INFINITY NATURAL RESOURCES, INC., 10-K filed on 3/10/2026
Annual Report
v3.25.4
Cover - USD ($)
 12 Months Ended
Dec. 31, 2025
Mar. 05, 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 001-42499    
Registrant Name INFINITY NATURAL RESOURCES, INC.    
Entity Incorporation, State or Country Code DE    
Entity Tax Identification Number 99-3407012    
Entity Address, Address Line One 2605 Cranberry Square    
Entity Address, City or Town Morgantown    
Entity Address, State or Province WV    
Entity Address, Postal Zip Code 26508    
City Area Code 304    
Local Phone Number 212-2350    
Title of 12(b) Security Class A common stock, par value $0.01 per share    
Trading Symbol INR    
Security Exchange Name NYSE    
Entity Well-known Seasoned Issuer No    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Non-accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company true    
Entity Ex Transition Period false    
ICFR Auditor Attestation Flag false    
Document Financial Statement Error Correction [Flag] false    
Entity Shell Company false    
Entity Public Float     $ 277,442,275
Central Index Key 0002029118    
Amendment Flag false    
Document Fiscal Period Focus FY    
Document Fiscal Year Focus 2025    
Common Class A      
Document Information [Line Items]      
Entity Common Stock, Shares Outstanding   18,165,700  
Common Class B      
Document Information [Line Items]      
Entity Common Stock, Shares Outstanding   45,247,974  
v3.25.4
Audit Information
 12 Months Ended
Dec. 31, 2025
Audit Information [Abstract]  
Auditor Name Deloitte & Touche LLP
Auditor Location Pittsburgh, Pennsylvania
Auditor Firm ID 34
v3.25.4
Consolidated Balance Sheets - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Current assets:    
Cash and cash equivalents $ 2,849 $ 2,203
Oil and natural gas sales, net 54,836 39,314
Joint interest and other, net 12,912 32,229
Short Term Deposit on Acquisitions 61,200 0
Prepaid expenses and other current assets 4,002 11,822
Commodity derivative assets 24,838 0
Total current assets 160,637 85,568
Oil and natural gas properties, full cost method (including $88.7 million and $86.5 million as of December 31, 2025 and 2024, respectively excluded from amortization) 1,264,212 933,228
Midstream and other property and equipment 57,116 40,053
Less: Accumulated depreciation, depletion, and amortization (256,712) (153,233)
Property and equipment, net 1,064,616 820,048
Operating lease right-of-use assets, net 1,147 1,389
Deferred tax asset, net 4,858 0
Other assets 6,709 8,461
Commodity derivative assets 2,885 0
Total assets 1,240,852 915,466
Current liabilities:    
Accounts payable 38,572 51,370
Royalties payable 39,686 23,129
Accrued liabilities and other 23,021 46,004
Operating lease liabilities 181 247
Commodity derivative liabilities, short-term 1,106 12,596
Total current liabilities 102,566 133,346
Credit facility borrowings 150,862 259,406
Operating lease liabilities, net of current portion 966 1,142
Asset retirement obligations 3,636 2,988
Commodity derivative liabilities 3,361 10,342
Tax Receivable Agreement 1,537 0
Total liabilities 262,928 407,224
Redeemable non-controlling interest 670,785 0
Stockholders’ equity / members’ equity    
Members’ equity 0 508,242
Additional paid-in capital 310,972 0
Accumulated deficit (4,440) 0
Total stockholders' deficit 307,139 0
Total stockholders’ equity / members’ equity 0 508,242
Total liabilities, redeemable non-controlling interest and stockholders’ equity / members’ equity 1,240,852 915,466
Common Class A    
Stockholders’ equity / members’ equity    
Common stock outstanding 155 0
Common Class B    
Stockholders’ equity / members’ equity    
Common stock outstanding $ 452 $ 0
v3.25.4
Consolidated Statements of Operations - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Revenues:      
Total revenues $ 356,431 $ 259,022 $ 161,730
Operating expenses:      
Gathering, processing, and transportation 54,779 49,290 31,097
Lease operating 26,675 28,154 18,371
Production and ad valorem taxes 5,918 1,071 886
Depreciation, depletion, and amortization 103,751 73,726 53,796
General and administrative expense [1] 153,413 13,045 4,885
Total operating expenses 344,536 165,286 109,035
Operating income 11,895 93,736 52,695
Other income (expense):      
Interest, net (9,666) (21,529) (11,910)
Gain (loss) on derivative instruments 58,407 (22,047) 45,322
Other income (expense) (1,535) (874) 565
Net income before income tax expense (benefit) 59,101 49,286 86,672
Income tax expense (benefit) (4,858) 0 0
Net income 63,959 49,286 86,672
Net income attributable to Infinity Natural Resources, LLC prior to the reorganization 9,914 49,286 $ 86,672
Net income attributable to redeemable non-controlling interests 40,209 0  
Net income attributable to Infinity Natural Resources, Inc. $ 13,836 $ 0  
Weighted-average common stock outstanding—basic (in shares) 15,382,681 0 0
Net income (loss) attributable to Infinity Natural Resources, Inc.—basic (in dollars per share) $ 0.90 $ 0 $ 0
Weighted-average common stock outstanding—diluted (in shares) 60,954,639 0 0
Net income (loss) attributable to Infinity Natural Resources, Inc.— diluted (in dollars per share) $ 0.89 $ 0 $ 0
Oil, natural gas, and natural gas liquids sales      
Revenues:      
Total revenues $ 350,375 $ 257,706 $ 159,532
Midstream activities      
Revenues:      
Total revenues $ 6,056 $ 1,316 $ 2,198
[1] General and administrative expense includes a one-time share-based compensation expense of $126.1 million for the year ended December 31, 2025, incurred in connection with the IPO (as defined herein).
v3.25.4
Consolidated Statements of Operations (Parenthetical)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Income Statement [Abstract]  
Compensation expense $ 126.1
v3.25.4
Consolidated Statements of Redeemable Non-controlling Interest and Stockholders’ (Deficit) Equity / Members’ Equity (Unaudited) - USD ($)
$ in Thousands
Total
Additional Paid-in Capital
Retained Earnings
Common Class A
Common Class A
Common Stock
Common Class B
Common Class B
Common Stock
INR, Inc. Members' Equity, beginning balance at Dec. 31, 2022 $ 149,506            
Increase (Decrease) in Partners' Capital [Roll Forward]              
Contributions 222,278            
Net Income 86,672            
INR, Inc. Members' Equity, ending balance at Dec. 31, 2023 458,456            
Equity, beginning balance (in shares) at Dec. 31, 2022         0   0
Equity, beginning balance at Dec. 31, 2022 0 $ 0 $ 0   $ 0   $ 0
Redeemable Non-controlling Interest, beginning balance at Dec. 31, 2022 0            
Increase (Decrease) in Partners' Capital [Roll Forward]              
Contributions 500            
Net Income 49,286            
INR, Inc. Members' Equity, ending balance at Dec. 31, 2024 508,242            
Equity, ending balance (in shares) at Dec. 31, 2024       0 0 0 0
Equity, Ending balance at Dec. 31, 2024 0 0 0   $ 0   $ 0
Redeemable Non-controlling Interest, ending balance at Dec. 31, 2024 0            
Increase (Decrease) in Partners' Capital [Roll Forward]              
Net Income 9,914            
Effect of the reorganization transactions (518,156)            
INR, Inc. Members' Equity, ending balance at Dec. 31, 2025 0            
Increase (Decrease) in Stockholders' Equity [Roll Forward]              
Effect of the reorganization transactions (in shares)             45,638,889,000
Effect of the reorganization transactions 456           $ 456
Stock exchanged during period (in shares)         15,237,500,000    
Issuance of common stock in connection with initial public offering, net of underwriting discounts, commissions and other offering costs $ 198,356 198,204     $ 152    
Stock Issued During Period, Shares, Conversion of Units 400,000       390,915,000   (390,915,000)
Conversion of Class B Units to Class A Units $ 7,248 7,248     $ 4   $ (4)
Share-based compensation plans (in shares)         1,238,000    
Share-based compensation plans 133,423 133,423          
Net income 13,836            
Stock repurchase program (in shares)         (87,132,000)    
Stock repurchase program (1,188) (1,187)     $ (1)    
Increase in Tax Receivable Agreement Liability / Establishment of liabilities under the Tax Receivable Agreement (1,537) (1,537)          
Adjustment of redeemable non-controlling interest to redemption value (43,455) (25,179) (18,276)        
Equity, ending balance (in shares) at Dec. 31, 2025       15,542,521 15,542,521,000 45,247,974 45,247,974,000
Equity, Ending balance at Dec. 31, 2025 307,139 $ 310,972 $ (4,440)   $ 155   $ 452
Increase (Decrease) in Temporary Equity [Roll Forward]              
Effect of the reorganization transactions 517,700            
Issuance of common stock in connection with initial public offering, net of underwriting discounts, commissions and other offering costs 76,911            
Conversion of Class B Units to Class A Units (7,248)            
Distributions to noncontrolling interest owners (242)            
Net income 40,209            
Adjustment of redeemable non-controlling interest to redemption value 43,455            
Redeemable Non-controlling Interest, ending balance at Dec. 31, 2025 $ 670,785            
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 $ 63,959 $ 49,286 $ 86,672
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation, depletion, and amortization 103,751 73,726 53,796
Amortization of debt issuance costs 1,705 1,957 778
Share-based compensation expense 133,423 0 0
Loss (gain) on derivative instruments (58,407) 22,047 (45,322)
Cash received on settlement of derivative instruments 12,213 28,360 19,438
Non-cash lease expense 248 203 98
Deferred income taxes (4,858) 0 0
Changes in operating assets and liabilities:      
Accounts receivable 3,795 (27,447) (21,775)
Prepaid expenses and other assets (1,791) 143 (1,770)
Accounts payable 743 16,367 7,565
Royalties payable 16,557 5,554 6,390
Accrued and other expenses (3,082) 11,776 703
Other assets and liabilities (6,469) (4,306) (98)
Net cash provided by operating activities 261,787 177,666 106,475
Cash flows from investing activities:      
Additions to oil and gas properties (356,369) (249,545) (145,979)
Additions to oil and gas properties 0 0 (278,967)
Deposits of acquisitions of oil and gas properties (61,200) 0 0
Additions to midstream and other property and equipment (12,598) (6,573) (11,740)
Net cash used in investing activities (430,167) (256,118) (436,686)
Cash flows from financing activities:      
Borrowings under revolving credit facility 253,500 411,456 203,864
Borrowings on notes payable 124 0 0
Payments on revolving credit facility (362,000) (323,073) (90,800)
Proceeds from issuance of Class A common stock in initial public offering, net of underwriting discounts and commissions 286,465 500 222,278
Payments of debt issuance costs (645) (5,200) (4,256)
Payments of initial public offering costs (6,760) (4,415) 0
Payments on notes payable (229) (117) (110)
Distributions to noncontrolling interest owners (242) 0 0
Share Repurchase Program (1,187) 0 0
Net cash provided by financing activities 169,026 79,151 330,976
Net increase in cash and cash equivalents 646 699 765
Cash and cash equivalents at beginning of period 2,203 1,504 739
Cash and cash equivalents at end of period $ 2,849 $ 2,203 $ 1,504
v3.25.4
Supplemental Cash Flow Information
 12 Months Ended
Dec. 31, 2025
Supplemental Cash Flow Elements [Abstract]  
Supplemental Cash Flow Information Supplemental Cash Flow Information
The following table provides additional information concerning non-cash activities and cash paid for interest, net of amounts capitalized, for the years ended December 31, 2025, 2024 and 2023:
 For the Year Ended December 31,
 202520242023
Supplemental disclosure of non-cash transactions:
Right-of-use assets and lease liabilities6 834 18 
Net impact of non-cash asset retirement obligations409 1,917 140 
Debt issuance in accrued liabilities— 645 — 
Deferred offering costs included in accounts payable and accrued liabilities— 5,196 — 
Additions to oil and natural gas properties included in accounts payable and accrued liabilities40,168 50,052 25,453 
Additions to other property and equipment included in accounts payable and accrued liabilities1,858 769 831 
Increase in tax receivable agreement liability$1,537 $— $— 
Supplemental disclosure of cash flow information
Interest paid$7,269 $19,200 $10,136 
v3.25.4
Supplemental Cash Flow Information
 12 Months Ended
Dec. 31, 2025
Supplemental Cash Flow Elements [Abstract]  
Schedule of Supplemental Cash Flow Information
The following table provides additional information concerning non-cash activities and cash paid for interest, net of amounts capitalized, for the years ended December 31, 2025, 2024 and 2023:
 For the Year Ended December 31,
 202520242023
Supplemental disclosure of non-cash transactions:
Right-of-use assets and lease liabilities6 834 18 
Net impact of non-cash asset retirement obligations409 1,917 140 
Debt issuance in accrued liabilities— 645 — 
Deferred offering costs included in accounts payable and accrued liabilities— 5,196 — 
Additions to oil and natural gas properties included in accounts payable and accrued liabilities40,168 50,052 25,453 
Additions to other property and equipment included in accounts payable and accrued liabilities1,858 769 831 
Increase in tax receivable agreement liability$1,537 $— $— 
Supplemental disclosure of cash flow information
Interest paid$7,269 $19,200 $10,136 
v3.25.4
Consolidated Balance Sheets (Parenthetical) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Capitalized cost excluded from amortization $ 88.7 $ 86.5
Common Class A    
Common stock par value (in USD per share) $ 0.01 $ 0.01
Common stock authorized (in shares) 400,000,000 400,000,000
Common stock issued (in shares) 15,542,521 0
Common stock outstanding (in shares) 15,542,521 0
Common Class B    
Common stock par value (in USD per share) $ 0.01 $ 0.01
Common stock authorized (in shares) 150,000,000 150,000,000
Common stock issued (in shares) 45,247,974 0
Common stock outstanding (in shares) 45,247,974 0
v3.25.4
Supplemental Cash Flow Information - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Supplemental disclosure of non-cash transactions:      
Right-of-use assets and lease liabilities $ 6 $ 834 $ 18
Net impact of non-cash asset retirement obligations 409 1,917 140
Debt issuance in accrued liabilities 0 645 0
Deferred offering costs included in accounts payable and accrued liabilities 0 5,196 0
Additions to oil and natural gas properties included in accounts payable and accrued liabilities 40,168 50,052 25,453
Additions to other property and equipment included in accounts payable and accrued liabilities 1,858 769 831
Increase in tax receivable agreement liability 1,537 0 0
Supplemental disclosure of cash flow information      
Interest paid $ 7,269 $ 19,200 $ 10,136
v3.25.4
Description of the Business and Basis of Presentation
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Description of the Business and Basis of Presentation Description of the Business and Basis of Presentation
Description of Business. Infinity Natural Resources, Inc., together with its subsidiaries (collectively referred to as “Infinity”, the “Company,” “we,” “our,” or “us”, unless the context otherwise indicates), was incorporated in the state of Delaware on May 15, 2024 in anticipation of a potential initial public offering and related reorganization transactions. The Company is an independent oil and natural gas exploration and production company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids (“NGLs”). Our operations are located in the Appalachian Basin in the northeastern United States.

Initial Public Offering. On January 30, 2025, the Company's registration statement on Form S-1 relating to its initial public offering (“IPO”) was declared effective by the Securities and Exchange Commission (“SEC”), and the shares of its Class A common stock, par value $0.01 per share (“Class A common stock”) began trading on the New York Stock Exchange (“NYSE”) on January 31, 2025. The IPO closed in February 2025, pursuant to which the Company issued and sold 15,237,500 shares of its Class A common stock at a public offering price of $20.00 per share, including 1,987,500 shares issued pursuant to the full exercise of the underwriters’ option to purchase additional shares. The Company received net proceeds of approximately $286.5 million, after deducting underwriting discounts and commissions of $18.3 million. The Company contributed the net proceeds of the IPO to Infinity Natural Resources, LLC (“INR Holdings”), and INR Holdings used the net proceeds, after payment of certain offering expenses, to repay borrowings outstanding under its revolving credit facility.

Corporate Reorganization. In connection with the IPO, we underwent a corporate reorganization whereby: (a) the membership interests of the existing owners (the “Legacy Owners”) in INR Holdings were recapitalized into a single class of units (the “INR Units”), and, in exchange for their existing membership interests, the Legacy Owners received INR Units and an equal number of shares of the Company’s Class B common stock, par value $0.01 per share (“Class B common stock”); and (b) we contributed the net proceeds of the IPO to INR Holdings in exchange for newly issued INR Units and a managing member interest in INR Holdings (the “Corporate Reorganization”). Pursuant to the Second Amended and Restated Limited Liability Company Agreement of INR Holdings (as amended, the “INR Holdings LLC Agreement”), holders of INR Units (other than INR) are entitled to exchange their INR Units, and surrender an equivalent number of shares of Class B common stock, for a number of shares of Class A common stock on a one-for-one basis or, at our option, the receipt of an equivalent amount of cash. As of December 31, 2025, we own an approximate 25.6% interest in INR Holdings and the Legacy Owners own an approximate 74.4% interest in INR Holdings.

The Company is a holding company whose sole material asset consists of membership interests in INR Holdings. The Company is the managing member of INR Holdings and controls all operational, management and administrative decisions relating to INR Holdings’ business. Accordingly, the Company consolidates the financial results of INR Holdings and reports redeemable non-controlling interests in its consolidated financial statements related to the INR Units held by the Legacy Owners.

