodity derivative contracts under which we will receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume. These commodity derivative contracts consisted of the following:
PeriodIndexDaily VolumeWeighted Average Price
Oil (Bbl)
Fixed Price Swaps
January 2025 - December 2025NYMEX WTI500$71.60
January 2026 - June 2026NYMEX WTI300$68.67
NGL (Bbl)
Fixed Price SwapsJanuary 2025 - December 2025
Mont Belvieu OPIS (1)
300$39.69
(1) NGL swaps exclude ethane
Subsequent to December 31, 2025, the Company entered into the following natural gas derivative contracts:
PeriodType of Derivative InstrumentIndexDaily Volume (MMBtu)Weighted Average Price Per MMBtu
February 2026 - December 2026Fixed price swapsNYMEX Henry Hub3,750$4.20

Subsequent to December 31, 2025, the Company entered into the following oil derivative contracts:
PeriodType of Derivative InstrumentIndexDaily Volume (Bbl)Weighted Average Price Per Bbl
February 19, 2026 - December 2026Producer Costless CollarsNYMEX WTI816
$56.63 Put / $79.43 Call
March 2026 - December 2026Fixed price swapsNYMEX WTI275$70.00
Schedule of Fair Value of Derivative Contract
The following table presents the fair value of the Company’s derivative contracts on a net basis with same counterparty netting (in thousands):
Type of ContractBalance Sheet ClassificationDecember 31, 2025
Oil and natural gas price swaps and collarsCurrent assets - Derivative Contracts$2,773 
Total net derivative contracts$2,773 

Type of ContractBalance Sheet ClassificationDecember 31, 2024
Oil and NGL price swapsCurrent assets - Derivative Contracts$114 
Oil and NGL price swapsNon-current assets - Derivative Contracts86 
Total net derivative contracts$200 
v3.25.4
Leases (Table)
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Schedule of Components of Lease Costs
The components of lease costs recognized for the Company's right-of-use leases are shown below (in thousands):
Year Ended December 31,
202520242023
Short-term lease cost (1)$2,303 $1,815 $3,139 
Financing lease cost861 904 874 
Operating lease cost161 167 167 
Total lease cost$3,325 $2,886 $4,180 
___________________
(1)During the year ended December 31, 2025, there were $8.0 million in short-term lease costs capitalized associated with our drilling rig lease. During the years ended December 31, 2024, there were no short-term lease costs capitalized associated with drilling rig leases. During the year ended December 31, 2023, there were $1.6 million in short-term lease costs capitalized associated with our drilling rig lease. Portions of these costs were reimbursed to the Company by other working interest owners.
v3.25.4
Property, Plant and Equipment (Tables)
 12 Months Ended
Dec. 31, 2025
Property, Plant and Equipment [Abstract]  
Schedule of Property, Plant and Equipment
Property, plant and equipment consists of the following (in thousands):
December 31,
20252024
Oil and natural gas properties
Proved$1,759,943 $1,689,807 
Unproved27,520 23,504 
Total oil and natural gas properties1,787,463 1,713,311 
Less accumulated depreciation, depletion and impairment(1,446,824)(1,415,110)
Net oil and natural gas properties capitalized costs340,639 298,201 
Land200 200 
Electrical infrastructure122,380 121,818 
Non-oil and natural gas equipment1,626 1,634 
Buildings and structures3,603 3,603 
Financing leases1,345 1,286 
Total129,154 128,541 
Less accumulated depreciation and amortization(53,505)(47,852)
Other property, plant and equipment, net75,649 80,689 
Total property, plant and equipment, net$416,288 $378,890 
v3.25.4
Accounts Payable and Accrued Expenses (Tables)
 12 Months Ended
Dec. 31, 2025
Payables and Accruals [Abstract]  
Schedule of Accounts Payable and Accrued Expenses
Accounts payable and accrued expenses consist of the following (in thousands):
 December 31,
 20252024
Accounts payable and other accrued expenses$25,402 $19,502 
Production payable29,221 27,557 
Payroll and benefits3,211 2,912 
Taxes payable1,203 654 
Total accounts payable and accrued expenses$59,037 $50,625 
v3.25.4
Asset Retirement Obligations (Tables)
 12 Months Ended
Dec. 31, 2025
Asset Retirement Obligation Disclosure [Abstract]  
Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations
The following table presents the balance and activity of the Company’s asset retirement obligations (in thousands):
Year Ended December 31,
202520242023
Beginning balance$68,580 $64,404 $63,709 
Liability incurred upon acquiring and drilling wells57 353 113 
Revisions in estimated cash flows (1)29 31 (939)
Liability settled or disposed in current period (1,377)(889)(2,927)
Accretion (2)5,102 4,681 4,448 
Ending balance72,391 68,580 64,404 
Less: current portion8,098 9,131 9,851 
Asset retirement obligations, net of current$64,293 $59,449 $54,553 
____________________

(1)    Revisions for the year ended December 31, 2023 relate primarily to changes in working interest and estimated well lives.
(2)    Included on the Depreciation and depletion - oil and natural gas line item on the Consolidated Statements of Operations.
v3.25.4
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Schedule of (Benefit) Provision for Income Taxes
The Company’s income tax (benefit) provision consisted of the following components (in thousands):
Year Ended December 31,
202520242023
Current
Federal$— $— $— 
State— — — 
— — — 
Deferred
Federal(4,755)(19,370)12,002 
State(780)(2,862)1,958 
(5,535)(22,232)13,960 
Total (benefit) provision $(5,535)$(22,232)$13,960 
Schedule of Reconciliation of Provision (Benefit) for Income Taxes at Statutory Federal Tax Rate
A reconciliation of the (benefit) provision for income taxes at the statutory federal tax rate to the Company’s actual income tax (benefit) provision is as follows (in thousands):
Year Ended December 31, 2025Year Ended December 31, 2024Year Ended December 31, 2023
$ AmountPercent$ AmountPercent$ AmountPercent
Provision for income taxes at U.S. Federal statutory rate$13,580 21.0 %$8,559 21.0 %$15,712 21.0 %
State and local income taxes, net of federal benefit (1)(780)(1.2)%(2,862)(7.0)%1,958 2.6 %
Effect of changes in tax laws or rates enacted in the current period— — %— — %— — %
Changes in the valuation allowance(18,380)(28.4)%(27,930)(68.5)%(3,699)(4.9)%
Nontaxable or nondeductible items45 0.1 %1 — %(69)(0.1)%
Other adjustments— — %— — %58 0.1 %
Total$(5,535)(8.5)%$(22,232)(54.5)%$13,960 18.7%
____________________
(1) The state that contributes to the majority (greater than 50%) of the tax effect in this category is Oklahoma.
Schedule of Deferred Tax Assets and Liabilities
Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):
 Year Ended December 31,
20252024
Deferred tax liabilities
Investments (1)$— $— 
Derivative contracts— — 
Total deferred tax liabilities— — 
Deferred tax assets
Property, plant and equipment50,421 57,061 
Net operating loss carryforwards363,807 373,506 
Tax credits and other carryforwards33,851 33,851 
Asset retirement obligations13,091 13,327 
Investments (1)98 97 
Other1,935 1,454 
Total deferred tax assets463,203 479,296 
Valuation allowance(384,867)(406,495)
Net deferred tax asset$78,336 $72,801 
____________________
(1) Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts.
v3.25.4
Equity (Tables)
 12 Months Ended
Dec. 31, 2025
Equity [Abstract]  
Schedule of Treasury Stock Activity The following table shows the number of shares withheld for taxes and the associated value of those shares. These shares were accounted for as treasury stock when withheld, and then immediately retired (in thousands).
Year Ended December 31,
202520242023
Number of shares withheld for taxes25 29 59 
Value of shares withheld for taxes$290 $393 $929 
v3.25.4
Revenues (Tables)
 12 Months Ended
Dec. 31, 2025
Revenue from Contract with Customer [Abstract]  
Schedule of Disaggregation of Revenue
The following table disaggregates the Company’s revenue by source (in thousands):
Year Ended December 31,
202520242023
Oil $77,270 $68,231 $78,174 
Natural gas41,587 21,397 34,941 
NGL37,500 35,662 35,526 
Total revenues$156,357 $125,290 $148,641 
v3.25.4
Share Based Compensation (Tables)
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Schedule of Awards
The following table presents a summary of the Company’s unvested restricted stock awards:
Number of
Shares
Weighted-
Average Grant
Date Fair Value
(In thousands)
Unvested restricted stock awards outstanding at January 1, 202318$18.93 
Granted54$13.85 
Vested(18)$18.93 
Forfeited / Canceled—$— 
Unvested restricted stock awards outstanding at December 31, 202354$13.85 
Granted65$13.20 
Vested(65)$13.76 
Forfeited / Canceled—$— 
Unvested restricted stock awards outstanding at December 31, 202453$13.17 
Granted67$10.94 
Vested (1)(53)$13.17 
Forfeited / Canceled—$— 
Unvested restricted stock awards outstanding at December 31, 202567$10.94 
Totals may not sum or recalculate due to rounding
____________________