Basis of Accounting and Presentation. The consolidated financial statements present the financial position, results of operations, and cash flows of the Company in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”). The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. All intercompany balances and transactions are eliminated upon consolidation. The consolidated financial statements include the accounts of the Company, its subsidiary INR Holdings, and INR Holding’s wholly owned subsidiaries. Noncontrolling interests represent third‑party ownership interests in INR Holdings and are presented as a component of equity. See Note 12 - “Stockholders' Equity and Noncontrolling Interest” for a discussion of noncontrolling interest.
v3.25.4
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies Summary of Significant Accounting Policies
Use of Estimates. The preparation of financial statements 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. Management evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods it considers
reasonable in the particular circumstances. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Estimates significant to our consolidated financial statements include the following:
•proved reserves used in calculating depletion;
•estimates of accrued revenues and unbilled costs;
•future cash flows from proved oil and natural gas reserves used in the impairment assessment;
•derivative financial instruments; and
•asset retirement obligations.
Cash and Cash Equivalents. We consider all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short-term maturity of these investments. Interest earned on cash equivalents is included as a reduction of interest expense, net. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits; however, we have not experienced any significant losses from such investments.
Commodity Derivative Financial Instruments. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. We have elected not to designate any of our commodity derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, realized gains and losses from the settlement of commodity derivatives and unrealized gains and losses from changes in the fair value of remaining unsettled commodity derivatives are presented as a component of other income in the consolidated statements of operations. Management believes that presenting realized and unrealized gains and losses on commodity derivative instruments within revenues reflects the manner in which such instruments are economically linked to the Company’s oil and natural gas production and sales. Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the consolidated balance sheet. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors and nonperformance risk. See Note 9.
Deferred Offering Costs. Deferred offering costs incurred in connection with the Company’s initial public offering were capitalized and offset against IPO proceeds upon completion of the offering in February 2025. As of December 31, 2024, deferred offering costs of $9.6 million were included in prepaid expenses and other current assets. No deferred offering costs were recorded as of December 31, 2025.

Accounts Receivable and Allowance for Expected Credit Losses. Accounts receivable consist of receivables from the sales of oil, natural gas, and NGL production delivered to purchasers and from joint interest owners on properties we operate. Accounts receivable are stated at the amount due, net of an allowance for expected losses as estimated by us when applicable. Most payments for accounts receivable are received within 30 to 60 days. We typically have the ability to withhold future revenue disbursements to recover any non-payment of joint interest accounts receivable from joint interest owners outstanding longer than the contractual payment terms are considered past due. As of December 31, 2025, 2024 and 2023, our allowances for credit losses were not material.
Drilling Advances. The Company participates in the drilling of crude oil and natural gas wells with other working interest owners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest owner responsible for conducting the drilling operations may request advance payments from other working interest owners for their share of the costs. The following table summarizes drilling advance receivables and deposits included in accounts receivable – other and accrued liabilities on the consolidated balance sheets as December 31, 2025 and 2024:

For the Year Ended December 31,
in thousands20252024
Drilling Advance Receivable
$2,444 $12,502 
Drilling Advance Deposits
$1,296 $6,188 
Concentrations of Credit Risk. We are exposed to credit risk in the event of nonpayment by counterparties. We sell production to a relatively small number of customers, as is customary in our business. The table below summarizes the purchasers that accounted for 10% or more of our total revenues from the sale of commodities for the periods presented:
 For the Year Ended December 31,
 202520242023
Marathon Oil Company
33%55%49%
BP America
35%17%28%
Ergon16%—%—%
Blue Racer Midstream
—%10%13%
During these periods, no other purchaser accounted for 10% or more of our total commodity sales revenues. As of December 31, 2025, our accounts receivable balance related to oil and gas sales was comprised of amounts due from various purchasers, including amounts due from Marathon Oil Company, BP America and Ergon comprising 24%, 53% and 18%, respectively, of the total balance. As of December 31, 2024, our accounts receivable balance related to oil and gas sales was comprised of amounts due from Marathon Oil Company and BP America, which accounted for 49% and 25%, respectively, of the total balance.
By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company also exposes itself to credit risk. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. We minimize the credit risk in derivative instruments by: (i) limiting our exposure to any single counterparty; and (ii) only entering into hedging arrangements with counterparties that are also participants in our credit agreement, all of which have investment-grade credit ratings.
Oil and Gas Properties
Oil and Natural Gas Properties. The Company uses the full cost method of accounting for its oil and natural gas properties. Accordingly, all costs directly associated with the acquisition, exploration, and development of oil, natural gas, and NGL reserves for both productive and nonproductive properties are capitalized into a full cost pool. Capitalized costs also include the costs of unproved properties and internal costs (i.e. salaries and benefits attributed to production activities of a well) directly related to the Company’s acquisition, exploration, and development activities. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred.
Under the full cost method of accounting, total net capitalized costs of proved oil and natural gas properties may not exceed the ceiling limitation determined based on the estimated future net revenues of our proved reserves discounted at 10%. The future net revenues are estimated using the average of the first day of the month trailing 12-month price as of the period end date in accordance with guidance provided by the SEC, adjusted for basis or location differentials, held constant over the life of the proved reserves. 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 members’ equity and typically results in lower depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date. The Company did not have a ceiling test impairment for the years ended December 31, 2025, 2024 and 2023. See Note 4.
The costs associated with unproved properties are primarily the costs to acquire unproved acreage. Costs associated with unproved properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We review our unproved properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. We also may capitalize interest on expenditures made in connection with bringing unproved properties to their intended use. We determine capitalized interest, when applicable, by multiplying our weighted-average borrowing cost on our revolving credit facility by the average amount of qualifying costs incurred that were excluded from the full cost pool; however, capitalized interest cannot exceed the amount of gross
interest expense incurred in any given period. The following table represents our capitalized internal costs and interest shown within our oil and gas properties on the audited balance sheet for the years ended 2025, 2024 and 2023:

For the Year Ended December 31,
in thousands202520242023
Capitalized Internal Costs
$7,558 $5,612 $2,238 
Capitalized Interest Costs
$— $41 $— 
Capitalized costs of proved properties are computed on a units-of-production basis based on estimated proved reserves, whereby the depletion rate is determined by dividing the total unamortized cost base plus future development costs by estimated proved reserves on a net equivalent basis at the beginning of the period. The depletion rate is multiplied by total production for the period to compute depletion expense. The following table shows our years ended 2025, 2024 and 2023 depletion expense related to oil and gas properties and average depletion rate per Boe:
For the Year Ended December 31,
in thousands202520242023
Depletion of Proved Oil and Natural Gas Properties
$100,644 $71,553 $52,075 
Average Depletion Rate per BOE
$7.81 $8.10 $7.17 
Unproved Property Impairment. The Company assesses properties excluded from the full cost pool. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation. The Company did not have impairment on unproved properties for the years ended December 31, 2025, 2024 and 2023.
Midstream and Other Property and Equipment. Other property and equipment includes midstream assets, vehicles, furniture, fixtures, office equipment, and leasehold improvements, all of which are recorded at cost. These assets are depreciated using the straight-line method over their estimated useful lives which range between three and 25 years. Equipment upgrades and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts and a gain or loss is recorded in the consolidated statements of operations as needed. See Note 4.
Leases. At contract inception, we determine whether or not an arrangement contains a lease in accordance with the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Codification Topic 842, Leases (“ASC 842”). A contract is or contains a lease if it conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Upon determination that a contract meets the definition of a lease subject to ASC 842, a right-of-use asset and related lease liability are recorded based on the present value of the future lease payments over the lease term. Right-of-use assets represent our right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make future lease payments arising from the lease. Since the implicit rate in the lease is generally not available, we utilize our incremental borrowing rate as the discount rate for determining the present value of lease payments. See Note 6.
Asset Retirement Obligations. We accrue a liability for the estimated future costs associated with the plugging and abandonment of our oil and natural gas properties. For oil and natural gas wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. The fair value of the liability recognized is based on the present value of the estimated future cash outflows associated with our plugging and abandonment obligations. Revisions typically occur due to changes in estimated abandonment costs or the remaining lives of our wells, or if federal or state regulators enact new requirements regarding the abandonment of wells. We deplete the amount added to the costs of proved oil and natural gas properties and recognize an expense in
connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties. Accretion expense is included within depreciation, depletion, and amortization in the consolidated statements of operations. See Note 7.
Revenue Recognition. We derive revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when a performance obligation is satisfied by transferring control of the produced oil, natural gas, or NGLs to the customer. For all commodity products, we record revenue in the month production is delivered to the customer based on the amount of production delivered to the customer and the price we will receive. Payments are generally received between 30 and 60 days after the date of production. See Note 3.
Reportable Segment. We operate in only one reportable segment that is the exploration and production segment. All of our operations are conducted in one geographic area within the Appalachian Basin, primarily in Pennsylvania and Ohio, in the United States. See Note 17.
Income Taxes. The Company is subject to U.S. federal, state and local income taxes with respect to its allocable share of any taxable income of INR Holdings, as well as any stand-alone income generated by the Company. INR Holdings is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, INR Holdings is not subject to U.S. federal and certain state and local income taxes. Any taxable income generated by INR Holdings is passed through to and included in the taxable income of its members, including the Company, on a pro rata basis.
Income taxes are recognized based on earnings reported for tax return purposes and provisions recorded for deferred income taxes. Deferred income tax assets and liabilities are recognized based on temporary differences resulting from: (i) net operating loss carryforwards for income tax purposes, and (ii) differences between the amounts recorded to the consolidated financial statements and the tax basis of assets and liabilities, as measured using enacted statutory tax rates in effect at the end of a period. The effect of a change in tax rates or tax laws is recognized in income during the period such changes are enacted. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.
Adoption of New Accounting Standards
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740) – Improvements to Income Tax Disclosures (“ASU 2023-09”), which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated and provides additional requirements regarding income taxes paid. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted, and should be applied either prospectively or retrospectively. The Company adopted this guidance effective upon becoming a public company in 2025.

In March 2024, the FASB issued ASU 2024-01, Compensation-Stock Compensation (Topic 718). This ASU illustrates how to apply the scope guidance to determine whether a profits interest award should be accounted for as a share-based payment arrange under Accounting Standards Codification (“ASC”) 718 or another accounting standard. The amendments in this update are effective for public entities for fiscal years beginning after December 15, 2024. The Company adopted this guidance effective upon becoming a public company in 2025.
Accounting Standards Not Yet Adopted
In November 2024, the FASB issued ASU 2024-03 - Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40). This ASU requires entities to disaggregate any relevant expense caption presented on the face of the income statement within continuing operations into the following required natural expense categories within the footnotes, as applicable: (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, and (5) DD&A recognized as part of oil- and gas-producing activities or other depletion expenses. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of the adoption of this guidance.
We considered the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or not material upon adoption.
v3.25.4
Revenues
 12 Months Ended
Dec. 31, 2025
Revenue from Contract with Customer [Abstract]  
Revenues Revenues
Crude oil, natural gas, and NGL sales are recognized at the point in time when control of the product is transferred to the customer. Virtually all of our contract pricing provisions are based on market indices, with adjustments for transportation costs, quality differentials, and other contractual factors.
The following table presents commodity sales revenues from the sale of crude oil, natural gas, and NGLs:

 Year Ended December 31,
 202520242023
(in thousands)   
Oil revenues
$173,612 $161,514 $85,276 
Natural gas revenues
127,448 51,157 49,617 
NGL revenues
49,315 45,035 24,639 
Oil, natural gas, and natural gas liquids sales
$350,375 $257,706 $159,532 
Oil Sales
Our crude oil sales contracts are generally structured whereby oil is delivered to the customer at a contractually agreed-upon delivery point. This delivery point is usually at the wellhead. Revenue is recognized when control transfers to the customer at the delivery point based on the net price received from the customer. Any downstream transportation or marketing costs incurred by purchasers of our crude oil are reflected in the price we receive and are presented as a net reduction to oil sales revenues.
Natural Gas and NGL Sales
Under our natural gas processing contracts, liquids rich natural gas is delivered to a midstream gathering and processing entity at an agreed upon delivery point. The midstream entity gathers and processes the raw gas and then remits proceeds to us. For these contracts, we evaluate when control of the residue gas and NGLs is transferred in order to determine whether revenues should be recognized on a gross or net basis. Where we elect to take its residue gas and/or NGL production “in-kind” at the plant tailgate, fees incurred prior to transfer of control at the outlet of the plant are presented as gathering, processing, and transportation expense within the consolidated statements of operations. Where we do not take our residue gas and/or NGL production “in-kind”, transfer of control typically occurs at the inlet of the midstream entity’s gas gathering system such that any fees incurred subsequent to the delivery point are reflected as a net reduction to natural gas and NGL revenues presented in the table above and as included within oil, natural gas, and natural gas liquids sales within the consolidated statements of operations. Accordingly, we recognizes revenues from natural gas and NGL sales on either a gross or net basis depending on when control of the commodity transfers to the customer under the applicable contract.
Performance Obligations
Our commodity sales contracts originate upon production and do not exist beyond each day’s production. As a result, there are no remaining performance obligations under these contracts. Each delivery generally represents a separate performance obligation, and future volumes are wholly unsatisfied. Accordingly, disclosure of the transaction price allocated to remaining performance obligations is not required.
For all commodity products, we record revenue in the month production is delivered to the purchaser. Settlement statements for crude oil are generally received within 30 days following the date that production volumes are delivered, but for natural gas and NGL sales, statements may not be received for 30 to 60 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At such time, the volumes delivered and sales prices can be reasonably estimated and amounts due from customers are accrued in Accounts receivable – oil and natural gas sales, net in the consolidated balance sheets. As of December 31, 2025 and 2024, such receivable balances were $54.8 million and $39.3 million, respectively.
The Company is party to certain gathering service agreements that include minimum volume commitments (“MVCs”), which specify minimum quantities that the Company is required to deliver or pay for regardless of actual volumes
gathered. Revenue related to MVCs is recognized when the related performance obligation has been satisfied, which occurs when the gas is gathered or when it becomes remote that the Company will meet the contractual minimum volume.
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
Oil and Natural Gas Properties
We utilize the full cost method of accounting for costs related to the exploration, development, and acquisition of oil and natural gas properties. Our capitalized costs of oil and natural gas properties and the related accumulated depreciation, depletion, and amortization as of December 31, 2025 and 2024 are as follows:
 December 31, 2025December 31, 2024
(in thousands)
Oil and natural gas properties:
Proved properties$1,175,523 $846,738 
Unproved properties88,689 86,490 
Gross oil and natural gas properties1,264,212 933,228 
Less: accumulated depreciation, depletion, and amortization(249,296)(148,638)
Oil and natural gas properties, net$1,014,916 $784,590 
In July 2024 we closed on approximately 5,705 net acres within Salt Fork State Park for $58.5 million, which was recorded to unproved leasehold properties.
Capitalized costs of oil and natural gas properties are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved oil, natural gas, and NGL reserves discounted at 10%. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, despite commodity price increases which subsequently increase the ceiling. Companies using the full cost method are required to use the unweighted average of the first‑day‑of‑the‑month prices for the preceding 12 months to calculate the ceiling value of reserves. Historically, we have not designated any of our derivative contracts as cash flow hedges. Prices used to calculate the ceiling value of reserves were as follows:
For the Year Ended December 31,
20252024
Oil (per barrel)
$65.34 $75.48 
Natural gas (per MMBtu)
$3.39 2.13 
NGLs (per barrel)
$23.20 25.48 
Using the average quoted prices above, adjusted for market differentials, the net book value of our oil and natural gas properties did not exceed the ceiling amount at December 31, 2025 or 2024. We had no derivative positions that were designated for hedge accounting as of and for the years ended December 31, 2025 and 2024. Future decreases in market prices, as well as changes in production rates, levels of reserves, evaluation costs excluded from amortization, future development costs and production costs may result in future non-cash impairments to our oil and natural gas properties.
Costs associated with unproved properties are excluded from the amortization base until the properties are evaluated or impairment is indicated. The costs associated with unproved leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from the amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value.
Our decision to exclude costs from amortization and the timing of the transfer of those costs into the amortization base involves judgment and may be subject to changes over time based on numerous factors, including drilling plans, availability of capital, project economics, and drilling results from adjacent acreage.
Costs of unproved properties excluded from amortization consist of leasehold acreage and relate to properties which are not individually significant for which the evaluation process has not been completed. The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells, results of drilling, and other assessments. Therefore, we are unable to estimate when these costs will be included in the amortization computation.
Other Property and Equipment
Our other property and equipment consists of the following assets that are recorded at cost and depreciated on a straight-line basis over the respective estimated useful lives.
 December 31,
 20252024
(in thousands)  
Midstream assets
$53,077 $36,880 
Other property and equipment4,039 3,173 
Gross midstream and other property and equipment
57,116 40,053 
Less: Accumulated depreciation
(7,416)(4,595)
Total midstream and other property and equipment, net
$49,700 $35,458 
The estimated useful lives of other property and equipment depreciated on a straight-line basis are as follows:
Midstream assets
5 – 25 years
Vehicles
5 years
Furniture, fixtures, and office equipment
3 – 10 years
Leasehold improvements
5 years
The carrying value of long-lived assets that are not part of our full cost pool are evaluated for recoverability whenever events or changes in circumstances indicate that such carrying values may not be recoverable. Should an impairment exist, the impairment loss would be measured as the amount that the asset’s carrying value exceeds its fair value. We did not recognize any impairment during the years ended December 31, 2025 and 2024. Total depreciation expense for the years ended December 31, 2025 and 2024 totaled approximately $0.1 million and $2.1 million, respectively.
v3.25.4
Accrued Liabilities and Other
 12 Months Ended
Dec. 31, 2025
Payables and Accruals [Abstract]  
Accrued Liabilities and Other Accrued Liabilities and Other
Our accrued liabilities as of December 31, 2025 and December 31, 2024 consisted of the following amounts:
 December 31, 2025December 31, 2024
Accrued capital expenditures7,270 27,234 
Accrued general and administrative expenses7,706 3,293 
JIB advance deposits1,296 6,188 
Other accrued liabilities6,749 9,289 
Total accrued liabilities$23,021 $46,004 
v3.25.4
Leases
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Leases Leases
At contract inception, the Company determines whether or not an arrangement contains a lease in accordance with ASC 842. A contract is or contains a lease if it conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Upon determination that a contract meets the definition of a lease subject to ASC 842, a right-of-use asset and related lease liability are recorded based on the present value of the future lease payments over the lease term. Right-of-use assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make future lease payments arising from the lease. Since the implicit rate in the lease is
generally not available, the Company utilizes its incremental borrowing rate as the discount rate for determining the present value of lease payments. Right-of-use assets also include any lease payments made prior to commencement, excluding any lease incentives received.
We may enter into lease agreements for various purposes including drilling rig contracts, wellhead and surface equipment, rights-of-way and easements, and office space and equipment. For agreements that contain both lease and non-lease components, we have elected to combine and account for these as a single lease component. As of December 31, 2025, our lease agreements have remaining lease terms ranging from one month to 15 years; some of our agreements include options to extend the lease term and some of our agreements include options to early terminate at our sole discretion. These options are considered in determining the lease term and are included in the present value of future payments that are recorded for leases when we are reasonably certain to exercise the option. None of our lease agreements contain any material residual value guarantees or material restrictive covenants.
Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheets. Lease expense for operating leases recorded on our consolidated balance sheets is recognized on a straight-line basis over the lease term. Variable lease payments for leases that are not recorded on our consolidated balance sheets are recognized in the period in which they are incurred, which primarily relate to our office space and equipment leases.
The following table provides additional information related to our lease right-of-use assets and liabilities as of December 31, 2025, 2024 and 2023:
 For the Year Ended December 31,
 202520242023
Weighted-average discount rate9.0%9.0%9.1%
Weighted-average remaining lease term (years)9.79.413.0
For the years ended December 31, 2025, 2024 and 2023, lease expense, including operating leases related to our office space, of $0.4 million, $0.3 million and $0.2 million, respectively, was included within general and administrative expenses within our consolidated statements of operations.
Payments due under our long-term operating lease liabilities by fiscal year as of December 31, 2025, are as follows:
 Operating Leases
(in thousands)
2026$277 
2027277 
2028221 
2029185 
203091 
Thereafter705 
   Total lease payments1,756 
Less: imputed interest(609)
   Present value of lease liabilities$1,147 
v3.25.4
Asset Retirement Obligations
 12 Months Ended
Dec. 31, 2025
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligations Asset Retirement Obligations
 December 31,
 20252024
(in thousands)
Asset retirement obligations, beginning of period$2,988 $970 
Liabilities assumed in leasehold acquisitions121 — 
Liabilities incurred389 87 
Liabilities settled(150)(10)
Accretion expense268 101 
Revision to estimated cash flows20 1,840 
Asset retirement obligations, end of period$3,636 $2,988 
An asset retirement obligation represents a legal obligation associated with the retirement of a tangible long-lived asset in which the timing and/or method of settlement may or may not be conditional on a future event that may or may not be within our control. The liability is initially measured as the present value of the estimated future costs associated with plugging and abandonment of oil and natural gas wells and other equipment removal, and land restoration activities. Upon initially recognizing the liability, the Company capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period through accretion expense and the capitalized cost is depleted over the units-of-production method as part of the full cost pool. Accretion expense is included as part of depreciation, depletion, and amortization in the consolidated statements of operations.
Inherent in the fair value calculation of asset retirement obligations are numerous estimates and assumptions including plugging and abandonment settlement amounts, inflation rates, credit-adjusted risk-free rates, and the timing of settlement. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable. During 2025, the Company recorded changes in estimates attributable primarily to changes in working interest. During 2024, the Company recorded changes in estimates attributable primarily to increased plugging costs.
v3.25.4
Debt
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Debt Debt
On September 25, 2024, INR Holdings entered into a credit facility led by Citibank, N.A. (the “Credit Facility” and the credit agreement governing the Credit Facility, as amended, the “Credit Agreement”) with a syndicate of financial institutions with an initial aggregate elected commitment amount and initial borrowing base of $325.0 million. On March 31, 2025, the Company amended the Credit Agreement to, among other things, increase each of the aggregate elected commitment amount and borrowing base from $325.0 million to $350.0 million. On May 29, 2025, the Company amended the Credit Agreement to, among other things, amend certain provisions relating to hedging requirements and restrictions in the Credit Agreement. Effective October 1, 2025, the borrowing base under the Credit Facility was increased from $350.0 million to $375.0 million and the aggregate elected commitment amount was also increased from $350.0 million to $375.0 million.

On December 5, 2025, INR Holdings entered into that certain Third Amendment to Credit Agreement, which among other things, amended certain provisions relating to hedging requirements and restrictions, debt incurrences and permitted acquisitions in the Credit Agreement. The borrowing base is based on the net present value of our oil and gas properties and is subject to semi-annual redeterminations. The Credit Facility is guaranteed by INR Holdings’ subsidiaries and is secured by first priority security interests on substantially all of INR Holdings’ consolidated assets.
Borrowings under the Credit Facility may be base rate loans or Secured Overnight Financing Rate (“SOFR”) loans. Base rate loans bear interest at a rate per annum equal to the greater of: (i) the administrative agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted Term SOFR rate (as defined in the Credit Agreement), plus an additional basis point credit spread, plus an applicable margin ranging from 275 basis points to 375 basis points, depending on the percentage of the borrowing base utilized. SOFR loans bear interest at SOFR plus an applicable margin ranging from 275 basis points to 375 basis points, depending on the percentage of the borrowing base utilized, plus an additional basis point credit spread. We also pay a commitment fee on unused elected commitment amounts under the Credit Facility, which is also dependent on the percentage of the borrowing base utilized. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. The Credit Facility matures in September 2028. As of December 31, 2025, the Company’s reserves supported a $375.0 million borrowing base of which $150.9 million was outstanding, leaving $224.1 million of unused capacity.
For the years ended December 31, 2025 and 2024, total interest expense on the Credit Facility was $7.8 million and $19.1 million, respectively. We did not capitalize any interest expense for the years ended December 31, 2025 and 2024. For the years ended December 31, 2025 and 2024, the Company’s weighted-average interest rate was 7.2% and 8.3%, respectively.
Debt issuance costs associated with the Credit Facility are capitalized and presented as other assets within the unaudited condensed consolidated balance sheets. Debt issuance costs are amortized using the straight-line method over the term of the related agreement. We capitalized an additional $1.1 million of debt issuance costs related to the Credit Facility for the year ended December 31, 2025. As of December 31, 2025 and December 31, 2024, capitalized debt issuance costs were approximately $6.7 million and $7.9 million, respectively. Amortization of debt issuance costs, which is included within interest expense in the consolidated statements of operations, was approximately $2.3 million and $2.4 million for the years ended December 31, 2025 and 2024, respectively.
The Credit Facility also requires INR Holdings to maintain compliance with financial ratios including a current ratio of not less than 1.0 to 1.0 and a leverage ratio no greater than 3.0 to 1.0, each of which is defined within the terms of the Credit Agreement. INR Holdings is in compliance with the covenants and financial ratios under the Credit Agreement described above through the date these audited consolidated financial statements were available to be issued.
Other Long-Term Debt
Other long-term debt principally relates to car loans associated with our car fleet to support service and maintenance of our operated wells.
Payments due by fiscal year related to other long-term debt as of December 31, 2025 are as follows:
 Notes Payable
(in thousands)
2026$40 
202715 
2028— 
2029— 
2030— 
Total payments$55 
v3.25.4
Derivatives and Risk Management
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivatives and Risk Management Derivatives and Risk Management
We are exposed to volatility in market prices and basis differentials for oil, natural gas, and NGLs, which impacts the predictability of our cash flows related to the sale of those commodities. The overall objective of our hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices, which we do by using various derivative instruments including fixed price swaps, basis swaps, and collars. As a result of our hedging activities, we may realize prices that are greater or less than the market prices that we would have otherwise received.
We typically enter into over the counter (OTC) derivative contracts with financial institutions and regularly monitor the creditworthiness of all counterparties. Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our Credit Facility. As of December 31, 2025, we did not have any cash or letters of credit posted as collateral for our derivative financial instruments.
We do not designate any of its derivative instruments as cash flow hedges; therefore, all changes in fair value of our derivative instruments are recognized in other income within the consolidated statements of operations. We recognize all derivative instruments as either assets or liabilities at fair value within the consolidated balance sheets, subject to master netting arrangements that permit the net settlement of derivative assets and liabilities.
Contracts that result in physical delivery of a commodity expected to be sold by us in the normal course of business are generally designated as normal purchases and normal sales and are exempt from derivative accounting. Contracts that result in the physical receipt or delivery of a commodity but are not designated or do not meet all of the criteria to qualify for the normal purchase and normal sale scope exception are subject to derivative accounting.
The following tables provide information about our derivative financial instruments. The tables present the notional amount, the weighted average contract prices and the fair values by expected maturity dates as of December 31, 2025.
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Oil(in MBbls)
($ per Bbl)
(in thousands)
Fixed price swaps
20261,540$64.06 $10,777 
202797$63.95 683 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total
1,637$11,460 