(1)     The aggregate intrinsic value of restricted stock that vested during 2025 was approximately $0.6 million based on the stock price at the time of vesting.
The following table presents a summary of the Company’s unvested restricted stock units:
Number of
Units
Weighted-
Average Grant
Date Fair Value
(In thousands)
Unvested restricted stock units outstanding at January 1, 2023252$5.93 
Granted79$15.13 
Vested(175)$4.33 
Forfeited / Canceled(18)$11.50 
Unvested restricted stock units outstanding at December 31, 2023138$12.51 
Granted96$13.14 
Vested(81)$10.85 
Forfeited / Canceled—$— 
Unvested restricted stock units outstanding at December 31, 2024153$13.78 
Granted109$11.48 
Vested (1)(61)$13.92 
Forfeited / Canceled—$— 
Unvested restricted stock units outstanding at December 31, 2025201$12.50 
Totals may not sum or recalculate due to rounding
____________________

(1)     The aggregate intrinsic value of restricted stock units that vested during 2025 was approximately $0.7 million based on the stock price at the time of vesting.
The following table presents a summary of the Company's performance share units:
Number of
Units
Weighted-
Average Grant
Date Fair Value
(In thousands)
Unvested performance share units outstanding at January 1, 202317$13.51 
Granted19$15.31 
Vested(17)$13.51 
Forfeited / Canceled(3)$15.31 
Unvested performance share units outstanding at December 31, 202316$15.31 
Granted23$13.63 
Vested(16)$15.31 
Forfeited / Canceled—$— 
Unvested performance share units outstanding at December 31, 202423$13.63 
Granted44$11.60 
Vested (1)(23)$13.63 
Forfeited / Canceled—$— 
Unvested performance share units outstanding at December 31, 202544$11.60 
Totals may not sum or recalculate due to rounding
____________________

(1)     The aggregate intrinsic value of performance share units that vested during 2025 was approximately $0.3 million.
Schedule of Weighted Average Assumptions
The fair value of stock options was estimated on the date of the grant using a Black-Scholes valuation model that used the weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s common stock and other factors. The Company uses historical data on the exercise of stock options, post-vesting forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant. Generally, stock options granted to employees and directors vest ratably over three years from the grant date and expire seven years from the date of grant. There were no stock options granted during the years ended December 31, 2025, 2024 or 2023.

AssumptionsYear Ended December 31, 2021
Risk-free interest rate0.79%
Expected dividend yield—%
Expected volatility78.2%
Expected term5 years
Schedule of Stock Option Activity The following table presents a summary of the Company's stock option activity:
Number of SharesWeighted Average Exercise Price per ShareWeighted Average Remaining Contractual Term(years)Aggregate Intrinsic Value (in millions)
(In thousands)
Outstanding at January 1, 2023286$— 7.64$2.38 
Granted—$— — $— 
Exercised(36)$15.68 — $— 
Expired—$— — $— 
Forfeited / Canceled—$— — $— 
Outstanding at December 31, 2023250$— 7.66$1.02 
Exercisable at December 31, 2023100$— 7.66$0.41 
Outstanding at December 31, 2023250$— 7.66$1.02 
Granted—$— — $— 
Exercised—$— — $— 
Expired—$— — $— 
Forfeited / Canceled—$— — $— 
Outstanding at December 31, 2024250$— 6.65$0.53 
Exercisable at December 31, 2024150$— 6.65$0.32 
Outstanding at December 31, 2024250$— 6.65$0.53 
Granted—$— — $— 
Exercised—$— — $— 
Expired—$— — $— 
Forfeited / Canceled—$— — $— 
Outstanding at December 31, 2025250$— 5.65$1.21 
Exercisable at December 31, 2025200$— 5.65$0.97 
Totals may not sum or recalculate due to rounding
____________________

(1)     All outstanding stock options as of December 31, 2025 are expected to vest.
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan
The following tables summarize the Company's share and incentive-based compensation (in thousands):
Recurring Compensation Expense (1)
Year Ended December 31, 2025
Equity-classified awards:
Restricted stock awards and units$1,909 
Performance share units535 
Stock options300 
Total share-based compensation expense$2,744 
Year Ended December 31, 2024
Equity-classified awards:
Restricted stock awards and units$1,790 
Performance share units264 
Stock options300 
Total share-based compensation expense$2,354 
Year Ended December 31, 2023
Equity-classified awards:
Restricted stock awards and units$1,415 
Performance share units229 
Stock options301 
Total share-based compensation expense$1,945 
____________________

(1)Included in general and administrative expense in the accompanying consolidated statements of operations.
v3.25.4
Earnings per Share (Tables)
 12 Months Ended
Dec. 31, 2025
Earnings Per Share [Abstract]  
Schedule of Earnings (Loss) per Share
The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings (loss) per share:
Net Income (loss)
Weighted Average SharesEarnings (Loss) Per Share
(In thousands, except per share amounts)
Year Ended December 31, 2025
Basic earnings per share$70,203 36,773 $1.91
Effect of dilutive securities
Restricted stock awards (1)— 29 
Restricted share units (1)— 63 
Performance share units (1)— 31 
Stock options (1)— 12 
Diluted earnings per share$70,203 36,908 $1.90
Year Ended December 31, 2024
Basic earnings per share$62,986 37,106 $1.70
Effect of dilutive securities
Restricted stock awards (1)— 28 
Restricted share units (1)— 32 
Performance share units (1)— 11 
Stock options (1)— 11 
Diluted earnings per share$62,986 37,188 $1.69
Year Ended December 31, 2023
Basic earnings per share$60,857 36,939 $1.65
Effect of dilutive securities
Restricted stock awards (1)— 19 
Restricted share units (1)— 120 
Performance share units (1)— 13 
Stock options (1)— 43 
Diluted earnings per share$60,857 37,134 $1.64
____________________

(1)The incremental shares of potentially dilutive restricted stock awards, restricted stock units, performance share units and stock options were included as their effect was dilutive under the treasury stock method..
v3.25.4
Segment Reporting (Tables)
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Schedule of Segment Reporting Information
The following table presents selected financial information with respect to the Company’s single operating segment (in thousands):
 Year Ended December 31,
 202520242023
Revenues
Oil$77,270 $68,231 $78,174 
Natural gas41,587 21,397 34,941 
NGL37,500 35,662 35,526 
Total revenues156,357 125,290 148,641 
Expenses
Lease operating expenses36,191 40,012 41,862 
Production, ad valorem, and other taxes9,846 6,780 10,870 
Depreciation and depletion—oil and natural gas36,439 25,976 15,657 
Depreciation and amortization—other6,433 6,503 6,518 
General and administrative13,201 11,695 10,735 
Restructuring expenses1,060 474 406 
Employee termination benefits— — 19 
(Gain) loss on derivative contracts(7,763)(748)(1,447)
Other operating (income) expense— 1,372 (157)
Total expenses95,407 92,064 84,463 
Income (loss) from operations60,950 33,226 64,178 
Other income (expense)
Interest income (expense), net3,687 7,744 10,552 
Other income (expense), net31 (216)87 
Total other income (expense)3,718 7,528 10,639 
Income (loss) before income taxes64,668 40,754 74,817 
Income tax (benefit)(5,535)(22,232)13,960 
Net income (loss)$70,203 $62,986 $60,857 
Capital expenditures, including acquisitions$77,500 $156,472 $33,664 
v3.25.4
Subsequent Events (Tables)
 12 Months Ended
Dec. 31, 2025
Subsequent Events [Abstract]  
Schedule of Natural Gas Derivative Swap These commodity derivative contracts consisted of the following:
PeriodIndexDaily Volume
Weighted Average Price
Oil (Bbl)
Fixed Price SwapsJanuary 2026 - June 2026NYMEX WTI300$68.67
Natural Gas (MMBtu)
Fixed Price SwapsJanuary 2026 - December 2026NYMEX Henry Hub11,797$4.16
Producer Costless CollarsJanuary 2026 - December 2026NYMEX Henry Hub4,500
$3.35 Put / $5.35 Call