 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Natural gas(in MMBtu)
($ per MMBtu)
(in thousands)
Fixed price swaps
202650,726,000$3.86 $16,467 
202745,438,000$3.94 1,969 
202835,967,000$3.77 917 
202930,320,000$3.62 194 
203026,580,000$3.57 (1,276)
20312,120,000$4.08 (169)
Total
191,151,000$18,102 
 VolumeBasis DifferentialFair Value as of
December 31, 2025
Natural gas(in MMBtu)($ per MMBtu)(in thousands)
Basis swaps
202653,439,000$(0.89)$(6,850)
202731,629,000$(0.64)(1,717)
202832,603,750$(0.52)(1,178)
20292,607,500$(0.30)(78)
2030—$— — 
2031—$— — 
Total120,279,250$(9,823)
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Ethane(in gallons)($ per gallon)(in thousands)
Fixed price swaps
20268,604,000$0.28 $282 
2027708,000$0.30 14 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total
9,312,000$296 
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Propane(in gallons)($ per gallon)(in thousands)
Fixed price swaps
202619,377,000$0.71 $2,008 
20271,524,000$0.71 103 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total20,901,000$2,111 
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Isobutane(in gallons)($ per gallon)(in thousands)
Fixed price swaps
20263,498,000$0.84 $98 
2027276,000$0.83 4 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total3,774,000$102 
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Normal butane(in gallons)($ per gallon)(in thousands)
Fixed price swaps
20265,743,000$0.82 $397 
2027455,000$0.82 19 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total6,198,000$416 
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Pentane(in gallons)($ per gallon)(in thousands)
Fixed price swaps
20262,487,000$1.38 $553 
2027190,000$1.34 39 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total2,677,000$592 
Derivative assets and liabilities are presented below as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in the accompanying balance sheets.
The following table summarizes the gross fair value of our derivative assets and liabilities and the effect of netting as of December 31, 2025 and 2024:
 December 31, 2025
Balance Sheet ClassificationGross Amounts
Netting Adjustment
Net Amounts Presented on Balance Sheet
(in thousands)
Assets
Commodity derivative assets, short-term$32,718 $(7,880)$24,838 
Commodity derivative assets, long-term7,701 (4,816)2,885 
Total assets$40,419 $(12,696)$27,723 
Liabilities
Commodity derivative liabilities, short-term$8,986 $(7,880)$1,106 
Commodity derivative liabilities, long-term8,177 (4,816)3,361 
Total liabilities$17,163 $(12,696)$4,467 
 December 31, 2024
Balance Sheet ClassificationGross Amounts
Netting Adjustment
Net Amounts Presented on Balance Sheet
(in thousands)
Assets
Commodity derivative assets, short-term$6,089 $(6,089)$— 
Commodity derivative assets, long-term2,647 (2,647)— 
Total assets$8,736 $(8,736)$— 
Liabilities
Commodity derivative liabilities, short-term$18,685 $(6,089)$12,596 
Commodity derivative liabilities, long-term12,989 (2,647)10,342 
Total liabilities$31,674 $(8,736)$22,938 
Our total derivative gains and losses for the years ended December 31, 2025, 2024 and 2023 were as follows:
 For the Year Ended December 31,
(in thousands)202520242023
Realized gain on derivative instruments$12,213 $28,360 $19,438 
Unrealized gain (loss) on derivative instruments46,194 (50,407)25,884 
Total gain (loss) on derivative instruments$58,407 $(22,047)$45,322 
v3.25.4
Fair Value Measurements
 12 Months Ended
Dec. 31, 2025
Fair Value Disclosures [Abstract]  
Fair Value Measurements Fair Value Measurements
Certain of our assets and liabilities are measured at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. In determining fair value, we use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.
The carrying values of cash and cash equivalents, including accounts receivable, other current assets, accounts payable and other current liabilities approximate fair value due to their short-term nature. The carrying value of outstanding borrowings under the Credit Facility approximates fair value because the interest rates are variable and reflective of market rates. The estimated fair value of borrowings under the Credit Facility would be categorized as a Level 2 measurement within the fair value hierarchy.
We follow ASC Topic 820, Fair Value Measurement (“ASC 820”), which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
•Level 1: Quoted Prices in Active Markets for Identical Assets - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
•Level 2: Significant Other Observable Inputs - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets (other than quoted prices included within Level 1), and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
•Level 3: Significant Unobservable Inputs - inputs to the valuation methodology are unobservable but should reflect the assumptions that market participants would use when pricing the asset or liability, including assumptions about risk (consistent with the fair value measurement objective).
Recurring Fair Value Measurements
The following table presents, for each applicable level within the fair value hierarchy, our net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis.
 December 31, 2025
 Level 1Level 2Level 3Fair Value
(in thousands)
Assets
Fixed price swaps$— $33,079 $— $33,079 
Basis swaps— 349 — 349 
Liabilities
Fixed price swaps— — — — 
Basis swaps— (10,172)— (10,172)
Total$— $23,256 $— $23,256 
 December 31, 2024
 Level 1Level 2Level 3Fair Value
(in thousands)  
Assets
Fixed price swaps
$— $4,012 $— $4,012 
Basis swaps
— — — — 
Liabilities
Fixed price swaps
— (13,685)— (13,685)
Basis swaps
— (13,263)— (13,263)
Total
$— $(22,938)$— $(22,938)
Derivative assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. We have classified our derivative instruments into levels depending upon the data utilized to determine their fair values. The Company uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. As such, the Company classifies the fair value of its commodity derivative contract within Level 2 of the fair value hierarchy.
Nonrecurring Fair Value Measurements
Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include asset retirement obligations when incurred and other long-lived assets that are written down to fair value when they are impaired. The Company did not record any impairment charge related to these assets and liabilities for the years ended December 31, 2025 and December 31, 2024.
v3.25.4
Income Taxes and Tax Receivable Agreement
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Income Taxes and Tax Receivable Agreement Income Taxes and Tax Receivable Agreement
Tax Provision. As a result of the IPO and related Corporate Reorganization, Infinity became the sole managing member of INR Holdings, which is treated as a partnership for U.S. federal and certain state and local income tax purposes. As a partnership, INR Holdings is not subject to U.S. federal income tax at the entity level. Instead, taxable income or loss generated by INR Holdings is allocated to its members, including the Company, and is reported on the respective tax returns of those members.
Our predecessor, INR Holdings, is a limited liability company treated as a partnership for U.S. federal income tax purposes and, therefore, has not been subject to U.S. federal income tax at an entity level. As a result, the consolidated net income (loss) in our historical financial statements for periods prior to the IPO and Corporate Reorganization does not reflect the tax expense (benefit) we would have incurred if we were subject to U.S. federal income tax at an entity level during those periods.
Beginning with the IPO, the Company is subject to U.S. federal income taxes and state and local income taxes with respect to its allocable share of taxable income or loss of INR Holdings, as well as any stand‑alone income or loss generated at the Company level. Prior to the IPO and Corporate Reorganization, INR Holdings operated as a limited liability company treated as a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax at the entity level. As a result, the consolidated net income (loss) in the historical financial statements for periods prior to the IPO does not reflect the income tax expense (benefit) that would have been incurred if the Company had been subject to U.S. federal income tax during those periods.
Year Ended December 31,
202520242023
Current tax expense (benefit)
Federal $— $— $— 
State$— $— $— 
Total current tax expense (benefit)$— $— $— 
Deferred tax expense (benefit)
Federal $(4,668)$— $— 
State$(190)$— $— 
Total deferred tax expense (benefit)$(4,858)$— $— 
Total income tax expense (benefit)$(4,858)$— $— 
Effective Tax Rate. The Company's overall effective tax rate differs from the U.S statutory rate primarily due to the fact that prior to the IPO, INR Holdings was structured as a partnership for U.S. federal income tax and subsequent to the IPO, the income (loss) attributable to the non-controlling interests in INR Holdings is not subject to U.S. federal income tax at the Company or INR Holdings. In addition, the Company reduced its valuation allowance with respect to investment in INR Holdings as discussed further below. As a result of the Company’s Up‑C organizational structure, the allocation of income to non‑controlling interests, and valuation allowance activity, the Company’s effective tax rate for the year ended December 31, 2025 is not indicative of the effective tax rate that may be expected in future periods.
In connection with the IPO, the Company recorded a deferred tax asset of $16.8 million resulting from its purchase of INR Units in INR Holdings. The deferred tax asset results from the difference between the Company's outside basis in its investment in INR Holdings compared to its share of the net financial statement carrying value of the assets of INR Holdings. At the time of the IPO, we determined that the deferred tax asset associated with the investment in INR Holdings was not more likely than not to be realized and recorded a valuation allowance of $16.8 million. The initial deferred tax asset of $16.8 million for the investment in INR Holdings and the related valuation allowance of $16.8 million are recorded against additional paid-in capital in the condensed consolidated statements of redeemable non-controlling interest and stockholders’ / members’ equity.
During the year ended December 31, 2025, the Company’s taxable income attributable to its interest in INR Holdings was lower than its share of book income, which reduced the Company’s deferred tax asset related to its investment in INR
Holdings. As a result, a corresponding reduction in the valuation allowance was recorded through income tax benefit in the consolidated statements of operations.
The reconciliation of income taxes at the federal statutory level to provision for income taxes is as follows:
Year Ended December 31,
202520242023
$%$%$%
U.S. federal tax expense (benefit) at statutory rate$12,429 21 %$— 21 %$— 21 %
State tax, net of federal benefit$(150)— %$— — %$— — %
Pre-Offering non-taxable/deductible income$24,407 41 %$— — %$— — %
Non-controlling interests$(27,520)(47)%$— — %$— — %
IPO Underwriting Fees$— — %$— — %$— — %
Non-Deductible expenses$291 1 %$— — %$— — %
Percentage Depletion$(575)(1)%$— — %$— — %
Change in Valuation Allowance$(13,741)(23)%$— — %$— — %
Total income tax expense (benefit)$(4,858)(8)%$— 21 %$— 21 %
Deferred Tax Assets and Liabilities. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses and other tax carryforwards, using enacted tax rates in effect for the taxing jurisdictions in which the Company operates for the year in which those temporary differences are expected to be recovered or settled.
The tax effects of each temporary difference and carryforward as of December 31, 2025 and December 31, 2024 are as follows:
Year Ended December 31,
20252024
Deferred tax assets:
Net operating losses$4,054 $— 
Investment in partnership$2,298 $— 
Disallowed depletion carryforward$804 $— 
Total deferred tax assets:$7,157 $— 
Deferred tax liabilities:
Valuation allowance$(2,298)$— 
Net deferred tax asset (liabilities)$4,858 $— 
The Company evaluates all deferred tax assets as to their future realization using positive and negative evidence. As of December 31, 2025, the Company has recorded a full valuation allowance against its deferred tax asset associated with its investment in INR Holdings. The Company carries a deferred tax asset on its net operating losses at the federal and Pennsylvania level. These net operating losses do not expire. The Company has determined that it is more likely than not to realize all of the tax benefits associated with its net operating losses due to the lack of expiration of the net operating losses, positive book income in 2025, and projected income in future years.
During the year ended December 31, 2025, members of INR Holdings redeemed 0.4 million INR Holdings Units (together with the cancellation of 0.4 million shares of Class B common stock) for an equivalent number of shares of Class A common stock. As a result of this redemption, there was minimal change in the Company's deferred tax asset position. Because the deferred tax change arose in connection with a transaction between the Company and stockholders, the initial change in deferred tax asset, as well as the impact on the Company's valuation allowance, is recorded in additional paid-in capital in the condensed consolidated statements of redeemable non-controlling interest and stockholders’ / members’ equity.
The Company evaluates uncertain tax positions for recognition and measurement in the financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. As of December 31, 2025, the Company has no significant uncertain tax positions.
The Company files income tax returns in the U.S. federal jurisdiction and Pennsylvania on a separate basis. There are currently no federal or state income tax examinations underway for these jurisdictions. The Company's federal and state returns remain open to examination for tax years 2024 and 2025.
Taxes Paid by Jurisdiction. For the years ended December 31 2025, 2024 and 2023, neither INR Holdings nor the Company paid any entity level U.S. federal, state or foreign income taxes.
Tax Receivable Agreement. We entered into the TRA with the Legacy Owners in connection with the IPO. This agreement generally provides for the payment by us to the Legacy Owners of 85% of the net cash savings, if any, in U.S. federal, state and local income tax that we (a) actually realize with respect to taxable periods ending after the IPO or (b) are deemed to realize in the event of a change of control (as defined under the TRA, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of our board of directors) or the TRA terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of INR Units and the corresponding surrender of an equivalent number of shares of Class B common stock by the Legacy Owners for a number of shares of Class A common stock on a one-for-one basis or, at our option, the receipt of an equivalent amount of cash pursuant to the INR Holdings LLC Agreement and (ii) deductions arising from imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the TRA. We will retain the benefit of the remaining 15% of these cash savings, if any.
On August 15, 2025 a Legacy Owner redeemed 390,915 INR Units for shares of Class A common stock on a one-for-one basis. Concurrently with the redemption of the INR Units, an equal number of shares of Class B common stock were cancelled. The Company recognizes a liability for the estimated amounts payable under the TRA when it is probable that taxable income will be sufficient to realize the related tax benefits and the amounts can be reasonably estimated. The estimation of liability under the TRA is by its nature imprecise and subject to significant assumptions regarding the amount, character, and timing of the taxable income of the Company in the future. Changes in tax laws or rates could also materially impact the estimated liability. As of December 31, 2025, the Company recorded a TRA liability of $1.5 million, all of which has been classified as a non-current liability.
v3.25.4
Stockholders' Equity and Noncontrolling Interest
 12 Months Ended
Dec. 31, 2025
Equity [Abstract]  
Stockholders' Equity and Noncontrolling Interest Stockholders' Equity and Noncontrolling Interest
Predecessor Members’ Equity
Prior to the Corporate Reorganization, INR Holdings had two classes of equity in the form of Class A and Class B interests, and non-voting, performance-based incentive units (“Incentive Units”) that were issued to certain members of management. Profits and losses for both Class A and Class B interests were determined and allocated among each equity interest holder in a manner such that the adjusted capital account of each equity interest holder was as nearly as possible equal to the distributions that would have been made to such equity interest holder if certain transactions occurred based on each equity interest holders proportionate ownership interest.
Distributions to holders of Class A interests, Class B interests and Incentive Units were made in accordance with the INR Holdings Amended and Restated Limited Liability Company Agreement (as amended, the “Amended and Restated LLC Agreement”), which were provided first to holders of Class A interests and then to Class B interests. Distributions to holders of Incentive Units were made upon the occurrence of each respective Incentive Unit Tier’s Payout per each respective Incentive Unit Tier (each as defined in the Amended and Restated LLC Agreement).
At the time of the Corporate Reorganization, Class A interests, Class B interests, and Incentive Units were issued and outstanding. As a result of the Corporate Reorganization, all Class A interests, Class B interests, and Incentive Units were exchanged for INR Units and an equal number of shares of Class B common stock, and no Class A interests, Class B interests, or Incentive Units remain issued or outstanding.
Stockholders’ Equity
As a result of the Corporate Reorganization, the membership interests of the Legacy Owners in INR Holdings were recapitalized into INR Units, and, in exchange for their existing membership interests, the Legacy Owners received 45,638,889 INR Units and an equal number of shares of our Class B common stock. We contributed the net proceeds of the IPO to INR Holdings in exchange for 15,237,500 newly issued INR Units and a managing member interest in INR Holdings. We own an approximate 74.4% interest in INR Holdings and the Legacy Owners own an approximate 25.6% interest in INR Holdings.
As of December 31, 2025, the Company’s equity structure consists of Class A common stock and Class B common stock. Each share of Class A common stock entitles its holder to one vote per share and the right to receive dividends and other distributions when, as, and if declared by our board of directors. Class A stockholders are also entitled to share in any assets remaining upon liquidation, after satisfaction of all debts and liabilities. Holders of Class A common stock do not have preemptive or conversion rights. The Class A common stock is economically entitled to the results of operations of the Company, through its ownership interest in INR Holdings.
Each share of Class B common stock entitles its holder to one vote per share on matters submitted to the Company’s stockholders but does not provide the holder with economic rights. Class B common stockholders do not participate in dividends or other distributions and have no rights to Company assets upon liquidation. Each share of Class B common stock is paired with one INR Unit and is cancellable upon exchange or redemption of the corresponding INR Unit for one share of Class A common stock or, at our option, the receipt of an equivalent amount of cash. INR Units represent economic interests in INR Holdings.
Distributions by INR Holdings, if any, are made to the holders of INR Units on a pro rata basis, subject to applicable law and the INR Holdings LLC Agreement. Distributions, if any, are expected to be made to fund the Company’s payment of taxes, payments under the TRA, any dividends declared on Class A common stock, and other corporate purposes.
As of December 31, 2025, the Company consolidates the financial results of INR Holdings in its consolidated financial statements. The portion of net income and equity attributable to the INR Units held by the Legacy Owners is reported as a redeemable non-controlling interest within mezzanine equity in the consolidated financial statements.
v3.25.4
Share-based Compensation
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Share-based Compensation Share-based Compensation
INR Holdings Incentive Plan
In connection with the closing of the IPO, INR Holdings’ members elected to accelerate the vesting of certain Incentive Units. The Incentive Units were originally issued by INR Holdings and were accounted for under ASC 710. As a result of the acceleration, all unvested Incentive Units vested and were recapitalized into INR Units at a valuation of $20.00 per unit, which reflects the IPO price of the Company’s Class A common stock. This recapitalization resulted in the recognition of $126.1 million of non-recurring compensation expense for the year ended December 31, 2025 and is recorded within the consolidated statement of operations as a component of General and administrative.
Omnibus Incentive Plan
In connection with the IPO, the Company adopted the Infinity Natural Resources, Inc. Omnibus Incentive Plan (the “Plan”). The Plan provides for the grant of stock-based awards to the Company’s employees, non-employee directors, and consultants, including restricted stock units (“RSUs”), performance stock units (“PSUs”), stock options, stock appreciation rights, restricted stock, dividend equivalent rights and other stock or stock-based awards. An aggregate of 5,888,889 shares of Class A common stock have been reserved for issuance under the Plan, subject to adjustments for stock splits, recapitalizations, and other corporate events. We recognize share-based compensation expense in the consolidated statement of operations as a component of General and administrative.
Restricted Stock Units
In connection with the closing of IPO, the Company granted 162,500 RSUs to employees under the Plan. These RSUs vest in full after one year of continuous service. In March and April 2025, the Company granted an additional 311,991 RSUs to certain employees and non-employee directors under the Plan. In July 2025, the Company granted an additional 10,086 RSUs to an employee under the Plan. The RSUs granted to employees generally vest ratably over a three-year service period, while the RSUs granted to non-employee directors vest in full on the earlier of (i) the one year anniversary and (ii) the Company's next annual stockholder meeting.
In July and August 2025, the Company accelerated the vesting of 1,779 RSUs awarded to certain former employees based on a pro rata allocation of the service period completed through the date of their respective terminations of employment. This accelerated vesting did not result in any incremental fair value, and therefore, no additional compensation expense was recognized. Upon vesting, the Company issued 1,238 shares of Class A common stock, net of shares withheld to cover employee tax obligations.
The grant-date fair value of each RSU is determined based on the closing stock price of the Company’s Class A common stock on the grant date. Share-based compensation expense related to RSUs is recognized on a straight-line basis over the requisite service period, which corresponds to the vesting terms of the respective awards. We account for forfeitures as they occur. The following table summarizes the RSU activity for the year ended December 31, 2025:
RSUs
Weighted-average grant date fair value
Unvested as of beginning of period—
Granted485,558$18.12
Vested and settled(1,779)$18.33
Canceled/Forfeited(50,297)$17.67
Unvested as of end of period433,482$18.17
The RSUs are entitled to Dividend Equivalent Rights (as defined in the Plan) on unvested RSUs, which are payable only if the underlying RSUs vest. The Company recognized compensation expense for RSUs of $4.7 million for the year ended December 31, 2025.
As of December 31, 2025, unrecognized compensation expense related to unvested RSU awards was $3.2 million, which is expected to be recognized over a weighted-average remaining service period of 1.1 years.
Performance Stock Units
In March 2025, the Company granted 455,601 PSUs under the Plan to certain employees. The PSUs are subject to a performance period from the grant date to December 31, 2027. Vesting is based on the Company's Total Shareholder Return (“TSR”) relative to a defined peer group and the Company's absolute TSR over the performance period. The number of PSUs that may vest ranges from 0% to 300% of the target award, depending on performance outcomes.
The grant-date fair value of the PSUs was estimated using a Monte Carlo simulation model, which reflects the probability of achieving various market-based outcomes and incorporates key assumptions such as expected volatility, risk-free interest rate, expected dividend yield and correlation with the peer group.
2025
Expected volatility40.00%
Risk-free rate4.04%
Expected dividend yield—%
Correlation with peer group range
45.00% - 68.00%
The fair value was determined on the grant date and will not be remeasured. Compensation expense for the PSUs is recognized on a straight-line basis over the requisite service period, which begins on the grant date and ends on the certification date. Expense is recognized regardless of whether the market conditions are ultimately achieved, provided the service condition is satisfied. The Company accounts for forfeitures as they occur. The PSUs are entitled to Dividend Equivalent Rights (as defined in the Plan) on unvested PSUs, which are payable only if the underlying PSUs vest. The following table summarizes the PSU activity for the year ended December 31, 2025:
PSUs
Weighted-average grant date fair value
Unvested as of beginning of period—
Granted455,601$22.20
Vested—
Canceled/Forfeited(29,019)22.20
Unvested as of end of period426,582$22.20
The Company recognized compensation expense for PSUs of $2.5 million for the year ended December 31, 2025, respectively.
As of December 31, 2025, unrecognized compensation expense related to unvested PSU awards was $6.9 million, which is expected to be recognized over a weighted-average remaining service period of 2.2 years.
v3.25.4
Earnings Per Share
 12 Months Ended
Dec. 31, 2025
Earnings Per Share [Abstract]  
Earnings Per Share Earnings Per Share
Basic earnings (loss) per share is calculated by dividing net (loss) income attributable to Infinity Natural Resources, Inc. by the weighted average number of shares of Class A common stock outstanding during the period. Diluted net (loss) earnings per share gives effect, when applicable, to unvested RSUs and PSUs granted under the Plan and the exchange INR Units (and the cancellation of an equal number of shares of Class B common stock) held by the Legacy Owners into Class A common stock.
The following table summarizes the calculation of weighted average shares of Class A common stock outstanding used in the computation of diluted loss per share:
For the Year Ended December 31, 2025For the Year Ended December 31, 2024
(in thousands, except per share amounts)
Net income attributable to Infinity Natural Resources, Inc.$13,836$—
Net income attributable to redeemable non-controlling interests$40,209$—
Diluted net income attributable to Infinity Natural Resources, Inc.$54,045$—
Weighted average number of Class A common stock outstanding:
Basic15,382,681—
Effect of dilutive securities:
INR Units45,491,091—
RSUs80,867—
PSUs——
Diluted60,954,6390
Net income attributable to Infinity Natural Resources, Inc. per share of Class A common stock
Basic$0.90$—
Diluted$0.89$—
The calculation of diluted net income per share for the year ended December 31, 2025 excludes (i) the exchange of INR Units (and the cancellation of an equal number of shares of Class B common stock) to Class A common stock and (ii) 433,482 and 426,582 unvested RSUs and PSUs, respectively.
v3.25.4
Commitment and Contingencies
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Commitments and Contingencies
South Bend Utica Farmout Agreement. On March 2, 2018, INR Holdings entered into an Exploration and Development Agreement and Farm Out Agreement (collectively, the “South Bend Utica Development Agreements”) with Dominion Energy Transmission, Inc. (“Dominion”) covering approximately 11,000 acres in Armstrong and Indiana Counties, Pennsylvania targeting the Utica Shale horizon. This acreage underpins our acreage position at South Bend for Utica development.
The South Bend Utica Development Agreements had an initial term of 15 years and require the drilling of one (1) seven thousand foot lateral into the Utica formation. As of December 31, 2025, we had yet to satisfy that obligation and have approximately 9 years remaining to meet its obligation.

Minimum Future Commitments
The following table summarizes our future commitments related to these oil and natural gas transportation and gathering agreements as of December 31, 2025:
 As of December 31, 2025
 20262027202820292030 and
thereafter		Total
(in thousands)  
Total minimum future volume commitments14,093 13,346 13,962 12,677 13,418 67,496 
Total minimum future service commitments5,850 — — — — 5,850 
Total minimum future commitments$19,943 13,346 13,962 12,677 13,418 $73,346 
Lease Commitments. Refer to Note 6 – “Leases” for details on our operating lease agreements. We do not have any finance lease obligations.
Litigation. From time to time, we are party to various legal and/or regulatory proceedings arising in the ordinary course of business. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that all such matters
are without merit and involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material effect on our financial condition, results of operations or cash flows.
When it is determined that a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at the time. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.
v3.25.4
Segment Information
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Segment Information Segment Information
The Company has one reportable segment, which is engaged in the acquisition, exploration, development and production of crude oil and natural gas in the United States. All of the Company’s oil and natural gas sales come from customers in the United States. The segment’s revenues are primarily derived from our interests in the sales of crude oil and natural gas production. The Company’s chief operating decision maker (“CODM”) is our chief executive officer, who manages the Company’s business activities as a single operating and reporting segment.
The accounting policies of the one reportable segment are the same as those described in the summary of significant accounting policies. The CODM uses net income, as reported in our statement of operations, to measure segment profit or loss, assess performance, and make strategic capital resources allocations. The measure of segment assets is reported on our balance sheet as total assets. The significant expense categories regularly provided to the CODM are the expenses as noted on the face of the statements of operations.
The following table provides information about the Company’s one reportable segment and includes the reconciliation to consolidated net income:
 For the Year Ended December 31,
 202520242023
Total revenues356,431 259,022 161,730 
Less:
Gathering, processing, and transportation54,779 49,290 31,097 
Lease operating26,675 28,154 18,371 
Production and ad valorem taxes5,918 1,071 886 
Depreciation, depletion, and amortization103,751 73,726 53,796 
General and administrative153,413 13,045 4,885 
Other segment (income)/expenses(1)
(52,064)44,450 (33,977)
Segment income$63,959 $49,286 $86,672 
Other segment (income) / expenses are comprised of net interest expense of $9,666, 21,529 and 11,910 for December 31, 2025, 2024 and 2023, respectively, gain/(loss) on derivative instruments of $58,407, (22,047) and 45,322 for December 31, 2025, 2024 and 2023, respectively, other income/(loss) of $(1,535), (874) and 565 for December 31, 2025, 2024 and 2023, respectively, and Income tax expense / (benefit) of $(4,858) and $0 for December 31, 2025, 2024 and 2023.
v3.25.4
Subsequent Events
 12 Months Ended
Dec. 31, 2025
Subsequent Events [Abstract]  
Subsequent Events Subsequent Events
Chase Acquisition. On January 20, 2026, the Company and INR Holdings completed the acquisition of certain non‑operated rights, title, and interests in oil and gas properties and related assets located in the South Bend Field in the State of Pennsylvania (the “Chase Acquisition”). The Chase Acquisition was completed pursuant to a purchase and sale agreement entered into with Chase Oil Corporation and certain other sellers.
The consideration for the Chase Acquisition consisted of the issuance of 2,517,194 shares of the Company’s Class A common stock.
The Chase Acquisition was completed subsequent to December 31, 2025 and, accordingly, the accompanying consolidated financial statements do not reflect the results of operations, financial position, or cash flows of the acquired interests.
Upstream and Midstream Asset Acquisition. On February 23, 2026, INR Holdings and Northern Oil and Gas, Inc. (“Northern” and, together with INR Holdings, the “Buyers”) completed their previously announced acquisitions (collectively, the “Antero Acquisitions”) of upstream and midstream assets located in the State of Ohio pursuant to separate purchase and sale agreements dated December 5, 2025, as amended on February 22, 2026.

Pursuant to the amended upstream purchase agreement, INR Holdings and Northern acquired certain rights, title, and interests in upstream oil and gas properties and related assets located in the State of Ohio (the “Upstream Assets”) from Antero Resources Corporation, Antero Minerals LLC, and Monroe Pipeline LLC (collectively, the “Upstream Sellers”). INR Holdings acquired an undivided 60% interest in the Upstream Assets, and Northern acquired an undivided 40% interest. The aggregate cash purchase price for the Upstream Assets was approximately $800 million, subject to customary post‑closing adjustments.
Pursuant to the amended midstream purchase agreement, INR Holdings and Northern acquired certain gathering, compression, and transportation systems, water facilities and systems, equipment, and related assets located in Belmont, Guernsey, Monroe, Noble, and Washington Counties, Ohio (the “Midstream Assets”) from Antero Midstream LLC, Antero Water LLC, and Antero Treatment LLC (collectively, the “Midstream Sellers”). INR Holdings acquired an undivided 60% interest in the Midstream Assets, and Northern acquired an undivided 40% interest. The aggregate cash purchase price for the Midstream Assets was approximately $400 million, subject to customary post‑closing adjustments.
The Antero Acquisitions were completed subsequent to December 31, 2025 and, accordingly, the accompanying consolidated financial statements do not reflect the results of operations, financial position, or cash flows of the acquired assets.
Issuance of Preferred Stock. On February 23, 2026, the Company issued and sold an aggregate of 350,000 shares of Series A Convertible Preferred Stock of the Company, par value $0.01 per share (the “Series A Preferred Stock”) for gross proceeds of approximately $350 million. After deducting placement agent fees, Infinity received net proceeds of approximately $337.1 million. Of these shares, affiliates of Quantum Capital Group acquired 275,000 shares and affiliates of Carnelian Energy Capital Management, L.P. acquired 75,000 shares (each a “Preferred Purchaser” and, collectively, the “Preferred Purchasers”).
The proceeds from the issuance of the Series A Preferred Stock were used to fund a portion of the Antero Acquisitions, with any remaining proceeds to be used for general corporate purposes. The issuance of the Series A Preferred Stock occurred subsequent to December 31, 2025 and, accordingly, the accompanying consolidated financial statements do not reflect the impact of this transaction.
In connection with the issuance of the Series A Preferred Stock, the Company (i) entered into a registration rights agreement with the Preferred Purchasers, pursuant to which the Preferred Purchasers have certain customary registration rights, including rights with respect to the filing of a shelf registration statement, underwritten offering rights and piggyback rights with respect to any shares of Class A common stock of the Company issuable upon conversion of the Series A Preferred Stock, and (ii) amended the INR Holdings LLC Agreement to create a class of convertible preferred units with rights, preferences and privileges that mirror the Series A Preferred Stock. The Company filed a certificate of designation with the Secretary of State of the State of Delaware on February 23, 2026 setting forth the powers, designations, preferences, and other rights of the shares of Series A Preferred Stock.
Amendment to Credit Agreement. On February 23, 2026, INR Holdings entered into a fourth amendment to the Credit Agreement. The fourth amendment, among other things, increased the aggregate elected commitment and borrowing base under the Credit Agreement from $375.0 million to $875.0 million and removed the credit spread adjustment previously applicable to SOFR borrowings. The amendment to the Credit Agreement was completed subsequent to December 31, 2025 and, accordingly, the accompanying consolidated financial statements do not reflect the impact of this amendment.
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)
Capitalized Costs
The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion, and amortization are shown below:
 December 31,
 202520242023
(in thousands)   
Proved properties(1)
$1,175,523 $846,738 $615,456 
Unproved properties88,689 86,490 37,189 
Total proved and unproved properties1,264,212 933,228 652,645 
Accumulated depreciation, depletion, and amortization(249,296)(148,638)(77,085)
Net capitalized costs$1,014,916 $784,590 $575,560 
(1)Includes asset retirement costs of $3.3 million, $2.7 million and $0.8 million as of December 31, 2025, 2024 and 2023, respectively.
Costs Incurred for Oil and Natural Gas Producing Activities
Our capital costs incurred for acquisition and development activities are shown below:
December 31,
202520242023
(in thousands)
Acquisition costs:
Proved properties
$44,585 $19,172 $274,732 
Unproved properties
5,236 89,174 1,047 
Development costs
274,723 165,795 144,121 
Exploration costs
— — — 
$324,544 $274,141 $419,900 
Estimated Quantities of Proved Oil and Gas Reserves
The reserve estimates presented below and included herein conform to the definitions prescribed by the SEC. We retained Wright & Company, Inc., an independent petroleum engineering firm, to prepare the estimates of all of its proved reserves as of December 31, 2025, 2024, and 2023 and their related pre-tax future net cash flows. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
Reserve estimates are based on an unweighted arithmetic average of commodity prices during the 12-month period, using the closing prices on the first day of each month, as defined by the SEC.
As of December 31, 2025, all of our oil and gas reserves are attributable to properties within the United States. The table below presents a summary of changes in quantities of proved oil and gas reserves in our estimated proved reserves:
 Crude Oil (MBbls)Natural Gas (MMcf)
Natural Gas Liquids (MBbls)
Total (MBoe)
Total proved reserves:
December 31, 20225,913358,33714,15279,788
Extensions7,443168,7049,01544,575
Revisions to previous estimates252(118,920)(4,501)(24,069)
Purchases of reserves in place18,636128,1108,20748,194
Production(1,205)(27,506)(1,112)(6,901)
December 31, 202331,038508,72525,762141,587
Extensions9,997127,4294,78236,018
Revisions to previous estimates(1,301)9,1521,3351,559
Purchases of reserves in place————
Production(2,380)(28,291)(1,723)(8,818)
December 31, 202437,354617,01530,156170,346
Extensions3,277362,6333,44467,159
Revisions to previous estimates(886)(17,428)4,157366
Purchases of reserves in place————
Production(3,074)(45,596)(2,209)(12,882)
December 31, 202536,671916,62435,548224,989
Proved developed reserves:
December 31, 202313,172252,83212,64467,954
December 31, 202414,577248,63412,85668,872
December 31, 202514,717417,36215,958100,235
Proved undeveloped reserves:
December 31, 202317,866255,89313,11873,633
December 31, 202422,777368,38217,300101,474
December 31, 202521,954499,26219,589124,753
Notable changes in proved reserves for the year ended December 31, 2025 included the following:
•Extensions. In 2025, total extensions to previous estimates increased proved reserves by 67.2 MMBoe. These extensions primarily related to the addition of 28 PUD locations to be developed by 2030 (as that year entered the 5-year development window) which added 53.0 MMBoe of proved reserves. Other extensions including converting 14.2 MMBoe on 9 wells from proved undeveloped in 2024 to producing in 2025.
•Revisions to previous estimates. In 2025, total revisions to previous estimates increased proved reserves by 0.4 MMBoe. These revisions primarily consisted of 4.6 MMBoe of downward revisions from 2024 to 2025 due to 2 PUD locations that were removed due to changes to our development plan. Additionally, our proved developed producing properties had upward revisions of 5.0 MMBoe related to increases in working interest, improvement in expense assumptions, and improvement in type curve.
Notable changes in proved reserves for the year ended December 31, 2024 included the following:
•Extensions. In 2024, total extensions to previous estimates increased proved reserves by 36.0 MMBoe. These extensions primarily related to the addition of 27 proved undeveloped (“PUD”) locations to be developed by 2029 (as that year entered the 5-year development window) which added 35.3 MMBoe of proved reserves. Other extensions included converting 0.7 MMBoe of unproved reserves to proved developed reserves by drilling eighteen (18) wells during 2024, two of which were producing as of
December 31, 2024. During 2024, our drilling program was focused on adding locations primarily in the various Utica and Point Pleasant formations in Ohio and the Marcellus shale formation in Pennsylvania.
•Revisions to previous estimates. In 2024, total revisions to previous estimates reduced proved reserves by 1.5 MMBoe. These downward revisions primarily consisted of 5.2 MMBoe of revisions to PUD reserves, due to changes to our development plan that resulted in 8 PUD locations being reclassified as they were outside the 5 year development window while the Company performs further technical refinements and analysis to evaluate well spacing assumptions. Additionally, our proved developed producing properties had upward revisions of 6.5 MMBoe and PUD reserves had upward revisions of 0.2 MMBoe related to decreases in capitalized costs which impacted the estimated performance of these wells.
Notable changes in proved reserves for the year ended December 31, 2023 included the following:
•Extensions. In 2023, total extensions to previous estimates increased proved reserves by 44.6 MMBoe. These extensions primarily related to the addition of 21 PUD locations to be developed by 2028 (as that year entered the 5-year development window) which added 32.5 MMBoe of proved reserves. Other extensions included converting 12.0 MMBoe of unproved reserves to proved developed reserves by drilling six (6) wells during 2023, two of which were producing as of December 31, 2023. During 2023, our drilling program was focused on adding locations primarily in the various Utica / Point Pleasant formation in Ohio and the Marcellus shale formation in Pennsylvania.
•Revisions to previous estimates. In 2023, total revisions to previous estimates reduced proved reserves by 24.1 MMBoe. These downward revisions primarily consisted of 20.8 MMBoe of downward revisions to PUD reserves, due to changes to our development plan that resulted in 18 PUD locations being reclassified as they were outside the 5 year development window while we perform further technical refinements and analysis to evaluate well spacing assumptions. Our proved developed producing properties had upward revisions of 3.3 MMBoe related to increases in commodity prices which impacted the estimated timing and performance of these wells.
Purchases of reserves in place. In 2023, 48.2 MMBoe of proved reserves were added primarily from properties acquired in the Ohio Utica Acquisition on October 4, 2023, including 20.4 MMBoe of proved developed reserves and 27.8 of proved undeveloped locations.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows (the “Standardized Measure”) relating to proved oil and gas reserves has been prepared in accordance with FASB ASC Topic 932, Extractive Activities – Oil and Gas (“ASC 932”). Future cash inflows as of December 31, 2025, 2024 and 2023 have been computed by applying average fiscal year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month periods ended December 31, 2025, 2024, 2023, respectively) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves, based on year-end costs and assuming the continuation of existing economic conditions. The Standardized Measure also includes costs for future dismantlement, abandonment, and rehabilitation obligations.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves.
Future net cash flows are discounted at a rate of 10% annually to derive the Standardized Measure. This calculation does not necessarily result in an estimate of the fair value of our oil and gas properties.
The following table presents our Standardized Measure of discounted future net cash flows:
 December 31,
 202520242023
(in thousands)
Future cash inflows
$5,511,802 $4,181,440 $3,865,302 
Future development costs (1)
(764,219)(652,135)(545,803)
Future production costs
(1,824,402)(1,548,957)(1,281,802)
Future income tax expense(531,584)— — 
Future net cash flows
2,391,597 1,980,348 2,037,697 
10% discount to reflect timing of cash flows
(1,310,404)(1,007,830)(1,099,313)
Standardized measure of discounted future net cash flows
$1,081,193 $972,518 $938,384 
(1)Future development costs include costs associated with the future abandonment of proved properties, including proved undeveloped locations.
The following summarizes the principal sources of change in the Standardized Measure of discounted future net cash flows and such changes have been computed in accordance with ASC 932:
 For the Year Ended December 31,
 202520242023
(in thousands)
Beginning of period
$972,518 $938,384 $1,017,607 
Sales of oil, natural gas, NGLs, net of production costs
(263,003)(176,822)(109,179)
Acquisitions of reserves
— — 534,927 
Extensions, net of future development costs
299,655 200,954 199,378 
Net change in price and production costs
238,597 (264,003)(643,905)
Previously estimated development costs incurred
118,750 140,274 68,412 
Change in estimated future development costs
(27,274)(7,170)4,734 
Revisions of previous quantity estimates
22,064 45,803 (224,318)
Accretion of discount
79,321 93,838 101,761 
Net change in income taxes
(251,800)— — 
Net change in timing of production and other
(107,635)1,260 (11,034)
End of period
$1,081,193 $972,518 $938,384 
Future net revenues included in the Standardized Measure relating to proved oil and natural gas reserves incorporate weighted average sales prices (inclusive of adjustments for transportation, quality, and basis differentials) for each of the periods indicated below as follows:
 December 31,
 202520242023
Oil (per Bbl)
$58.61 $67.98 $73.73 
Natural gas (per MMBtu)
$2.77 $1.42 $1.74 
NGL (per Bbl)
$23.20 $25.48 $26.87 
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]
We rely on information technology and data to operate our business effectively and recognize the importance of implementing and maintaining cybersecurity systems and processes that allow us to protect the confidentiality, integrity and availability of our information systems and the data residing within them.
We maintain a comprehensive cybersecurity risk program to effectively identify, assess, manage, and respond to cybersecurity risks and incidents. Our program is implemented by in-house personnel with experience in cybersecurity fields and is further enhanced by external partners that specialize in cybersecurity services. Our program is built on recognized industry standards and frameworks that are regularly evaluated and updated to address emerging threats.
Key elements of our cybersecurity risk management program include regular and thorough risk assessments to identify potential cybersecurity threats across our operations, the implementation of appropriate multi-layered security controls and advanced monitoring systems, comprehensive employee cybersecurity awareness training and education programs delivered throughout the year. A key element of our cybersecurity response program is the regular and redundant point-in-time backup of critical configurations and files.
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block]
We maintain a comprehensive cybersecurity risk program to effectively identify, assess, manage, and respond to cybersecurity risks and incidents. Our program is implemented by in-house personnel with experience in cybersecurity fields and is further enhanced by external partners that specialize in cybersecurity services. Our program is built on recognized industry standards and frameworks that are regularly evaluated and updated to address emerging threats.
Key elements of our cybersecurity risk management program include regular and thorough risk assessments to identify potential cybersecurity threats across our operations, the implementation of appropriate multi-layered security controls and advanced monitoring systems, comprehensive employee cybersecurity awareness training and education programs delivered throughout the year. A key element of our cybersecurity response program is the regular and redundant point-in-time backup of critical configurations and files.
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]
Our board of directors oversees our cybersecurity risk management program through the Audit Committee. Our management team, including our Vice President of Technology, provides periodic updates on cybersecurity matters to the Audit Committee, which relays them to the board of directors as needed. Our Vice President of Technology has primary responsibility for assessing and managing cybersecurity risks and leading our overall cybersecurity posture, including the engagement of external third parties to assist us. Our Vice President of Technology has 30 years of experience in the field of information systems and cybersecurity.
Impact of Risks from Cybersecurity Threats
As of the date of this Annual Report, we are not aware of any previous cybersecurity incidents that have materially affected or are reasonably likely to materially affect the Company, including our business strategy, results of operations and financial condition. We acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents, material or otherwise, remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cybersecurity incident will not occur. While we devote resources to our security measures designed to protect our systems and information, no security measure is infallible. For more information about the cybersecurity risks we face, refer to “Item 1A. Risk Factors” in this Annual Report.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] Our board of directors oversees our cybersecurity risk management program through the Audit Committee. Our management team, including our Vice President of Technology, provides periodic updates on cybersecurity matters to the Audit Committee, which relays them to the board of directors as needed.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block] Our Vice President of Technology has primary responsibility for assessing and managing cybersecurity risks and leading our overall cybersecurity posture, including the engagement of external third parties to assist us. Our Vice President of Technology has 30 years of experience in the field of information systems and cybersecurity.
Cybersecurity Risk Role of Management [Text Block] Our Vice President of Technology has primary responsibility for assessing and managing cybersecurity risks and leading our overall cybersecurity posture
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]
Our board of directors oversees our cybersecurity risk management program through the Audit Committee. Our management team, including our Vice President of Technology, provides periodic updates on cybersecurity matters to the Audit Committee, which relays them to the board of directors as needed. Our Vice President of Technology has primary responsibility for assessing and managing cybersecurity risks and leading our overall cybersecurity posture, including the engagement of external third parties to assist us. Our Vice President of Technology has 30 years of experience in the field of information systems and cybersecurity.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] Our Vice President of Technology has 30 years of experience in the field of information systems and cybersecurity.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block] We acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents, material or otherwise, remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cybersecurity incident will not occur.
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
Accounting Policies [Abstract]  
Use of Estimates
Use of Estimates. The preparation of financial statements 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. Management evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods it considers
reasonable in the particular circumstances. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Estimates significant to our consolidated financial statements include the following:
•proved reserves used in calculating depletion;
•estimates of accrued revenues and unbilled costs;
•future cash flows from proved oil and natural gas reserves used in the impairment assessment;
•derivative financial instruments; and
•asset retirement obligations.
Cash and Cash Equivalents
Cash and Cash Equivalents. We consider all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short-term maturity of these investments. Interest earned on cash equivalents is included as a reduction of interest expense, net. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits; however, we have not experienced any significant losses from such investments.
Commodity Derivative Financial Instruments
Commodity Derivative Financial Instruments. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. We have elected not to designate any of our commodity derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, realized gains and losses from the settlement of commodity derivatives and unrealized gains and losses from changes in the fair value of remaining unsettled commodity derivatives are presented as a component of other income in the consolidated statements of operations. Management believes that presenting realized and unrealized gains and losses on commodity derivative instruments within revenues reflects the manner in which such instruments are economically linked to the Company’s oil and natural gas production and sales. Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the consolidated balance sheet. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors and nonperformance risk. See Note 9.
Deferred Offering Costs
Deferred Offering Costs. Deferred offering costs incurred in connection with the Company’s initial public offering were capitalized and offset against IPO proceeds upon completion of the offering in February 2025. As of December 31, 2024, deferred offering costs of $9.6 million were included in prepaid expenses and other current assets. No deferred offering costs were recorded as of December 31, 2025.
Accounts Receivable and Allowance for Expected Credit Losses Accounts Receivable and Allowance for Expected Credit Losses. Accounts receivable consist of receivables from the sales of oil, natural gas, and NGL production delivered to purchasers and from joint interest owners on properties we operate. Accounts receivable are stated at the amount due, net of an allowance for expected losses as estimated by us when applicable. Most payments for accounts receivable are received within 30 to 60 days. We typically have the ability to withhold future revenue disbursements to recover any non-payment of joint interest accounts receivable from joint interest owners outstanding longer than the contractual payment terms are considered past due.
Drilling Advances Drilling Advances. The Company participates in the drilling of crude oil and natural gas wells with other working interest owners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest owner responsible for conducting the drilling operations may request advance payments from other working interest owners for their share of the costs.
Concentrations of Credit Risk Concentrations of Credit Risk. We are exposed to credit risk in the event of nonpayment by counterparties. We sell production to a relatively small number of customers, as is customary in our business.
Oil and Gas Properties and Midstream and Other Property and Equipment
Oil and Gas Properties
Oil and Natural Gas Properties. The Company uses the full cost method of accounting for its oil and natural gas properties. Accordingly, all costs directly associated with the acquisition, exploration, and development of oil, natural gas, and NGL reserves for both productive and nonproductive properties are capitalized into a full cost pool. Capitalized costs also include the costs of unproved properties and internal costs (i.e. salaries and benefits attributed to production activities of a well) directly related to the Company’s acquisition, exploration, and development activities. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred.
Under the full cost method of accounting, total net capitalized costs of proved oil and natural gas properties may not exceed the ceiling limitation determined based on the estimated future net revenues of our proved reserves discounted at 10%. The future net revenues are estimated using the average of the first day of the month trailing 12-month price as of the period end date in accordance with guidance provided by the SEC, adjusted for basis or location differentials, held constant over the life of the proved reserves. 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 members’ equity and typically results in lower depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date. The Company did not have a ceiling test impairment for the years ended December 31, 2025, 2024 and 2023. See Note 4.
The costs associated with unproved properties are primarily the costs to acquire unproved acreage. Costs associated with unproved properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We review our unproved properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. We also may capitalize interest on expenditures made in connection with bringing unproved properties to their intended use. We determine capitalized interest, when applicable, by multiplying our weighted-average borrowing cost on our revolving credit facility by the average amount of qualifying costs incurred that were excluded from the full cost pool; however, capitalized interest cannot exceed the amount of gross
interest expense incurred in any given period. The following table represents our capitalized internal costs and interest shown within our oil and gas properties on the audited balance sheet for the years ended 2025, 2024 and 2023:

For the Year Ended December 31,
in thousands202520242023
Capitalized Internal Costs
$7,558 $5,612 $2,238 
Capitalized Interest Costs
$— $41 $— 
Capitalized costs of proved properties are computed on a units-of-production basis based on estimated proved reserves, whereby the depletion rate is determined by dividing the total unamortized cost base plus future development costs by estimated proved reserves on a net equivalent basis at the beginning of the period. The depletion rate is multiplied by total production for the period to compute depletion expense. The following table shows our years ended 2025, 2024 and 2023 depletion expense related to oil and gas properties and average depletion rate per Boe:
For the Year Ended December 31,
in thousands202520242023
Depletion of Proved Oil and Natural Gas Properties
$100,644 $71,553 $52,075 
Average Depletion Rate per BOE
$7.81 $8.10 $7.17 
Unproved Property Impairment. The Company assesses properties excluded from the full cost pool. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation. The Company did not have impairment on unproved properties for the years ended December 31, 2025, 2024 and 2023.
Midstream and Other Property and Equipment. Other property and equipment includes midstream assets, vehicles, furniture, fixtures, office equipment, and leasehold improvements, all of which are recorded at cost. These assets are depreciated using the straight-line method over their estimated useful lives which range between three and 25 years. Equipment upgrades and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts and a gain or loss is recorded in the consolidated statements of operations as needed. See Note 4.
Leases
Leases. At contract inception, we determine whether or not an arrangement contains a lease in accordance with the Financial Accounting Standards Board’s (the “FASB”) Accounting Standards Codification Topic 842, Leases (“ASC 842”). A contract is or contains a lease if it conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Upon determination that a contract meets the definition of a lease subject to ASC 842, a right-of-use asset and related lease liability are recorded based on the present value of the future lease payments over the lease term. Right-of-use assets represent our right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make future lease payments arising from the lease. Since the implicit rate in the lease is generally not available, we utilize our incremental borrowing rate as the discount rate for determining the present value of lease payments. See Note 6.
Asset Retirement Obligations
Asset Retirement Obligations. We accrue a liability for the estimated future costs associated with the plugging and abandonment of our oil and natural gas properties. For oil and natural gas wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. The fair value of the liability recognized is based on the present value of the estimated future cash outflows associated with our plugging and abandonment obligations. Revisions typically occur due to changes in estimated abandonment costs or the remaining lives of our wells, or if federal or state regulators enact new requirements regarding the abandonment of wells. We deplete the amount added to the costs of proved oil and natural gas properties and recognize an expense in
connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties. Accretion expense is included within depreciation, depletion, and amortization in the consolidated statements of operations. See Note 7.
Revenue Recognition
Revenue Recognition. We derive revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when a performance obligation is satisfied by transferring control of the produced oil, natural gas, or NGLs to the customer. For all commodity products, we record revenue in the month production is delivered to the customer based on the amount of production delivered to the customer and the price we will receive. Payments are generally received between 30 and 60 days after the date of production. See Note 3.
Reportable Segment
Reportable Segment. We operate in only one reportable segment that is the exploration and production segment. All of our operations are conducted in one geographic area within the Appalachian Basin, primarily in Pennsylvania and Ohio, in the United States. See Note 17.
Income Taxes
Income Taxes. The Company is subject to U.S. federal, state and local income taxes with respect to its allocable share of any taxable income of INR Holdings, as well as any stand-alone income generated by the Company. INR Holdings is treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, INR Holdings is not subject to U.S. federal and certain state and local income taxes. Any taxable income generated by INR Holdings is passed through to and included in the taxable income of its members, including the Company, on a pro rata basis.
Income taxes are recognized based on earnings reported for tax return purposes and provisions recorded for deferred income taxes. Deferred income tax assets and liabilities are recognized based on temporary differences resulting from: (i) net operating loss carryforwards for income tax purposes, and (ii) differences between the amounts recorded to the consolidated financial statements and the tax basis of assets and liabilities, as measured using enacted statutory tax rates in effect at the end of a period. The effect of a change in tax rates or tax laws is recognized in income during the period such changes are enacted. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.
Adoption of New Accounting Standards and Accounting Standards Not Yet Adopted
Adoption of New Accounting Standards
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740) – Improvements to Income Tax Disclosures (“ASU 2023-09”), which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated and provides additional requirements regarding income taxes paid. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted, and should be applied either prospectively or retrospectively. The Company adopted this guidance effective upon becoming a public company in 2025.

In March 2024, the FASB issued ASU 2024-01, Compensation-Stock Compensation (Topic 718). This ASU illustrates how to apply the scope guidance to determine whether a profits interest award should be accounted for as a share-based payment arrange under Accounting Standards Codification (“ASC”) 718 or another accounting standard. The amendments in this update are effective for public entities for fiscal years beginning after December 15, 2024. The Company adopted this guidance effective upon becoming a public company in 2025.
Accounting Standards Not Yet Adopted
In November 2024, the FASB issued ASU 2024-03 - Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40). This ASU requires entities to disaggregate any relevant expense caption presented on the face of the income statement within continuing operations into the following required natural expense categories within the footnotes, as applicable: (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, and (5) DD&A recognized as part of oil- and gas-producing activities or other depletion expenses. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of the adoption of this guidance.
We considered the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or not material upon adoption.
v3.25.4
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Schedule of Accounts Payable and Accrued Liabilities The following table summarizes drilling advance receivables and deposits included in accounts receivable – other and accrued liabilities on the consolidated balance sheets as December 31, 2025 and 2024:
For the Year Ended December 31,
in thousands20252024
Drilling Advance Receivable
$2,444 $12,502 
Drilling Advance Deposits
$1,296 $6,188 
Schedule of Revenue From Sale of Commodities The table below summarizes the purchasers that accounted for 10% or more of our total revenues from the sale of commodities for the periods presented:
 For the Year Ended December 31,
 202520242023
Marathon Oil Company
33%55%49%
BP America
35%17%28%
Ergon16%—%—%
Blue Racer Midstream
—%10%13%
Oil and Gas, Acreage The following table represents our capitalized internal costs and interest shown within our oil and gas properties on the audited balance sheet for the years ended 2025, 2024 and 2023:
For the Year Ended December 31,
in thousands202520242023
Capitalized Internal Costs
$7,558 $5,612 $2,238 
Capitalized Interest Costs
$— $41 $— 
The following table shows our years ended 2025, 2024 and 2023 depletion expense related to oil and gas properties and average depletion rate per Boe:
For the Year Ended December 31,
in thousands202520242023
Depletion of Proved Oil and Natural Gas Properties
$100,644 $71,553 $52,075 
Average Depletion Rate per BOE
$7.81 $8.10 $7.17 
v3.25.4
Revenues (Tables)
 12 Months Ended
Dec. 31, 2025
Revenue from Contract with Customer [Abstract]  
Disaggregation of Revenue
The following table presents commodity sales revenues from the sale of crude oil, natural gas, and NGLs:

 Year Ended December 31,
 202520242023
(in thousands)   
Oil revenues
$173,612 $161,514 $85,276 
Natural gas revenues
127,448 51,157 49,617 
NGL revenues
49,315 45,035 24,639 
Oil, natural gas, and natural gas liquids sales
$350,375 $257,706 $159,532 
v3.25.4
Property, Plant, and Equipment (Tables)
 12 Months Ended
Dec. 31, 2025
Property, Plant and Equipment [Abstract]  
Oil and Gas, Capitalized Cost Our capitalized costs of oil and natural gas properties and the related accumulated depreciation, depletion, and amortization as of December 31, 2025 and 2024 are as follows:
 December 31, 2025December 31, 2024
(in thousands)
Oil and natural gas properties:
Proved properties$1,175,523 $846,738 
Unproved properties88,689 86,490 
Gross oil and natural gas properties1,264,212 933,228 
Less: accumulated depreciation, depletion, and amortization(249,296)(148,638)
Oil and natural gas properties, net$1,014,916 $784,590 
The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion, and amortization are shown below:
 December 31,
 202520242023
(in thousands)   
Proved properties(1)
$1,175,523 $846,738 $615,456 
Unproved properties88,689 86,490 37,189 
Total proved and unproved properties1,264,212 933,228 652,645 
Accumulated depreciation, depletion, and amortization(249,296)(148,638)(77,085)
Net capitalized costs$1,014,916 $784,590 $575,560 
(1)Includes asset retirement costs of $3.3 million, $2.7 million and $0.8 million as of December 31, 2025, 2024 and 2023, respectively.
Oil and Gas, Average Sale Price and Production Cost Prices used to calculate the ceiling value of reserves were as follows:
For the Year Ended December 31,
20252024
Oil (per barrel)
$65.34 $75.48 
Natural gas (per MMBtu)
$3.39 2.13 
NGLs (per barrel)
$23.20 25.48 
Property, Plant and Equipment
Our other property and equipment consists of the following assets that are recorded at cost and depreciated on a straight-line basis over the respective estimated useful lives.
 December 31,
 20252024
(in thousands)  
Midstream assets
$53,077 $36,880 
Other property and equipment4,039 3,173 
Gross midstream and other property and equipment
57,116 40,053 
Less: Accumulated depreciation
(7,416)(4,595)
Total midstream and other property and equipment, net
$49,700 $35,458 
The estimated useful lives of other property and equipment depreciated on a straight-line basis are as follows:
Midstream assets
5 – 25 years
Vehicles
5 years
Furniture, fixtures, and office equipment
3 – 10 years
Leasehold improvements
5 years
v3.25.4
Accrued Liabilities and Other (Tables)
 12 Months Ended
Dec. 31, 2025
Payables and Accruals [Abstract]  
Schedule of Accrued Liabilities
Our accrued liabilities as of December 31, 2025 and December 31, 2024 consisted of the following amounts:
 December 31, 2025December 31, 2024
Accrued capital expenditures7,270 27,234 
Accrued general and administrative expenses7,706 3,293 
JIB advance deposits1,296 6,188 
Other accrued liabilities6,749 9,289 
Total accrued liabilities$23,021 $46,004 
v3.25.4
Leases (Tables)
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Lessee, Operating Lease, Additional Information
The following table provides additional information related to our lease right-of-use assets and liabilities as of December 31, 2025, 2024 and 2023:
 For the Year Ended December 31,
 202520242023
Weighted-average discount rate9.0%9.0%9.1%
Weighted-average remaining lease term (years)9.79.413.0
Lessee, Operating Lease, Liability, to be Paid, Maturity
Payments due under our long-term operating lease liabilities by fiscal year as of December 31, 2025, are as follows:
 Operating Leases
(in thousands)
2026$277 
2027277 
2028221 
2029185 
203091 
Thereafter705 
   Total lease payments1,756 
Less: imputed interest(609)
   Present value of lease liabilities$1,147 
v3.25.4
Asset Retirement Obligations (Tables)
 12 Months Ended
Dec. 31, 2025
Asset Retirement Obligation Disclosure [Abstract]  
Schedule of Asset Retirement Obligations
 December 31,
 20252024
(in thousands)
Asset retirement obligations, beginning of period$2,988 $970 
Liabilities assumed in leasehold acquisitions121 — 
Liabilities incurred389 87 
Liabilities settled(150)(10)
Accretion expense268 101 
Revision to estimated cash flows20 1,840 
Asset retirement obligations, end of period$3,636 $2,988 
v3.25.4
Debt (Tables)
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Schedule of Maturities of Long-Term Debt
Payments due by fiscal year related to other long-term debt as of December 31, 2025 are as follows:
 Notes Payable
(in thousands)
2026$40 
202715 
2028— 
2029— 
2030— 
Total payments$55 
v3.25.4
Derivatives and Risk Management (Tables)
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value
The following tables provide information about our derivative financial instruments. The tables present the notional amount, the weighted average contract prices and the fair values by expected maturity dates as of December 31, 2025.
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Oil(in MBbls)
($ per Bbl)
(in thousands)
Fixed price swaps
20261,540$64.06 $10,777 
202797$63.95 683 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total
1,637$11,460 