As of December 31, 2024, the Company's open derivative contracts consisted of oil and NGL commodity derivative contracts under which we will receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume. These commodity derivative contracts consisted of the following:
PeriodIndexDaily VolumeWeighted Average Price
Oil (Bbl)
Fixed Price Swaps
January 2025 - December 2025NYMEX WTI500$71.60
January 2026 - June 2026NYMEX WTI300$68.67
NGL (Bbl)
Fixed Price SwapsJanuary 2025 - December 2025
Mont Belvieu OPIS (1)
300$39.69
(1) NGL swaps exclude ethane
Subsequent to December 31, 2025, the Company entered into the following natural gas derivative contracts:
PeriodType of Derivative InstrumentIndexDaily Volume (MMBtu)Weighted Average Price Per MMBtu
February 2026 - December 2026Fixed price swapsNYMEX Henry Hub3,750$4.20

Subsequent to December 31, 2025, the Company entered into the following oil derivative contracts:
PeriodType of Derivative InstrumentIndexDaily Volume (Bbl)Weighted Average Price Per Bbl
February 19, 2026 - December 2026Producer Costless CollarsNYMEX WTI816
$56.63 Put / $79.43 Call
March 2026 - December 2026Fixed price swapsNYMEX WTI275$70.00
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2025
Extractive Industries [Abstract]  
Schedule of Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities
The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):
 December 31,
 20252024
Oil and natural gas properties
Proved$1,759,943 $1,689,807 
Unproved27,520 23,504 
Total oil and natural gas properties1,787,463 1,713,311 
Less accumulated depreciation, depletion and impairment(1,446,824)(1,415,110)
Net oil and natural gas properties capitalized costs$340,639 $298,201 
Schedule of Cost Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development
Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):
Year Ended December 31,
202520242023
Acquisitions of properties
Proved$2,331 $126,998 $11,232 
Unproved6,183 2,666 — 
Exploration(1)
5,016 11,246 (46)
Development63,970 15,562 22,478 
Total cost incurred$77,500 $156,472 $33,664 
____________________

(1)    Includes land, geological, geophysical and leasehold costs.
Schedule of Costs Excluded from Amortization
The following table summarizes the costs, by year incurred, related to unproved properties, which were excluded from oil and natural gas properties subject to amortization at December 31, 2025 (in thousands):

Year Ended December 31,
Total2025202420232022 and Prior
Acquisition, exploration, and other unproved property costs$26,636 $10,589 $4,298 $(270)$12,019 
Capitalized interest884 — — 884 
Total costs incurred(1)
$27,520 $10,589 $4,298 $(270)$12,903 
____________________
(1)    Includes application of fresh start accounting in 2016 and reflects remaining balance at December 31, 2025.
Schedule of Results of Operations for Oil, Natural Gas and NGL Producing Activities
The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the impact the Company’s operations have on actual net earnings.
Year Ended December 31,
202520242023
Revenues$156,357 $125,290 $148,641 
Expenses
Production costs46,629 46,832 53,099 
Depreciation and depletion36,439 25,976 15,657 
Total expenses83,068 72,808 68,756 
Income (loss) before income taxes73,289 52,482 79,885 
Income tax expense (benefit) (1)17,775 12,728 19,374 
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)$55,514 $39,754 $60,511 
____________________

(1)    Income tax (benefit) expense is hypothetical and is calculated by applying the Company’s statutory tax rate to income (loss) before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits.
Schedule of Changes in Estimated Oil, Natural Gas and NGL Reserves
The summary below presents changes in the Company’s estimated reserves.
OilNGLNatural GasTotal
 (MBbls)(MBbls)(MMcf) (1)MBoe
Proved developed and undeveloped reserves
As of December 31, 20228,421 25,433 242,822 74,324 
Revisions of previous estimates (2)(1,027)(8,200)(36,464)(15,304)
Acquisitions of new reserves453 379 5,474 1,745 
Extensions and discoveries283 357 3,431 1,211 
Sales of reserves in place(26)(49)(427)(147)
Production(1,047)(1,705)(20,403)(6,152)
As of December 31, 20237,057 16,215 194,433 55,677 
Revisions of previous estimates (2)(535)489 (14,754)(2,503)
Acquisitions of new reserves4,131 5,884 35,738 15,971 
Extensions and discoveries10 (6)(21)1 
Sales of reserves in place— — — — 
Production(918)(1,889)(19,488)(6,056)
As of December 31, 20249,745 20,693 195,908 63,090 
Revisions of previous estimates (2)(349)2,929 7,629 3,852 
Acquisitions of new reserves522 575 3,478 1,677 
Extensions and discoveries2,272 2,516 15,063 7,298 
Sales of reserves in place— — — — 
Production(1,214)(2,254)(19,802)(6,768)
As of December 31, 202510,976 24,460 202,276 69,148 
Proved developed reserves
As of December 31, 20228,421 25,433 242,822 74,324 
As of December 31, 20237,057 16,215 194,433 55,677 
As of December 31, 20247,863 18,499 183,647 56,970 
As of December 31, 20258,204 21,428 184,112 60,317
Proved undeveloped reserves
As of December 31, 2022— — — — 
As of December 31, 2023— — — — 
As of December 31, 20241,882 2,194 12,261 6,120 
As of December 31, 20252,771 3,032 18,164 8,831 
Totals may not sum or recalculate due to rounding
_________________

(1)    Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
(2)    Revisions include changes due to commodity prices, production costs, previous quantity estimates, and other commercial factors. Primary factor for revisions in years ended 2025, 2024 and 2023 were changes in SEC prices, among other factors. See Proved Reserves discussion in Part I, Item 1 of this Form 10-K for additional detail.
Schedule of Calculation of Weighted Average Per Unit Prices
The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:
 Year Ended December 31,
 202520242023
Oil (per Bbl)$64.15 $74.04 $76.65 
Natural gas (per Mcf)$2.07 $1.02 $1.62 
NGL (per Bbl)$17.13 $19.40 $21.53 
Schedule of Standardized Measure of Discounted Future Cash Flows
The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).
Year Ended December 31,
202520242023
Future cash inflows from production$1,542,062 $1,322,371 $1,204,568 
Future production costs (1)(592,532)(584,452)(627,715)
Future development costs (2)(135,268)(108,821)(39,288)
Future income tax expenses (3)— — — 
Undiscounted future net cash flows814,262 629,098 537,565 
10% annual discount(374,694)(266,402)(241,272)
Standardized measure of discounted future net cash flows $439,568 $362,696 $296,293 
____________________

(1)    Consists of severance taxes, ad valorem taxes, and lease operating expenses.
(2)    Includes abandonment costs.
(3)    The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws, including expected tax benefits to be realized from the utilization of net operating loss carryforwards.
Schedule of Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
Year Ended December 31,
202520242023
Beginning present value $362,696 $296,293 $806,865 
Changes during the year
Revenues less production(110,320)(78,497)(95,909)
Net changes in prices, production and other costs28,491 (43,115)(372,897)
Development costs incurred— — 645 
Net changes in future development costs (4,360)(6,991)(1,307)
Extensions and discoveries70,141 137 18,422 
Revisions of previous quantity estimates (1)25,851 (14,213)(171,758)
Previously estimated development costs incurred31,507 — — 
Accretion of discount36,270 29,629 81,066 
Net change in income taxes— — 3,798 
Purchases of reserves in-place22,463 168,590 14,450 
Sales of reserves in-place— — (1,394)
Timing differences and other (2)(23,171)10,863 14,312 
Net change for the year76,872 66,403 (510,572)
Ending present value (3) $439,568 $362,696 $296,293 
____________________