 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Natural gas(in MMBtu)
($ per MMBtu)
(in thousands)
Fixed price swaps
202650,726,000$3.86 $16,467 
202745,438,000$3.94 1,969 
202835,967,000$3.77 917 
202930,320,000$3.62 194 
203026,580,000$3.57 (1,276)
20312,120,000$4.08 (169)
Total
191,151,000$18,102 
 VolumeBasis DifferentialFair Value as of
December 31, 2025
Natural gas(in MMBtu)($ per MMBtu)(in thousands)
Basis swaps
202653,439,000$(0.89)$(6,850)
202731,629,000$(0.64)(1,717)
202832,603,750$(0.52)(1,178)
20292,607,500$(0.30)(78)
2030—$— — 
2031—$— — 
Total120,279,250$(9,823)
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Ethane(in gallons)($ per gallon)(in thousands)
Fixed price swaps
20268,604,000$0.28 $282 
2027708,000$0.30 14 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total
9,312,000$296 
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Propane(in gallons)($ per gallon)(in thousands)
Fixed price swaps
202619,377,000$0.71 $2,008 
20271,524,000$0.71 103 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total20,901,000$2,111 
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Isobutane(in gallons)($ per gallon)(in thousands)
Fixed price swaps
20263,498,000$0.84 $98 
2027276,000$0.83 4 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total3,774,000$102 
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Normal butane(in gallons)($ per gallon)(in thousands)
Fixed price swaps
20265,743,000$0.82 $397 
2027455,000$0.82 19 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total6,198,000$416 
 VolumeWeighted Average PriceFair Value as of
December 31, 2025
Pentane(in gallons)($ per gallon)(in thousands)
Fixed price swaps
20262,487,000$1.38 $553 
2027190,000$1.34 39 
2028—$— — 
2029—$— — 
2030—$— — 
2031—$— — 
Total2,677,000$592 
Offsetting Liabilities
The following table summarizes the gross fair value of our derivative assets and liabilities and the effect of netting as of December 31, 2025 and 2024:
 December 31, 2025
Balance Sheet ClassificationGross Amounts
Netting Adjustment
Net Amounts Presented on Balance Sheet
(in thousands)
Assets
Commodity derivative assets, short-term$32,718 $(7,880)$24,838 
Commodity derivative assets, long-term7,701 (4,816)2,885 
Total assets$40,419 $(12,696)$27,723 
Liabilities
Commodity derivative liabilities, short-term$8,986 $(7,880)$1,106 
Commodity derivative liabilities, long-term8,177 (4,816)3,361 
Total liabilities$17,163 $(12,696)$4,467 
 December 31, 2024
Balance Sheet ClassificationGross Amounts
Netting Adjustment
Net Amounts Presented on Balance Sheet
(in thousands)
Assets
Commodity derivative assets, short-term$6,089 $(6,089)$— 
Commodity derivative assets, long-term2,647 (2,647)— 
Total assets$8,736 $(8,736)$— 
Liabilities
Commodity derivative liabilities, short-term$18,685 $(6,089)$12,596 
Commodity derivative liabilities, long-term12,989 (2,647)10,342 
Total liabilities$31,674 $(8,736)$22,938 
Our total derivative gains and losses for the years ended December 31, 2025, 2024 and 2023 were as follows:
 For the Year Ended December 31,
(in thousands)202520242023
Realized gain on derivative instruments$12,213 $28,360 $19,438 
Unrealized gain (loss) on derivative instruments46,194 (50,407)25,884 
Total gain (loss) on derivative instruments$58,407 $(22,047)$45,322 
v3.25.4
Fair Value Measurements (Tables)
 12 Months Ended
Dec. 31, 2025
Fair Value Disclosures [Abstract]  
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis
The following table presents, for each applicable level within the fair value hierarchy, our net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis.
 December 31, 2025
 Level 1Level 2Level 3Fair Value
(in thousands)
Assets
Fixed price swaps$— $33,079 $— $33,079 
Basis swaps— 349 — 349 
Liabilities
Fixed price swaps— — — — 
Basis swaps— (10,172)— (10,172)
Total$— $23,256 $— $23,256 
 December 31, 2024
 Level 1Level 2Level 3Fair Value
(in thousands)  
Assets
Fixed price swaps
$— $4,012 $— $4,012 
Basis swaps
— — — — 
Liabilities
Fixed price swaps
— (13,685)— (13,685)
Basis swaps
— (13,263)— (13,263)
Total
$— $(22,938)$— $(22,938)
v3.25.4
Income Taxes and Tax Receivable Agreement (Tables)
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Schedule of Components of Income Tax Expense (Benefit) As a result, the consolidated net income (loss) in the historical financial statements for periods prior to the IPO does not reflect the income tax expense (benefit) that would have been incurred if the Company had been subject to U.S. federal income tax during those periods.
Year Ended December 31,
202520242023
Current tax expense (benefit)
Federal $— $— $— 
State$— $— $— 
Total current tax expense (benefit)$— $— $— 
Deferred tax expense (benefit)
Federal $(4,668)$— $— 
State$(190)$— $— 
Total deferred tax expense (benefit)$(4,858)$— $— 
Total income tax expense (benefit)$(4,858)$— $— 
Schedule of Effective Income Tax Rate Reconciliation
The reconciliation of income taxes at the federal statutory level to provision for income taxes is as follows:
Year Ended December 31,
202520242023
$%$%$%
U.S. federal tax expense (benefit) at statutory rate$12,429 21 %$— 21 %$— 21 %
State tax, net of federal benefit$(150)— %$— — %$— — %
Pre-Offering non-taxable/deductible income$24,407 41 %$— — %$— — %
Non-controlling interests$(27,520)(47)%$— — %$— — %
IPO Underwriting Fees$— — %$— — %$— — %
Non-Deductible expenses$291 1 %$— — %$— — %
Percentage Depletion$(575)(1)%$— — %$— — %
Change in Valuation Allowance$(13,741)(23)%$— — %$— — %
Total income tax expense (benefit)$(4,858)(8)%$— 21 %$— 21 %
Schedule of Deferred Tax Assets and Liabilities
The tax effects of each temporary difference and carryforward as of December 31, 2025 and December 31, 2024 are as follows:
Year Ended December 31,
20252024
Deferred tax assets:
Net operating losses$4,054 $— 
Investment in partnership$2,298 $— 
Disallowed depletion carryforward$804 $— 
Total deferred tax assets:$7,157 $— 
Deferred tax liabilities:
Valuation allowance$(2,298)$— 
Net deferred tax asset (liabilities)$4,858 $— 
v3.25.4
Share-based Compensation (Tables)
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Summary of RSU Activity The following table summarizes the RSU activity for the year ended December 31, 2025:
RSUs
Weighted-average grant date fair value
Unvested as of beginning of period—
Granted485,558$18.12
Vested and settled(1,779)$18.33
Canceled/Forfeited(50,297)$17.67
Unvested as of end of period433,482$18.17
Schedule of Valuation Assumptions for PSUs
The grant-date fair value of the PSUs was estimated using a Monte Carlo simulation model, which reflects the probability of achieving various market-based outcomes and incorporates key assumptions such as expected volatility, risk-free interest rate, expected dividend yield and correlation with the peer group.
2025
Expected volatility40.00%
Risk-free rate4.04%
Expected dividend yield—%
Correlation with peer group range
45.00% - 68.00%
Summary of PSU Activity The following table summarizes the PSU activity for the year ended December 31, 2025:
PSUs
Weighted-average grant date fair value
Unvested as of beginning of period—
Granted455,601$22.20
Vested—
Canceled/Forfeited(29,019)22.20
Unvested as of end of period426,582$22.20
v3.25.4
Earnings Per Share (Tables)
 12 Months Ended
Dec. 31, 2025
Earnings Per Share [Abstract]  
Computation of Diluted Loss Per Share
The following table summarizes the calculation of weighted average shares of Class A common stock outstanding used in the computation of diluted loss per share:
For the Year Ended December 31, 2025For the Year Ended December 31, 2024
(in thousands, except per share amounts)
Net income attributable to Infinity Natural Resources, Inc.$13,836$—
Net income attributable to redeemable non-controlling interests$40,209$—
Diluted net income attributable to Infinity Natural Resources, Inc.$54,045$—
Weighted average number of Class A common stock outstanding:
Basic15,382,681—
Effect of dilutive securities:
INR Units45,491,091—
RSUs80,867—
PSUs——
Diluted60,954,6390
Net income attributable to Infinity Natural Resources, Inc. per share of Class A common stock
Basic$0.90$—
Diluted$0.89$—
v3.25.4
Commitment and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Other Commitments
The following table summarizes our future commitments related to these oil and natural gas transportation and gathering agreements as of December 31, 2025:
 As of December 31, 2025
 20262027202820292030 and
thereafter		Total
(in thousands)  
Total minimum future volume commitments14,093 13,346 13,962 12,677 13,418 67,496 
Total minimum future service commitments5,850 — — — — 5,850 
Total minimum future commitments$19,943 13,346 13,962 12,677 13,418 $73,346 
v3.25.4
Segment Information (Tables)
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Schedule of Segment Reporting Information, by Segment
The following table provides information about the Company’s one reportable segment and includes the reconciliation to consolidated net income:
 For the Year Ended December 31,
 202520242023
Total revenues356,431 259,022 161,730 
Less:
Gathering, processing, and transportation54,779 49,290 31,097 
Lease operating26,675 28,154 18,371 
Production and ad valorem taxes5,918 1,071 886 
Depreciation, depletion, and amortization103,751 73,726 53,796 
General and administrative153,413 13,045 4,885 
Other segment (income)/expenses(1)
(52,064)44,450 (33,977)
Segment income$63,959 $49,286 $86,672 
Other segment (income) / expenses are comprised of net interest expense of $9,666, 21,529 and 11,910 for December 31, 2025, 2024 and 2023, respectively, gain/(loss) on derivative instruments of $58,407, (22,047) and 45,322 for December 31, 2025, 2024 and 2023, respectively, other income/(loss) of $(1,535), (874) and 565 for December 31, 2025, 2024 and 2023, respectively, and Income tax expense / (benefit) of $(4,858) and $0 for December 31, 2025, 2024 and 2023.
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2025
Extractive Industries [Abstract]  
Oil and Gas, Capitalized Cost Our capitalized costs of oil and natural gas properties and the related accumulated depreciation, depletion, and amortization as of December 31, 2025 and 2024 are as follows:
 December 31, 2025December 31, 2024
(in thousands)
Oil and natural gas properties:
Proved properties$1,175,523 $846,738 
Unproved properties88,689 86,490 
Gross oil and natural gas properties1,264,212 933,228 
Less: accumulated depreciation, depletion, and amortization(249,296)(148,638)
Oil and natural gas properties, net$1,014,916 $784,590 
The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion, and amortization are shown below:
 December 31,
 202520242023
(in thousands)   
Proved properties(1)
$1,175,523 $846,738 $615,456 
Unproved properties88,689 86,490 37,189 
Total proved and unproved properties1,264,212 933,228 652,645 
Accumulated depreciation, depletion, and amortization(249,296)(148,638)(77,085)
Net capitalized costs$1,014,916 $784,590 $575,560 
(1)Includes asset retirement costs of $3.3 million, $2.7 million and $0.8 million as of December 31, 2025, 2024 and 2023, respectively.
Oil and Gas, Cost Incurred, Property Acquisition, Exploration, and Development
Our capital costs incurred for acquisition and development activities are shown below:
December 31,
202520242023
(in thousands)
Acquisition costs:
Proved properties
$44,585 $19,172 $274,732 
Unproved properties
5,236 89,174 1,047 
Development costs
274,723 165,795 144,121 
Exploration costs
— — — 
$324,544 $274,141 $419,900 
Oil and Gas, Proved Reserve, Quantity The table below presents a summary of changes in quantities of proved oil and gas reserves in our estimated proved reserves:
 Crude Oil (MBbls)Natural Gas (MMcf)
Natural Gas Liquids (MBbls)
Total (MBoe)
Total proved reserves:
December 31, 20225,913358,33714,15279,788
Extensions7,443168,7049,01544,575
Revisions to previous estimates252(118,920)(4,501)(24,069)
Purchases of reserves in place18,636128,1108,20748,194
Production(1,205)(27,506)(1,112)(6,901)
December 31, 202331,038508,72525,762141,587
Extensions9,997127,4294,78236,018
Revisions to previous estimates(1,301)9,1521,3351,559
Purchases of reserves in place————
Production(2,380)(28,291)(1,723)(8,818)
December 31, 202437,354617,01530,156170,346
Extensions3,277362,6333,44467,159
Revisions to previous estimates(886)(17,428)4,157366
Purchases of reserves in place————
Production(3,074)(45,596)(2,209)(12,882)
December 31, 202536,671916,62435,548224,989
Proved developed reserves:
December 31, 202313,172252,83212,64467,954
December 31, 202414,577248,63412,85668,872
December 31, 202514,717417,36215,958100,235
Proved undeveloped reserves:
December 31, 202317,866255,89313,11873,633
December 31, 202422,777368,38217,300101,474
December 31, 202521,954499,26219,589124,753
Oil and Gas, Standardized Measure, Discounted Future Net Cash Flow
The following table presents our Standardized Measure of discounted future net cash flows:
 December 31,
 202520242023
(in thousands)
Future cash inflows
$5,511,802 $4,181,440 $3,865,302 
Future development costs (1)
(764,219)(652,135)(545,803)
Future production costs
(1,824,402)(1,548,957)(1,281,802)
Future income tax expense(531,584)— — 
Future net cash flows
2,391,597 1,980,348 2,037,697 
10% discount to reflect timing of cash flows
(1,310,404)(1,007,830)(1,099,313)
Standardized measure of discounted future net cash flows
$1,081,193 $972,518 $938,384 
(1)Future development costs include costs associated with the future abandonment of proved properties, including proved undeveloped locations.
Oil and Gas, Change in Standardized Measure, Discounted Future Net Cash Flow
The following summarizes the principal sources of change in the Standardized Measure of discounted future net cash flows and such changes have been computed in accordance with ASC 932:
 For the Year Ended December 31,
 202520242023
(in thousands)
Beginning of period
$972,518 $938,384 $1,017,607 
Sales of oil, natural gas, NGLs, net of production costs
(263,003)(176,822)(109,179)
Acquisitions of reserves
— — 534,927 
Extensions, net of future development costs
299,655 200,954 199,378 
Net change in price and production costs
238,597 (264,003)(643,905)
Previously estimated development costs incurred
118,750 140,274 68,412 
Change in estimated future development costs
(27,274)(7,170)4,734 
Revisions of previous quantity estimates
22,064 45,803 (224,318)
Accretion of discount
79,321 93,838 101,761 
Net change in income taxes
(251,800)— — 
Net change in timing of production and other
(107,635)1,260 (11,034)
End of period
$1,081,193 $972,518 $938,384 
Oil and Gas, Change in Standardized Measure, Weighted Average Sales Prices
Future net revenues included in the Standardized Measure relating to proved oil and natural gas reserves incorporate weighted average sales prices (inclusive of adjustments for transportation, quality, and basis differentials) for each of the periods indicated below as follows:
 December 31,
 202520242023
Oil (per Bbl)
$58.61 $67.98 $73.73 
Natural gas (per MMBtu)
$2.77 $1.42 $1.74 
NGL (per Bbl)
$23.20 $25.48 $26.87 
v3.25.4
Description of the Business and Basis of Presentation (Details)
$ / shares in Units, $ in Thousands
 1 Months Ended 12 Months Ended
Feb. 28, 2025
USD ($)
$ / shares
shares
Dec. 31, 2025
USD ($)
$ / shares
Dec. 31, 2024
USD ($)
$ / shares
Dec. 31, 2023
USD ($)
Jan. 30, 2025
$ / shares
Class of Stock [Line Items]          
Underwriting discounts and commissions | $   $ 6,760 $ 4,415 $ 0  
INR Holdings          
Class of Stock [Line Items]          
Ownership interest (as a percent)   74.40%      
INR Holdings | Legacy Owners          
Class of Stock [Line Items]          
Ownership interest (as a percent)   25.60%      
Public Stock Offering          
Class of Stock [Line Items]          
Aggregate net proceeds from stock offering | $ $ 286,500        
Underwriting discounts and commissions | $ $ 18,300        
Common Class A          
Class of Stock [Line Items]          
Common stock par value (in USD per share)   $ 0.01 $ 0.01    
Exchange ratio   1      
Common Class A | Public Stock Offering          
Class of Stock [Line Items]          
Common stock par value (in USD per share)         $ 0.01
Shares issued in transaction (in shares) | shares 15,237,500        
Public offering price (in USD per share) $ 20.00        
Common Class A | Over-Allotment Option          
Class of Stock [Line Items]          
Shares issued in transaction (in shares) | shares 1,987,500        
Common Class B          
Class of Stock [Line Items]          
Common stock par value (in USD per share)   $ 0.01 $ 0.01    
v3.25.4
Summary of Significant Accounting Policies - Additional Information (Details)
 12 Months Ended
Dec. 31, 2025
USD ($)
geographic_area
segment
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Product Information [Line Items]      
Deferred offering costs $ 9,600,000    
Allowance for credit loss $ 0 $ 0 $ 0
Number of reportable segments | segment 1    
Number of operating segments | segment 1    
Number of geographic areas | geographic_area 1    
Impairment on unproved properties $ 0 $ 0 $ 0
Marathon Oil Company      
Product Information [Line Items]      
Oil and gas, receivable (as a percent) 24.00% 49.00%  
BP America      
Product Information [Line Items]      
Oil and gas, receivable (as a percent) 53.00% 25.00%  
Ergon      
Product Information [Line Items]      
Oil and gas, receivable (as a percent) 18.00%  
Minimum      
Product Information [Line Items]      
Payment terms (in days) 30 days    
Estimated useful life 3 years    
Maximum      
Product Information [Line Items]      
Payment terms (in days) 60 days    
Estimated useful life 25 years    
v3.25.4
Summary of Significant Accounting Policies - Accounts Receivable And Accrued Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Product Information [Line Items]    
Prepaid expenses and other current assets $ 4,002 $ 11,822
Drilling Advance Receivable    
Product Information [Line Items]    
Prepaid expenses and other current assets 2,444 12,502
Drilling Advance Deposits    
Product Information [Line Items]    
Prepaid expenses and other current assets $ 1,296 $ 6,188
v3.25.4
Summary of Significant Accounting Policies - Revenue from Sale of Commodities (Details) - Revenue Benchmark - Customer Concentration Risk
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Marathon Oil Company      
Revenue from External Customer [Line Items]      
Revenue from sale of commodities 33.00% 55.00% 49.00%
BP America      
Revenue from External Customer [Line Items]      
Revenue from sale of commodities 35.00% 17.00% 28.00%
Ergon      
Revenue from External Customer [Line Items]      
Revenue from sale of commodities 16.00% 0.00% 0.00%
Blue Racer Midstream      
Revenue from External Customer [Line Items]      
Revenue from sale of commodities 0.00% 10.00% 13.00%
v3.25.4
Summary of Significant Accounting Policies - Oil And Gas Properties (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
Boe
Dec. 31, 2024
USD ($)
Boe
Dec. 31, 2023
USD ($)
Boe
Oil and Gas, Capitalized Cost [Line Items]      
Capitalized cost $ 274,723 $ 165,795 $ 144,121
Depletion of Proved Oil and Natural Gas Properties $ 100,644 $ 71,553 $ 52,075
Average Depletion Rate per BOE | Boe 7.81 8.10 7.17
Internal Costs      
Oil and Gas, Capitalized Cost [Line Items]      
Capitalized cost $ 7,558 $ 5,612 $ 2,238
Interest Costs      
Oil and Gas, Capitalized Cost [Line Items]      
Capitalized cost $ 0 $ 41 $ 0
v3.25.4
Revenues - Summary 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]      
Oil, natural gas, and natural gas liquids sales $ 350,375 $ 257,706 $ 159,532
Oil revenues      
Disaggregation of Revenue [Line Items]      
Oil, natural gas, and natural gas liquids sales 173,612 161,514 85,276
Natural gas revenues      
Disaggregation of Revenue [Line Items]      
Oil, natural gas, and natural gas liquids sales 127,448 51,157 49,617
NGL revenues      
Disaggregation of Revenue [Line Items]      
Oil, natural gas, and natural gas liquids sales $ 49,315 $ 45,035 $ 24,639
v3.25.4