(1)     A significant portion of the revisions of previous quantity estimates is related to pricing, which affects well life and other economic factors. See Proved Reserves discussion.
(2)     The change in timing differences and other are related to revisions in the Company's estimated time of production and development.
(3)    Standardized Measure was determined using SEC prices, and does not reflect actual prices received or current market prices.
v3.25.4
Summary of Significant Accounting Policies - Narrative (Details) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Dec. 31, 2025
Jun. 30, 2025
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Significant Accounting Policies [Line Items]          
Cash and cash equivalents $ 110,998   $ 110,998 $ 98,128 $ 252,400
Restricted cash $ 1,347   1,347 1,383 1,500
Impairments on production equipment inventory     0 1,300 0
Capitalized costs     $ 77,500 156,472 33,664
Maximum reserves sold from cost center not expected to result in significant alteration (less than) 25.00%   25.00%    
Percentage depletion rate of reserves (greater than) 0.10   0.10    
Interest capitalized during period     $ 0 0  
Natural gas balancing liability $ 0   0 0  
Operating lease, expense, adjustment $ 3,000 $ 2,100 5,100    
Internal Costs          
Significant Accounting Policies [Line Items]          
Capitalized costs     $ 700 $ 200 $ 200
Buildings and structures | Minimum          
Significant Accounting Policies [Line Items]          
Property, plant and equipment, useful life 7 years   7 years    
Buildings and structures | Maximum          
Significant Accounting Policies [Line Items]          
Property, plant and equipment, useful life 39 years   39 years    
Equipment | Minimum          
Significant Accounting Policies [Line Items]          
Property, plant and equipment, useful life 1 year   1 year    
Equipment | Maximum          
Significant Accounting Policies [Line Items]          
Property, plant and equipment, useful life 27 years   27 years    
v3.25.4
Summary of Significant Accounting Policies - Schedules of Concentration Risk (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Concentration Risk [Line Items]      
Sales $ 156,357 $ 125,290 $ 148,641
Targa Pipeline Mid-Continent West OK LLC      
Concentration Risk [Line Items]      
Sales $ 50,896 $ 46,248 $ 69,743
Targa Pipeline Mid-Continent West OK LLC | Revenue Benchmark | Customer Concentration Risk      
Concentration Risk [Line Items]      
% of Revenue 32.60% 36.90% 46.90%
Plains Marketing, L.P.      
Concentration Risk [Line Items]      
Sales $ 33,551 $ 50,465 $ 71,832
Plains Marketing, L.P. | Revenue Benchmark | Customer Concentration Risk      
Concentration Risk [Line Items]      
% of Revenue 21.50% 40.30% 48.30%
Valero Marketing and Supply Co      
Concentration Risk [Line Items]      
Sales $ 21,600    
Valero Marketing and Supply Co | Revenue Benchmark | Customer Concentration Risk      
Concentration Risk [Line Items]      
% of Revenue 13.80%    
v3.25.4
Supplemental Cash Flow Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Supplemental Disclosure of Cash Flow Information      
Cash paid for interest, net of amounts capitalized $ (295) $ (131) $ (104)
Supplemental Disclosure of Noncash Investing and Financing Activities      
Capital expenditures for property, plant and equipment in accounts payables and accrued expenses 11,554 1,182 919
Non-cash acquisition purchase price adjustments 241 8,819 (651)
Right-of-use assets obtained in exchange for financing lease obligations 821 790 760
Inventory material transfers to oil and natural gas properties 3 141 1,289
Asset retirement obligation capitalized 57 353 113
Asset retirement obligation removed due to divestiture (357) 0 (1,413)
Asset retirement obligation revisions 29 31 (939)
Change in accrued excise tax on repurchases of common stock (52) 0 0
Change in dividends payable $ 2 $ 42 $ (263)
v3.25.4
Acquisitions of Assets and Oil and Gas Properties - Schedule of Preliminary Allocation of Total Cost to the Assets Acquired and Liabilities Assumed (Details) - Cherokee play of the Western Anadarko Basin
$ in Thousands
Aug. 30, 2024
USD ($)
Total Consideration  
Cash paid $ 121,908
Assets  
Oil and natural gas properties 129,825
Total Assets 129,825
Liabilities  
Accounts payable and accrued expenses 7,917
Total liabilities assumed 7,917
Net Assets Acquired and Liabilities Assumed $ 121,908
v3.25.4
Acquisitions of Assets and Oil and Gas Properties - Narrative (Details)
$ in Millions
Dec. 13, 2024
USD ($)
Jun. 13, 2024
USD ($)
well
Jul. 11, 2023
USD ($)
well
Cherokee Play      
Asset Acquisition [Line Items]      
Gross purchase price | $ $ 5.2 $ 2.1  
Number of producing wells   29  
Number of saltwater disposal wells   5  
Northwest Stack Play      
Asset Acquisition [Line Items]      
Gross purchase price | $     $ 10.6
Number of producing wells     26
v3.25.4
Fair Value Measurements - Schedule of Assets and Liabilities Measured on Recurring Basis (Details) - Commodity derivative contracts - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]    
Assets at Fair Value $ 2,773 $ 200
Level 1    
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]    
Assets at Fair Value 0 0
Level 2    
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]    
Assets at Fair Value 3,130 830
Level 3    
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]    
Assets at Fair Value 0 0
Netting    
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]    
Assets at Fair Value $ 357 $ 630
v3.25.4
Accounts Receivable - Schedule of Accounts Receivable (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Receivables [Abstract]      
Oil, natural gas and NGL sales $ 16,740 $ 15,320  
Joint interest billing 11,138 9,957  
Other 788 628  
Total accounts receivable 28,666 25,905  
Less: allowance for expected credit losses (2,480) (2,027) $ (2,027)
Total accounts receivable, net $ 26,186 $ 23,878  
v3.25.4
Accounts Receivable - Schedule of Allowance for Expected Credit Loss (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Allowance for Doubtful Accounts Receivable [Roll Forward]    
Beginning balance $ (2,027) $ (2,027)
Additional allowance (453) 0
Deductions 0 0
Ending balance $ (2,480) $ (2,027)
v3.25.4
Derivatives - Schedule of Derivative Instruments, Gain (Loss) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
(Gain) loss on derivative contracts $ (7,763) $ (748) $ (1,447)
Realized settlement gains (losses) on derivative contracts 5,189 548 5,876
Commodity Derivatives      
Derivative Instruments and Hedging Activities Disclosures [Line Items]      
(Gain) loss on derivative contracts (7,763) (748) (1,447)
Realized settlement gains (losses) on derivative contracts $ 5,189 $ 548 $ 5,876
v3.25.4
Derivatives - Narrative (Details)
Dec. 31, 2025
institution
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Number of counterparties to open derivative contracts 1
v3.25.4
Derivatives - Schedule of Offsetting Assets (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure    
Gross Amounts $ 3,130 $ 830
Gross Amounts Offset 357 630
Amounts Net of Offset 2,773 200
Financial Collateral 0 0
Net Amount 2,773 200
Derivative contracts - current    
Derivative Instruments and Hedging Activities Disclosure    
Gross Amounts 3,130 744
Gross Amounts Offset 357 630
Amounts Net of Offset 2,773 114
Financial Collateral 0 0
Net Amount $ 2,773 114
Derivative contracts - non-current    
Derivative Instruments and Hedging Activities Disclosure    
Gross Amounts   86
Gross Amounts Offset   0
Amounts Net of Offset   86
Financial Collateral   0
Net Amount   $ 86
v3.25.4
Derivatives - Schedule of Derivative Contracts (Details) - Designated as Hedging Instrument
 12 Months Ended
Dec. 31, 2025
MMBTU
$ / MMBTU
$ / bbl
bbl
Dec. 31, 2024
$ / bbl
bbl
Oil Swaps January 2026 To June 2026    
Business Combination [Line Items]    
Daily Volume (in barrels) | bbl 300 300
Weighted average fixed price per unit (in dollars per unit) | $ / bbl 68.67 68.67
Natural Gas Swaps January 2026 To December 2026    
Business Combination [Line Items]    
Daily Volume (in million barrels) | MMBTU 11,797  
Weighted average fixed price per unit (in dollars per unit) | $ / MMBTU 4.16  
Natural Gas Collars January 2026 To December 2026    
Business Combination [Line Items]    
Daily Volume (in million barrels) | MMBTU 4,500  
Natural Gas Collars January 2026 To December 2026 | Short    
Business Combination [Line Items]    
Weighted average fixed price per unit (in dollars per unit) | $ / MMBTU 3.35  
Natural Gas Collars January 2026 To December 2026 | Long    
Business Combination [Line Items]    
Weighted average fixed price per unit (in dollars per unit) | $ / MMBTU 5.35  
Oil Swaps January 2025 To December 2025    
Business Combination [Line Items]    
Daily Volume (in barrels) | bbl   500
Weighted average fixed price per unit (in dollars per unit) | $ / bbl   71.60
Natural Gas Liquid Swaps January 2025 To December 2025    
Business Combination [Line Items]    
Daily Volume (in barrels) | bbl   300
Weighted average fixed price per unit (in dollars per unit) | $ / bbl   39.69
v3.25.4
Derivatives - Schedule of Fair Value of Derivative Contract (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative contract $ 2,773 $ 200
Derivative contracts - current    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative contract $ 2,773 114
Derivative contracts - non-current    
Derivative Instruments and Hedging Activities Disclosures [Line Items]    
Derivative contract   $ 86
v3.25.4
Leases - Schedule of Components of Lease Costs (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Leases [Abstract]      
Short-term lease cost $ 2,303 $ 1,815 $ 3,139
Financing lease cost 861 904 874
Operating lease cost 161 167 167
Total lease cost 3,325 2,886 4,180
Short-term lease, cost, capitalized $ 8,000 $ 0 $ 1,600
v3.25.4
Leases - Narrative (Details)
Dec. 31, 2025
Leases [Abstract]  
Finance lease, weighted average remaining lease term 2 years 2 months 12 days
Finance lease, weighted average discount rate 7.69%
Operating lease, weighted average remaining lease term 1 year
Operating lease, weighted average discount rate 7.38%
v3.25.4
Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Oil and natural gas properties    
Proved $ 1,759,943 $ 1,689,807
Unproved 27,520 23,504
Total oil and natural gas properties 1,787,463 1,713,311
Less: accumulated depreciation, depletion and impairment (1,446,824) (1,415,110)
Net oil and natural gas properties capitalized costs 340,639 298,201
Property, Plant and Equipment, Net    
Financing leases 1,345 1,286
Total 129,154 128,541
Less accumulated depreciation and amortization (53,505) (47,852)
Other property, plant and equipment, net 75,649 80,689
Total property, plant and equipment, net 416,288 378,890
Land    
Property, Plant and Equipment, Net    
Property, plant and equipment, gross 200 200
Electrical infrastructure    
Property, Plant and Equipment, Net    
Property, plant and equipment, gross 122,380 121,818
Non-oil and natural gas equipment    
Property, Plant and Equipment, Net    
Property, plant and equipment, gross 1,626 1,634
Buildings and structures    
Property, Plant and Equipment, Net    
Property, plant and equipment, gross $ 3,603 $ 3,603
v3.25.4
Property, Plant and Equipment - Narrative (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
$ / Boe
Dec. 31, 2024
USD ($)
$ / Boe
Dec. 31, 2023
$ / Boe
Property, Plant and Equipment [Line Items]      
Average depreciation and depletion rate (usd per Boe) | $ / Boe 4.63 3.52 1.82
Unproved | $ $ 27,520 $ 23,504  
Minimum      
Property, Plant and Equipment [Line Items]      
Expect completion of evaluation activities on majority of unproved properties, without existing production 3 years    
Maximum      
Property, Plant and Equipment [Line Items]      
Expect completion of evaluation activities on majority of unproved properties, without existing production 5 years    
v3.25.4
Accounts Payable and Accrued Expenses (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Payables and Accruals [Abstract]    
Accounts payable and other accrued expenses $ 25,402 $ 19,502
Production payable 29,221 27,557
Payroll and benefits 3,211 2,912
Taxes payable 1,203 654
Total accounts payable and accrued expenses $ 59,037 $ 50,625
v3.25.4
Asset Retirement Obligations - Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis      
Beginning balance $ 68,580 $ 64,404 $ 63,709
Liability incurred upon acquiring and drilling wells 57 353 113
Revisions in estimated cash flows 29 31 (939)
Liability settled or disposed in current period (1,377) (889) (2,927)
Accretion 5,102 4,681 4,448
Ending balance 72,391 68,580 64,404
Less: current portion 8,098 9,131 9,851
Asset retirement obligations, net of current $ 64,293 $ 59,449 $ 54,553
v3.25.4
Commitments and Contingencies (Details) - SandRidge Mississippian Trust I - Pending Litigation
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
individual
Loss Contingencies [Line Items]  
Number of defendants | individual 2
Loss contingency, estimate of possible loss | $ $ 17.0
v3.25.4
Income Taxes - Schedule of (Benefit) Provision for Income Taxes (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Current      
Federal $ 0 $ 0 $ 0
State 0 0 0
Current, total 0 0 0
Deferred      
Federal (4,755) (19,370) 12,002
State (780) (2,862) 1,958
Deferred, total (5,535) (22,232) 13,960
Total $ (5,535) $ (22,232) $ 13,960
v3.25.4
Income Taxes - Schedule of Reconciliation of Provision (Benefit) for Income Taxes at Statutory Federal Tax Rate (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Amount      
Provision for income taxes at U.S. Federal statutory rate $ 13,580 $ 8,559 $ 15,712
State and local income taxes, net of federal benefit (780) (2,862) 1,958
Effect of changes in tax laws or rates enacted in the current period 0 0 0
Changes in the valuation allowance (18,380) (27,930) (3,699)
Nontaxable or nondeductible items 45 1 (69)
Other adjustments 0 0 58
Total $ (5,535) $ (22,232) $ 13,960
Percent      
Provision for income taxes at U.S. Federal statutory rate 21.00% 21.00% 21.00%
State and local income taxes, net of federal benefit (1.20%) (7.00%) 2.60%
Effect of changes in tax laws or rates enacted in the current period 0.00% 0.00% 0.00%
Changes in the valuation allowance (28.40%) (68.50%) (4.90%)
Nontaxable or nondeductible items 0.10% 0.00% (0.10%)
Other adjustments 0.00% 0.00% 0.10%
Total (8.50%) (54.50%) 18.70%
v3.25.4
Income Taxes - Narrative (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Operating Loss Carryforwards [Line Items]    
Valuation allowance, deferred tax asset, increase (decrease) $ (78,300) $ (72,800)
Deferred federal and state tax expense 5,500  
Deferred tax assets, net of valuation allowance 78,336 $ 72,801
States operating loss carryforwards $ 199,000  
Minimum    
Operating Loss Carryforwards [Line Items]    
Number of tax years open for state tax audit (in years) 3 years  
Maximum    
Operating Loss Carryforwards [Line Items]    
Number of tax years open for state tax audit (in years) 5 years  
Domestic Tax Jurisdiction    
Operating Loss Carryforwards [Line Items]    
Federal net operating loss carryovers $ 1,600,000  
Operating loss carryforwards, subject to expiration 700,000  
Operating loss carryforwards, not subject to expiration 900,000  
Tax credits, not subject to expiration 33,500  
State and Local Jurisdiction    
Operating Loss Carryforwards [Line Items]    
Federal net operating loss carryovers 1,000,000  
Operating loss carryforwards, subject to expiration 176,000  
Operating loss carryforwards, not subject to expiration $ 645,000  
v3.25.4
Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Deferred tax liabilities    
Investments $ 0 $ 0
Derivative contracts 0 0
Total deferred tax liabilities 0 0
Deferred tax assets    
Property, plant and equipment 50,421 57,061
Net operating loss carryforwards 363,807 373,506
Tax credits and other carryforwards 33,851 33,851
Asset retirement obligations 13,091 13,327
Investments 98 97
Other 1,935 1,454
Total deferred tax assets 463,203 479,296
Valuation allowance (384,867) (406,495)
Net deferred tax asset $ 78,336 $ 72,801
v3.25.4
Equity - Narrative (Details)
$ / shares in Units, $ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
shareholder
$ / shares
shares
Dec. 31, 2024
USD ($)
$ / shares
shares
Dec. 31, 2023
USD ($)
shares
Aug. 05, 2025
May 31, 2023
USD ($)
Dec. 31, 2022
shares
Aug. 16, 2021
USD ($)
Jul. 01, 2020
$ / shares
shares
Class of Stock [Line Items]                
Number of shares authorized (in shares) 300,000,000              
Common stock, authorized (in shares) 250,000,000 250,000,000            
Common stock, par value (in dollars per share) | $ / shares $ 0.001 $ 0.001            
Preferred stock, authorized (in shares) 50,000,000              
Preferred stock, par value (in dollars per share) | $ / shares $ 0.001 $ 0.001            
Common stock, issued (in shares) 36,825,000 37,203,000            
Common stock, outstanding (in shares) 36,825,000 37,203,000            
Unvested options outstanding (in shares) 100,000 100,000            
Stock repurchase program, authorized amount | $         $ 75,000   $ 25,000  
Repurchases of common stock (in shares) 595,635 21,308            
Repurchases of common stock | $ $ 6,400 $ 233            
Common stock, shares, outstanding, minimal beneficial ownership trigger for dividend waiver       4.90%        
Dividends paid to stockholders | $ $ 15,864 72,336 $ 81,515          
Cash dividends on vested stock awards | $   $ 500            
Tax benefits preservation plan, ownership threshold, beneficial ownership threshold, number of shareholders | shareholder 1              
Tax benefits preservation plan, ownership threshold, beneficial ownership threshold, percent 4.90%              
Tax benefits preservation plan, ownership threshold, beneficial ownership threshold, period (in years) 3 years              
Maximum                
Class of Stock [Line Items]                
Tax benefits preservation plan, ownership threshold, beneficial ownership threshold, percent 5.00%              
Minimum                
Class of Stock [Line Items]                
Tax benefits preservation plan, ownership threshold, beneficial ownership threshold, increases by more points over lowest percentage of stock owned 50.00%              
Common Stock                
Class of Stock [Line Items]                
Common stock, outstanding (in shares) 36,825,000 37,203,000 37,091,000     36,868,000    
Repurchases of common stock (in shares) 596,000 21,000            
Dividend reinvestments (in shares) 92,733              
The Tax Benefits Preservation Plan                
Class of Stock [Line Items]                
Number of rights per outstanding share of common stock               1
The Tax Benefits Preservation Plan | Preferred Stock                
Class of Stock [Line Items]                
Exercise price of warrants (in usd per share) | $ / shares               $ 5
Restricted Stock                
Class of Stock [Line Items]                
Unvested shares/units outstanding (in shares) 67,000 53,000 54,000     18,000    
Restricted Stock Units                
Class of Stock [Line Items]                
Unvested shares/units outstanding (in shares) 201,000 153,000 138,000     252,000    
Performance share units                
Class of Stock [Line Items]                
Unvested shares/units outstanding (in shares) 44,000 23,000 16,000     17,000    
v3.25.4
Equity - Schedule of Treasury Stock Activity (Details) - Treasury Stock - USD ($)
shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Number of shares withheld for taxes 25 29 59
Value of shares withheld for taxes $ 290 $ 393 $ 929
v3.25.4
Revenues - Schedule of Disaggregation of Revenue (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Disaggregation of Revenue [Line Items]      
Total revenues $ 156,357 $ 125,290 $ 148,641
v3.25.4
Revenues - Narrative (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Disaggregation of Revenue [Line Items]      
Bad debt expense on revenues receivable $ 0.0 $ 0.0 $ 0.0
Accounts Receivable | Customer Concentration Risk | Five Purchasers      
Disaggregation of Revenue [Line Items]      
Concentration risk percentage 79.50%    
Revenue Receivable from Contract With Customers      
Disaggregation of Revenue [Line Items]      
Accounts receivable, gross $ 16.7 $ 15.3 $ 14.5
v3.25.4
Share Based Compensation - Narrative (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Oct. 04, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]    
Number of shares authorized (in shares) 300,000,000  
Omnibus Incentive Plan    
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]    
Number of shares authorized (in shares)   4,600,000
Restricted Stock    
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]    
Period of recognition for unrecognized costs (years) 6 months  
Unrecognized compensation expense $ 0.3  
Restricted Stock Units    
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]    
Vesting period (in years) 3 years  
Period of recognition for unrecognized costs (years) 1 year 9 months 18 days  
Unrecognized compensation expense $ 1.7  
Performance share units    
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]    
Vesting period (in years) 1 year  
Period of recognition for unrecognized costs (years) 2 months 12 days  
Unrecognized compensation expense $ 0.1  
Stock Options    
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]    
Vesting period (in years) 3 years  
Unrecognized compensation expense $ 0.2  
Expiration period (in years) 7 years  
Options outstanding, Weighted average remaining life (in years) 8 months 12 days  
Minimum | Restricted Stock    
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]    
Vesting period (in years) 1 year  
v3.25.4
Share Based Compensation - Schedule of Awards (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Restricted Stock      
Number of Shares      
Unvested shares/units outstanding at beginning of period (in shares) 53 54 18
Granted (in shares) 67 65 54
Vested (in shares) (53) (65) (18)
Forfeited / Canceled (in shares) 0 0 0
Unvested shares/units outstanding at end of period (in shares) 67 53 54
Weighted- Average Grant Date Fair Value (usd per share)      
Unvested shares outstanding at beginning of period (in usd per share) $ 13.17 $ 13.85 $ 18.93
Granted (in usd per share) 10.94 13.20 13.85
Vested (in usd per share) 13.17 13.76 18.93
Forfeited / Canceled (in usd per share) 0 0 0
Unvested shares outstanding at end of period (in usd per share) $ 10.94 $ 13.17 $ 13.85
Aggregate intrinsic value of award vested during period $ 0.6    
Restricted Stock Units      
Number of Shares      
Unvested shares/units outstanding at beginning of period (in shares) 153 138 252
Granted (in shares) 109 96 79
Vested (in shares) (61) (81) (175)
Forfeited / Canceled (in shares) 0 0 (18)
Unvested shares/units outstanding at end of period (in shares) 201 153 138
Weighted- Average Grant Date Fair Value (usd per share)      
Unvested shares outstanding at beginning of period (in usd per share) $ 13.78 $ 12.51 $ 5.93
Granted (in usd per share) 11.48 13.14 15.13
Vested (in usd per share) 13.92 10.85 4.33
Forfeited / Canceled (in usd per share) 0 0 11.50
Unvested shares outstanding at end of period (in usd per share) $ 12.50 $ 13.78 $ 12.51
Aggregate intrinsic value of award vested during period $ 0.7    
Performance share units      
Number of Shares      
Unvested shares/units outstanding at beginning of period (in shares) 23 16 17
Granted (in shares) 44 23 19
Vested (in shares) (23) (16) (17)
Forfeited / Canceled (in shares) 0 0 (3)
Unvested shares/units outstanding at end of period (in shares) 44 23 16
Weighted- Average Grant Date Fair Value (usd per share)      
Unvested shares outstanding at beginning of period (in usd per share) $ 13.63 $ 15.31 $ 13.51
Granted (in usd per share) 11.60 13.63 15.31
Vested (in usd per share) 13.63 15.31 13.51
Forfeited / Canceled (in usd per share) 0 0 15.31
Unvested shares outstanding at end of period (in usd per share) $ 11.60 $ 13.63 $ 15.31
Aggregate intrinsic value of award vested during period $ 0.3    
v3.25.4
Share Based Compensation - Schedule of Weighted Average Assumptions (Details) - Stock Options
 12 Months Ended
Dec. 31, 2021
USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]  
Risk-free interest rate 0.79%
Expected dividend yield $ 0
Expected volatility 78.20%
Expected term 5 years
v3.25.4
Share Based Compensation - Schedule of Stock Option Activity (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Stock Options Activity        
Outstanding at beginning of period (in shares) 250 250 286  
Granted (in shares) 0 0 0  
Exercised (in shares) 0 0 (36)  
Expired (in shares) 0 0 0  
Forfeited / Canceled (in shares) 0 0 0  
Outstanding at end of period (in shares) 250 250 250 286
Stock Options Weighted Average Exercise Price        
Options outstanding, Weighted average exercise price per share, beginning of period (in USD per share) $ 0 $ 0 $ 0  
Options granted, Weighted average exercise price per share (in USD per share) 0 0 0  
Options exercised, Weighted average exercise price per share (in USD per share) 0 0 15.68  
Options expired, Weighted average exercise price per share (in USD per share) 0 0 0  
Options forfeited / canceled, Weighted average exercise price per share (in USD per share) 0 0 0  
Options outstanding, Weighted average exercise price per share, end of period (in USD per share) $ 0 $ 0 $ 0 $ 0
Additional Disclosures        
Options outstanding, Weighted average remaining contractual term 5 years 7 months 24 days 6 years 7 months 24 days 7 years 7 months 28 days 7 years 7 months 20 days
Options outstanding, Aggregate intrinsic value $ 1,210 $ 530 $ 1,020 $ 2,380
Options exercisable, Number of options (in shares) 200 150 100  
Options exercisable, Weighted average exercise price per share (in USD per share) $ 0 $ 0 $ 0  
Options exercisable, Weighted average remaining contractual term 5 years 7 months 24 days 6 years 7 months 24 days 7 years 7 months 28 days  
Options exercisable, Aggregate intrinsic value $ 970 $ 320 $ 410  
v3.25.4
Share Based Compensation - Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan (Details) - Recurring Compensation Expense - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]      
Total share-based compensation expense $ 2,744 $ 2,354 $ 1,945
Restricted stock awards and units      
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]      
Total share-based compensation expense 1,909 1,790 1,415
Performance share units      
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]      
Total share-based compensation expense 535 264 229
Stock options      
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]      
Total share-based compensation expense $ 300 $ 300 $ 301
v3.25.4
Incentive and Deferred Compensation Plans (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]      
Retirement plan, employer matching contribution, percent of match 100.00% 100.00% 100.00%
Retirement plan, employer matching contribution, percent of employees' gross pay (up to) 10.00% 10.00% 10.00%
Retirement plan, cost recognized $ 0.9 $ 0.9 $ 0.8
Percent of employee contributions vesting immediately 100.00% 100.00% 100.00%
Retirement plan, employer matching contribution, vesting period (in years) 4 years    
Annual Incentive Plan      
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]      
Accrued bonuses $ 2.9 $ 2.2  
Payments to employees $ 2.7 $ 2.2 $ 2.2
v3.25.4
Earnings per Share (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Earnings Per Share [Abstract]      
Net Income (loss) $ 70,203 $ 62,986 $ 60,857
Weighted Average Shares, basic (in shares) 36,773 37,106 36,939
Earnings Per Share, Basic (in dollars per share) $ 1.91 $ 1.70 $ 1.65
Effect of dilutive securities      
Restricted share units $ 0 $ 0 $ 0
Restricted share units (in shares) 63 28 19
Restricted stock awards $ 0 $ 0 $ 0
Restricted stock awards (in shares) 29 32 120
Performance share units $ 0 $ 0 $ 0
Performance share units (in shares) 31 11 13
Stock Options $ 0 $ 0 $ 0
Stock Options (in shares) 12 11 43
Diluted earnings per share $ 70,203 $ 62,986 $ 60,857
Diluted earnings per share (in shares) 36,908 37,188 37,134
Diluted earnings per share (in dollars per share) $ 1.90 $ 1.69 $ 1.64
v3.25.4
Segment Reporting - Narrative (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
segment
Dec. 31, 2024
USD ($)
Segment Reporting Information [Line Items]    
Number of operating segments | segment 1  
Number of reportable segments | segment 1  
Assets | $ $ 644,021 $ 581,511
Reportable Segment    
Segment Reporting Information [Line Items]    
Assets | $ $ 644,000 $ 581,500
v3.25.4
Segment Reporting - Schedule of Segment Reporting Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting Information [Line Items]      
Total revenues $ 156,357 $ 125,290 $ 148,641
Expenses      
Lease operating expenses 36,191 40,012 41,862
Production, ad valorem, and other taxes 9,846 6,780 10,870
Depreciation and depletion—oil and natural gas 36,439 25,976 15,657
Depreciation and amortization—other 6,433 6,503 6,518
General and administrative 13,201 11,695 10,735
Restructuring expenses 1,060 474 406
Employee termination benefits 0 0 19
(Gain) loss on derivative contracts (7,763) (748) (1,447)
Other operating (income) expense 0 1,372 (157)
Total expenses 95,407 92,064 84,463
Income (loss) from operations 60,950 33,226 64,178
Interest income (expense), net 3,687 7,744 10,552
Other income (expense), net 31 (216) 87
Total other income (expense) 3,718 7,528 10,639
Income (loss) before income taxes 64,668 40,754 74,817
Total (5,535) (22,232) 13,960
Net income (loss) 70,203 62,986 60,857
Reportable Segment      
Segment Reporting Information [Line Items]      
Total revenues 156,357 125,290 148,641
Expenses      
Lease operating expenses 36,191 40,012 41,862
Production, ad valorem, and other taxes 9,846 6,780 10,870
Depreciation and depletion—oil and natural gas 36,439 25,976 15,657
Depreciation and amortization—other 6,433 6,503 6,518
General and administrative 13,201 11,695 10,735
Restructuring expenses 1,060 474 406
Employee termination benefits 0 0 19
(Gain) loss on derivative contracts (7,763) (748) (1,447)
Other operating (income) expense 0 1,372 (157)
Total expenses 95,407 92,064 84,463
Income (loss) from operations 60,950 33,226 64,178
Interest income (expense), net 3,687 7,744 10,552
Other income (expense), net 31 (216) 87
Total other income (expense) 3,718 7,528 10,639
Income (loss) before income taxes 64,668 40,754 74,817
Total (5,535) (22,232) 13,960
Net income (loss) 70,203 62,986 60,857
Capital expenditures, including acquisitions 77,500 156,472 33,664
Oil      
Segment Reporting Information [Line Items]      
Total revenues 77,270 68,231 78,174
Oil | Reportable Segment      
Segment Reporting Information [Line Items]      
Total revenues 77,270 68,231 78,174
Natural gas      
Segment Reporting Information [Line Items]      
Total revenues 41,587 21,397 34,941
Natural gas | Reportable Segment      
Segment Reporting Information [Line Items]      
Total revenues 41,587 21,397 34,941
NGL      
Segment Reporting Information [Line Items]      
Total revenues 37,500 35,662 35,526
NGL | Reportable Segment      
Segment Reporting Information [Line Items]      
Total revenues $ 37,500 $ 35,662 $ 35,526
v3.25.4
Subsequent Events - Narrative (Details)
Mar. 03, 2026
$ / shares
Subsequent Event  
Business Acquisition [Line Items]  
Dividends declared (in dollars per share) $ 0.12
v3.25.4
Subsequent Events - Schedule of Natural Gas Derivative Swap (Details) - Subsequent Event
 2 Months Ended
Mar. 05, 2026
MMBTU
$ / Unit
$ / MMBTU
bbl
NYMEX 2026  
Business Acquisition [Line Items]  
Daily Volume (in million barrels) | MMBTU 3,750
Weighted average fixed price per unit (in dollars per unit) | $ / MMBTU 4.20
Daily Volume (in barrels) | bbl 816
NYMEX 2026 | Put Option  
Business Acquisition [Line Items]  
Weighted average fixed price per unit (in dollars per unit) 56.63
NYMEX 2026 | Call Option  
Business Acquisition [Line Items]  
Weighted average fixed price per unit (in dollars per unit) 79.43
NYMEX March 2026 - December 2026  
Business Acquisition [Line Items]  
Weighted average fixed price per unit (in dollars per unit) 70.00
Daily Volume (in barrels) | bbl 275
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Capitalized Costs Related to Oil and Natural Gas Producing Activities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Oil and natural gas properties    
Proved $ 1,759,943 $ 1,689,807
Unproved 27,520 23,504
Total oil and natural gas properties 1,787,463 1,713,311
Less: accumulated depreciation, depletion and impairment (1,446,824) (1,415,110)
Net oil and natural gas properties capitalized costs $ 340,639 $ 298,201
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Acquisitions of properties      
Proved $ 2,331 $ 126,998 $ 11,232
Unproved 6,183 2,666 0
Exploration 5,016 11,246 (46)
Development 63,970 15,562 22,478
Total cost incurred $ 77,500 $ 156,472 $ 33,664
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Costs Excluded from Amortization (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Total    
Acquisition, exploration, and other unproved property costs $ 26,636  
Capitalized interest 884  
Total costs incurred 27,520 $ 23,504
2025    
Acquisition, exploration, and other unproved property costs 10,589  
Capitalized interest 0  
Total costs incurred 10,589  
2024    
Acquisition, exploration, and other unproved property costs 4,298  
Capitalized interest 0  
Total costs incurred 4,298  
2023    
Acquisition, exploration, and other unproved property costs (270)  
Capitalized interest  
Total costs incurred (270)  
2022 and Prior    
Acquisition, exploration, and other unproved property costs 12,019  
Capitalized interest 884  
Total costs incurred $ 12,903  
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Results of Operations from Oil and Natural Gas Producing Activities (Unaudited) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Results of Operations for Oil and Gas Producing Activities      
Revenues $ 156,357 $ 125,290 $ 148,641
Expenses      
Production costs 46,629 46,832 53,099
Depreciation and depletion 36,439 25,976 15,657
Total expenses 83,068 72,808 68,756
Income (loss) before income taxes 73,289 52,482 79,885
Income tax expense (benefit) 17,775 12,728 19,374
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) 55,514 39,754 60,511
Oil, natural gas and NGL      
Results of Operations for Oil and Gas Producing Activities      
Revenues $ 156,357 $ 125,290 $ 148,641
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Narrative (Details)
Boe in Thousands, MMBoe in Millions, MBoe in Millions
 12 Months Ended
Dec. 31, 2025
MBoe
Dec. 31, 2024
MBoe
Dec. 31, 2023
MBoe
MMBoe
Dec. 31, 2025
MBoe
Dec. 31, 2025
Boe
Dec. 31, 2024
MBoe
Dec. 31, 2024
Boe
Dec. 31, 2023
Boe
Dec. 31, 2022
MBoe
Dec. 31, 2022
Boe
Extractive Industries [Abstract]                    
Percentage of proved reserves estimates prepared by external engineers 0.979 0.975                
Percentage of proved reserves estimates prepared internally 2.10%                  
Proved developed and undeveloped reserves (MMBoe)     55.7 69.1 69,148 63.1 63,090 55,677 74.3 74,324
Increase (decrease) in commodity for oil and natural gas and extensions (MMBoe) 7.3   1.2              
Proved developed and undeveloped reserves, revision of previous estimate, Attributable to purchases (MMBoe) 1.7 16.0                
Proved developed and undeveloped reserves, revision of previous estimate, attributable to positive (negative) revisions including (MMBoe) 3.2 (6.6)                
Revision of previous estimates due to changes in commercial improvements (MMBoe) 4.5 3.5 1.7              
Proved developed and undeveloped reserves, revision of previous estimate, Change in pricing (MMBoe) 6.8   6.2              
Proved developed and undeveloped reserves, revision of previous estimate, attributable to other revisions (MMBoe) 3.9 1.7                
Proved developed and undeveloped reserves, net, adjustment for change in accounting, remaining proved reserves (MMBoe)   2.3 1.8              
Proved developed and undeveloped reserves, (energy), revision of previous estimate, attributable to performance revisions (MMBoe)   6.1                
Proved developed and undeveloped reserves, net (energy), adjustment for change in accounting (MMBoe)     17.5              
Attributable to well shut-ins and other revisions (MMBoe)     1.4              
Proved developed and undeveloped reserves, revision of previous estimate, attributable to sales (MMBoe)     0.1              
Revision of previous estimates due to changes in well performance (MMBoe)     1.9              
Percentage of discount factor 0.10                  
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Changes in Estimated Oil and Natural Gas Reserves (Unaudited) (Details)
bbl in Thousands, Mcf in Thousands, Boe in Thousands, MBoe in Millions
 12 Months Ended
Dec. 31, 2025
Boe
MBoe
bbl
Mcf
Dec. 31, 2025
Boe
bbl
Mcf
Dec. 31, 2025
Boe
Mcf
bbl
Dec. 31, 2025
Boe
bbl
Mcf
Dec. 31, 2025
Boe
psi
bbl
Mcf
Dec. 31, 2025
Boe
°F
bbl
Mcf
Dec. 31, 2024
MBoe
Boe
bbl
Mcf
Dec. 31, 2024
Boe
bbl
Mcf
Dec. 31, 2024
Boe
Mcf
bbl
Dec. 31, 2024
Boe
bbl
Mcf
Dec. 31, 2023
MBoe
Boe
bbl
Mcf
Dec. 31, 2023
Boe
bbl
Mcf
Dec. 31, 2023
Boe
Mcf
bbl
Dec. 31, 2023
Boe
bbl
Mcf
Dec. 31, 2022
Boe
Mcf
bbl
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)                              
Proved developed and undeveloped reserves, Beginning balance (MBoe) 63.1     63,090     55.7     55,677 74.3     74,324  
Revisions of previous estimates (MBoe) | Boe       3,852           (2,503)       (15,304)  
Acquisitions of new reserves (MBoe) | Boe       1,677           15,971       1,745  
Extensions and discoveries (MBoe) | Boe       7,298           1       1,211  
Sales of reserves in place (MBoe) | Boe       0           0       (147)  
Sales of reserves in place (MBoe) | Boe       (6,768)           (6,056)       (6,152)  
Proved developed and undeveloped reserves, Ending balance (MBoe) 69.1     69,148     63.1     63,090 55.7     55,677  
Proved developed reserves (MBoe) | Boe 60,317 60,317 60,317 60,317 60,317 60,317 56,970 56,970 56,970 56,970 55,677 55,677 55,677 55,677 74,324
Proved undeveloped reserves (MBoe) | Boe 8,831 8,831 8,831 8,831 8,831 8,831 6,120 6,120 6,120 6,120 0 0 0 0 0
Oil                              
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)                              
Proved developed and undeveloped reserves, beginning balance   9,745           7,057       8,421      
Revisions of previous estimates   (349)           (535)       (1,027)      
Acquisitions of new reserves   522           4,131       453      
Extensions and discoveries   2,272           10       283      
Sales of reserves in place   0           0       (26)      
Production   (1,214)           (918)       (1,047)      
Proved developed and undeveloped reserves, ending balance   10,976           9,745       7,057      
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) 8,204 8,204 8,204 8,204 8,204 8,204 7,863 7,863 7,863 7,863 7,057 7,057 7,057 7,057 8,421
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) 2,771 2,771 2,771 2,771 2,771 2,771 1,882 1,882 1,882 1,882 0 0 0 0 0
NGL                              
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)                              
Proved developed and undeveloped reserves, beginning balance   20,693           16,215       25,433      
Revisions of previous estimates   2,929           489       (8,200)      
Acquisitions of new reserves   575           5,884       379      
Extensions and discoveries   2,516           (6)       357      
Sales of reserves in place   0           0       (49)      
Production   (2,254)           (1,889)       (1,705)      
Proved developed and undeveloped reserves, ending balance   24,460           20,693       16,215      
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) 21,428 21,428 21,428 21,428 21,428 21,428 18,499 18,499 18,499 18,499 16,215 16,215 16,215 16,215 25,433
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) 3,032 3,032 3,032 3,032 3,032 3,032 2,194 2,194 2,194 2,194 0 0 0 0 0
Natural gas                              
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)                              
Proved developed and undeveloped reserves, beginning balance | Mcf     195,908           194,433       242,822    
Revisions of previous estimates | Mcf     7,629           (14,754)       (36,464)    
Acquisitions of new reserves | Mcf     3,478           35,738       5,474    
Extensions and discoveries | Mcf     15,063           (21)       3,431    
Sales of reserves in place | Mcf     0           0       (427)    
Production | Mcf     (19,802)           (19,488)       (20,403)    
Proved developed and undeveloped reserves, ending balance | Mcf     202,276           195,908       194,433    
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf 184,112 184,112 184,112 184,112 184,112 184,112 183,647 183,647 183,647 183,647 194,433 194,433 194,433 194,433 242,822
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf 18,164 18,164 18,164 18,164 18,164 18,164 12,261 12,261 12,261 12,261 0 0 0 0 0
Proved developed and undeveloped reserves, per square inch absolute | psi         14.65                    
Proved developed and undeveloped reserves, degree fahrenheit | °F           60                  
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Calculation of Weighted Average Per Unit Prices (Unaudited) (Details)
 12 Months Ended
Dec. 31, 2025
$ / Mcf
$ / bbl
Dec. 31, 2024
$ / bbl
$ / Mcf
Dec. 31, 2023
$ / bbl
$ / Mcf
Oil      
Oil and Gas, Present Activity [Line Items]      
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) 64.15 74.04 76.65
Natural gas      
Oil and Gas, Present Activity [Line Items]      
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) | $ / Mcf 2.07 1.02 1.62
NGL      
Oil and Gas, Present Activity [Line Items]      
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) 17.13 19.40 21.53
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Standardized Measure of Discounted Future Cash Flows (Unaudited) (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Extractive Industries [Abstract]        
Future cash inflows from production $ 1,542,062 $ 1,322,371 $ 1,204,568  
Future production costs (592,532) (584,452) (627,715)  
Future development costs (135,268) (108,821) (39,288)  
Future income tax expenses 0 0 0  
Undiscounted future net cash flows 814,262 629,098 537,565  
10% annual discount (374,694) (266,402) (241,272)  
Standardized measure of discounted future net cash flows $ 439,568 $ 362,696 $ 296,293 $ 806,865
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (Unaudited) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow [Roll Forward]      
Beginning present value $ 362,696 $ 296,293 $ 806,865
Changes during the year      
Revenues less production (110,320) (78,497) (95,909)
Net changes in prices, production and other costs 28,491 (43,115) (372,897)
Development costs incurred 0 0 645
Net changes in future development costs (4,360) (6,991) (1,307)
Extensions and discoveries 70,141 137 18,422
Revisions of previous quantity estimates 25,851 (14,213) (171,758)
Previously estimated development costs incurred 31,507 0 0
Accretion of discount 36,270 29,629 81,066
Net change in income taxes 0 0 3,798
Purchases of reserves in-place 22,463 168,590 14,450
Sales of reserves in-place 0 0 (1,394)
Timing differences and other (23,171) 10,863 14,312
Net change for the year 76,872 66,403 (510,572)
Ending present value $ 439,568 $ 362,696 $ 296,293