Revenues - Additional Information (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]    
Oil and natural gas sales, net $ 54,836 $ 39,314
Oil revenues    
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]    
Accounts receivable terms (in days) 30 days  
NGL | Minimum    
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]    
Accounts receivable terms (in days) 30 days  
NGL | Maximum    
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]    
Accounts receivable terms (in days) 60 days  
v3.25.4
Property, Plant, and Equipment - Summary of Capital Costs (Details) - USD ($)
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2022
Property, Plant and Equipment [Abstract]      
Proved properties $ 1,175,523,000 $ 846,738,000 $ 615,456,000
Unproved properties 88,689,000 86,490,000 37,189,000
Gross oil and natural gas properties 1,264,212,000 933,228,000 652,645,000
Less: accumulated depreciation, depletion, and amortization (249,296,000) (148,638,000) (77,085,000)
Net capitalized costs $ 1,014,916,000 $ 784,590,000 $ 575,560,000
v3.25.4
Property, Plant, and Equipment - Additional Information (Details)
$ in Thousands
 1 Months Ended 12 Months Ended
Jul. 31, 2024
USD ($)
a
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Property, Plant and Equipment [Line Items]        
Unproved properties   $ 5,236 $ 89,174 $ 1,047
Depreciation   $ 100 $ 2,100  
Salt Fork State Park        
Property, Plant and Equipment [Line Items]        
Net acres | a 5,705      
Unproved properties $ 58,500      
v3.25.4
Property, Plant, and Equipment - Schedule of Ceiling Values (Details)
Dec. 31, 2025
$ / bbl
$ / MMBTU
Dec. 31, 2024
$ / bbl
$ / MMBTU
Oil revenues    
Property, Plant and Equipment [Line Items]    
Ceiling value price (in USD per unit) 65.34 75.48
Natural gas revenues    
Property, Plant and Equipment [Line Items]    
Ceiling value price (in USD per unit) | $ / MMBTU 3.39 2.13
NGL revenues    
Property, Plant and Equipment [Line Items]    
Ceiling value price (in USD per unit) 23.20 25.48
v3.25.4
Property, Plant, and Equipment - Summary of Property, Plant, and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Gross midstream and other property and equipment    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment $ 57,116 $ 40,053
Less: Accumulated depreciation, depletion, and amortization (7,416) (4,595)
Property and equipment, net 49,700 35,458
Midstream assets    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment 53,077 36,880
Other property and equipment    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment $ 4,039 $ 3,173
v3.25.4
Property, Plant, and Equipment - Summary of Property, Plant, and Equipment Useful Life (Details)
Dec. 31, 2025
Midstream assets | Maximum  
Property, Plant and Equipment [Line Items]  
Useful life (in years) 25 years
Vehicles  
Property, Plant and Equipment [Line Items]  
Useful life (in years) 5 years
Vehicles | Minimum  
Property, Plant and Equipment [Line Items]  
Useful life (in years) 5 years
Furniture, fixtures, and office equipment | Minimum  
Property, Plant and Equipment [Line Items]  
Useful life (in years) 3 years
Furniture, fixtures, and office equipment | Maximum  
Property, Plant and Equipment [Line Items]  
Useful life (in years) 10 years
Leasehold improvements  
Property, Plant and Equipment [Line Items]  
Useful life (in years) 5 years
v3.25.4
Accrued Liabilities and Other (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Payables and Accruals [Abstract]    
Accrued capital expenditures $ 7,270 $ 27,234
Accrued general and administrative expenses 7,706 3,293
JIB advance deposits 1,296 6,188
Other accrued liabilities 6,749 9,289
Total accrued liabilities $ 23,021 $ 46,004
v3.25.4
Leases - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Lessee, Lease, Description [Line Items]      
Lease operating $ 26,675 $ 28,154 $ 18,371
Office Space      
Lessee, Lease, Description [Line Items]      
Lease operating $ 400 $ 300 $ 200
Maximum      
Lessee, Lease, Description [Line Items]      
Remaining lease term 15 years    
Minimum      
Lessee, Lease, Description [Line Items]      
Remaining lease term 1 month    
v3.25.4
Leases - Schedule of Operating Leases Information (Details)
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Leases [Abstract]      
Weighted-average discount rate 9.00% 9.00% 9.10%
Weighted-average remaining lease term (in years) 9 years 8 months 12 days 9 years 4 months 24 days 13 years
v3.25.4
Leases - Schedule of Future Payments (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
Leases [Abstract]  
2026 $ 277
2027 277
2028 221
2029 185
2030 91
Thereafter 705
Total lease payments 1,756
Less: imputed interest (609)
Present value of lease liabilities $ 1,147
v3.25.4
Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Asset retirement obligations, beginning of period $ 2,988 $ 970
Liabilities assumed in leasehold acquisitions 121 0
Liabilities incurred 389 87
Liabilities settled (150) (10)
Accretion expense 268 101
Revision to estimated cash flows 20 1,840
Asset retirement obligations, end of period $ 3,636 $ 2,988
v3.25.4
Debt - Additional Information (Details) - USD ($)
$ in Thousands
 12 Months Ended
Sep. 25, 2024
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Oct. 01, 2025
Sep. 30, 2025
Mar. 31, 2025
Sep. 24, 2024
Debt Instrument [Line Items]                
Capitalized Interest   $ 0            
Amortization of debt issuance costs   1,705 $ 1,957 $ 778        
Credit Facility | Line of Credit                
Debt Instrument [Line Items]                
Maximum borrowing capacity   375,000     $ 375,000 $ 350,000 $ 350,000 $ 325,000
Interest expense   $ 7,800 $ 19,100          
Weighted average interest rate (as a percent)   7.20% 8.30%          
Debt issuance costs   $ 6,700 $ 7,900          
Amortization of debt issuance costs   2,300 $ 2,400          
Credit Facility | Secured Overnight Financing Rate (SOFR) | Line of Credit | Maximum                
Debt Instrument [Line Items]                
Basis spread on variable rate 3.75%              
Credit Facility | Secured Overnight Financing Rate (SOFR) | Line of Credit | Minimum                
Debt Instrument [Line Items]                
Basis spread on variable rate 2.75%              
Amended And Restated Credit Facility | Line of Credit                
Debt Instrument [Line Items]                
Maximum borrowing capacity   375,000            
Credit facility borrowings   150,900            
Remaining borrowing capacity   224,100            
Debt issuance costs   $ 1,100            
Debt covenant, minimum current ratio   1.0            
Debt covenant, maximum leverage ratio   3.0            
Amended And Restated Credit Facility | Fed Funds Rate                
Debt Instrument [Line Items]                
Basis spread on variable rate 0.50%              
v3.25.4
Debt - Schedule of Long Term Debt Future Maturities (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
Debt Disclosure [Abstract]  
2026 $ 40
2027 15
2028 0
2029 0
2030 0
Total payments $ 55
v3.25.4
Derivatives and Risk Management - Schedule of Derivatives Instruments (Details) - Designated as Hedging Instrument
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
MMBTU
$ / MMBTU
$ / gal
$ / bbl
MBbls
gal
Oil | Oil Fixed Price Swap  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | MBbls 1,637
Derivative Liability $ 11,460
Oil | Oil Fixed Price Swap 2026  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | MBbls 1,540
Basis Differential | $ / bbl 64.06
Derivative Liability $ 10,777
Oil | Oil Fixed Price Swap 2027  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | MBbls 97
Basis Differential | $ / bbl 63.95
Derivative Liability $ 683
Oil | Oil Fixed Price Swap 2028  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | MBbls 0
Basis Differential | $ / bbl 0
Derivative Liability $ 0
Oil | Oil Fixed Price Swap 2029  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | MBbls 0
Basis Differential | $ / bbl 0
Derivative Liability $ 0
Oil | Oil Fixed Price Swap 2030  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | MBbls 0
Basis Differential | $ / bbl 0
Derivative Liability $ 0
Oil | Oil Fixed Price Swap 2031  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | MBbls 0
Basis Differential | $ / bbl 0
Derivative Liability $ 0
Natural gas | Natural Gas Fixed Price Swap  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 191,151,000
Derivative Liability $ 18,102
Natural gas | Natural Gas Fixed Price Swap 2026  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 50,726,000
Basis Differential | $ / MMBTU 3.86
Derivative Liability $ 16,467
Natural gas | Natural Gas Fixed Price Swap 2027  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 45,438,000
Basis Differential | $ / MMBTU 3.94
Derivative Liability $ 1,969
Natural gas | Natural Gas Fixed Price Swap 2028  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 35,967,000
Basis Differential | $ / MMBTU 3.77
Derivative Liability $ 917
Natural gas | Natural Gas Fixed Price Swap 2029  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 30,320,000
Basis Differential | $ / MMBTU 3.62
Derivative Liability $ 194
Natural gas | Natural Gas Fixed Price Swap 2030  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 26,580,000
Basis Differential | $ / MMBTU 3.57
Derivative Liability $ (1,276)
Natural gas | Natural Gas Fixed Price Swap 2031  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 2,120,000
Basis Differential | $ / MMBTU 4.08
Derivative Liability $ (169)
Natural gas | Natural Gas Basis Swap  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 120,279,250
Derivative Liability $ (9,823)
Natural gas | Natural Gas Basis Swap 2026  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 53,439,000
Basis Differential | $ / MMBTU (0.89)
Derivative Liability $ (6,850)
Natural gas | Natural Gas Basis Swap 2027  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 31,629,000
Basis Differential | $ / MMBTU (0.64)
Derivative Liability $ (1,717)
Natural gas | Natural Gas Basis Swap 2028  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 32,603,750
Basis Differential | $ / MMBTU (0.52)
Derivative Liability $ (1,178)
Natural gas | Natural Gas Basis Swap 2029  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 2,607,500
Basis Differential | $ / MMBTU (0.30)
Derivative Liability $ (78)
Natural gas | Natural Gas Basis Swap 2030  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 0
Basis Differential | $ / MMBTU 0
Derivative Liability $ 0
Natural gas | Natural Gas Basis Swap 2031  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Energy Measure | MMBTU 0
Basis Differential | $ / MMBTU 0
Derivative Liability $ 0
Ethane | Ethane Fixed Price Swap  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 9,312,000
Derivative Liability $ 296
Ethane | Ethane Fixed Price Swap 2026  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 8,604,000
Basis Differential | $ / gal 0.28
Derivative Liability $ 282
Ethane | Ethane Fixed Price Swap 2027  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 708,000
Basis Differential | $ / gal 0.30
Derivative Liability $ 14
Ethane | Ethane Fixed Price Swap 2028  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Ethane | Ethane Fixed Price Swap 2029  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Ethane | Ethane Fixed Price Swap 2030  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Ethane | Ethane Fixed Price Swap 2031  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Propane | Propane Fixed Price Swap  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 20,901,000
Derivative Liability $ 2,111
Propane | Propane Fixed Price Swap 2026  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 19,377,000
Basis Differential | $ / gal 0.71
Derivative Liability $ 2,008
Propane | Propane Fixed Price Swap 2027  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 1,524,000
Basis Differential | $ / gal 0.71
Derivative Liability $ 103
Propane | Propane Fixed Price Swap 2028  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Propane | Propane Fixed Price Swap 2029  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Propane | Propane Fixed Price Swap 2030  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Propane | Propane Fixed Price Swap 2031  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Isobutane | Isobutane Fixed Price Swap  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 3,774,000
Derivative Liability $ 102
Isobutane | Isobutane Fixed Price Swap 2026  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 3,498,000
Basis Differential | $ / gal 0.84
Derivative Liability $ 98
Isobutane | Isobutane Fixed Price Swap 2027  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 276,000
Basis Differential | $ / gal 0.83
Derivative Liability $ 4
Isobutane | Isobutane Fixed Price Swap 2028  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Isobutane | Isobutane Fixed Price Swap 2029  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Isobutane | Isobutane Fixed Price Swap 2030  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Isobutane | Isobutane Fixed Price Swap 2031  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Normal butane | Normal Butane Fixed Price Swap  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 6,198,000
Derivative Liability $ 416
Normal butane | Normal Butane Fixed Price Swap 2026  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 5,743,000
Basis Differential | $ / gal 0.82
Derivative Liability $ 397
Normal butane | Normal Butane Fixed Price Swap 2027  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 455,000
Basis Differential | $ / gal 0.82
Derivative Liability $ 19
Normal butane | Normal Butane Fixed Price Swap 2028  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Normal butane | Normal Butane Fixed Price Swap 2029  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Normal butane | Normal Butane Fixed Price Swap 2030  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Normal butane | Normal Butane Fixed Price Swap 2031  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Pentane | Pentane Fixed Price Swap  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 2,677,000
Derivative Liability $ 592
Pentane | Pentane Fixed Price Swap 2026  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 2,487,000
Basis Differential | $ / gal 1.38
Derivative Liability $ 553
Pentane | Pentane Fixed Price Swap 2027  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 190,000
Basis Differential | $ / gal 1.34
Derivative Liability $ 39
Pentane | Pentane Fixed Price Swap 2028  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Pentane | Pentane Fixed Price Swap 2029  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Pentane | Pentane Fixed Price Swap 2030  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
Pentane | Pentane Fixed Price Swap 2031  
Derivative Instruments and Hedging Activities Disclosures [Line Items]  
Volume | gal 0
Basis Differential | $ / gal 0
Derivative Liability $ 0
v3.25.4
Derivatives and Risk Management - Schedule of Derivative Netting (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Assets    
Gross Amounts $ 40,419 $ 8,736
Netting Adjustment (12,696) (8,736)
Net Amounts Presented on Balance Sheet 27,723 0
Liabilities    
Gross Amounts 17,163 31,674
Netting Adjustment (12,696)  
Netting Adjustment   (8,736)
Net Amounts Presented on Balance Sheet 4,467 22,938
Current Assets    
Assets    
Gross Amounts 32,718 6,089
Netting Adjustment (7,880) (6,089)
Net Amounts Presented on Balance Sheet 24,838 0
Noncurrent Assets    
Assets    
Gross Amounts 7,701 2,647
Netting Adjustment (4,816) (2,647)
Net Amounts Presented on Balance Sheet 2,885 0
Current Liabilities    
Liabilities    
Gross Amounts 8,986 18,685
Netting Adjustment (7,880)  
Netting Adjustment   (6,089)
Net Amounts Presented on Balance Sheet 1,106 12,596
Noncurrent Liabilities    
Liabilities    
Gross Amounts 8,177 12,989
Netting Adjustment (4,816)  
Netting Adjustment   (2,647)
Net Amounts Presented on Balance Sheet $ 3,361 $ 10,342
v3.25.4
Derivatives and Risk Management - Schedule of Derivative Gains and Losses (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]      
Realized gain on derivative instruments $ 12,213 $ 28,360 $ 19,438
Unrealized gain (loss) on derivative instruments 46,194 (50,407) 25,884
Gain (loss) on derivative instruments $ 58,407 $ (22,047) $ 45,322
v3.25.4
Fair Value Measurements - Schedule of Fair Value Measurements Recurring (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total $ 23,256 $ (22,938)
Fixed price swaps    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Commodity derivative assets 33,079 4,012
Derivative Liability 0 (13,685)
Basis swaps    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Commodity derivative assets 349 0
Derivative Liability (10,172) (13,263)
Level 1    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total 0 0
Level 1 | Fixed price swaps    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Commodity derivative assets 0 0
Derivative Liability 0 0
Level 1 | Basis swaps    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Commodity derivative assets 0 0
Derivative Liability 0 0
Level 2    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total 23,256 (22,938)
Level 2 | Fixed price swaps    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Commodity derivative assets 33,079 4,012
Derivative Liability 0 (13,685)
Level 2 | Basis swaps    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Commodity derivative assets 349 0
Derivative Liability (10,172) (13,263)
Level 3    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Total 0 0
Level 3 | Fixed price swaps    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Commodity derivative assets 0 0
Derivative Liability 0 0
Level 3 | Basis swaps    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Commodity derivative assets 0 0
Derivative Liability $ 0 $ 0
v3.25.4
Income Taxes and Tax Receivable Agreement - Federal And State Income Tax Expenses (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Current tax expense (benefit)      
Federal $ 0 $ 0 $ 0
State 0 0 0
Total current tax expense (benefit) 0 0 0
Deferred tax expense (benefit)      
Federal (4,668) 0 0
State (190) 0 0
Deferred income taxes (4,858) 0 0
Income tax expense (benefit) $ (4,858) $ 0 $ 0
v3.25.4
Income Taxes and Tax Receivable Agreement - Narrative (Details)
$ in Millions
 12 Months Ended
Aug. 15, 2025
shares
Dec. 31, 2025
USD ($)
shares
Income Tax Contingency [Line Items]    
Deferred tax assets   $ 16.8
Conversion of Class B Units to Class A Units (in shares) | shares 390,915 400,000
Stock split, conversion ratio 1  
TRA non-current liability   $ 1.5
v3.25.4
Income Taxes and Tax Receivable Agreement - Reconciliation of Income Taxes (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Tax Expense (Benefit), Effective Income Tax Rate Reconciliation, Amount [Abstract]      
U.S. federal tax expense (benefit) at statutory rate $ 12,429 $ 0 $ 0
State tax, net of federal benefit (150) 0 0
Pre-Offering non-taxable/deductible income 24,407 0 0
Non-controlling interests (27,520) 0 0
IPO Underwriting Fees 0 0 0
Non-Deductible expenses 291 0 0
Percentage Depletion (575) 0 0
Change in Valuation Allowance (13,741) 0 0
Income tax expense (benefit) $ (4,858) $ 0 $ 0
Effective Income Tax Rate Reconciliation, Percent [Abstract]      
U.S. federal tax expense (benefit) at statutory rate 21.00%    
State tax, net of federal benefit 0.00% 0.00% 0.00%
Pre-Offering non-taxable/deductible income 41.00% 0.00% 0.00%
Non-controlling interests (47.00%) 0.00% 0.00%
IPO Underwriting Fees 0.00% 0.00% 0.00%
Non-Deductible expenses 1.00% 0.00% 0.00%
Percentage Depletion (1.00%) 0.00% 0.00%
Change in Valuation Allowance (23.00%) 0.00% 0.00%
Total income tax expense (benefit) (8.00%)    
v3.25.4
Income Taxes and Tax Receivable Agreement - Deferred Tax Asset And Liabilities (Details) - USD ($)
$ in Thousands
Dec. 31, 2025
Dec. 31, 2024
Deferred tax assets:    
Net operating losses $ 4,054 $ 0
Investment in partnership 2,298 0
Disallowed depletion carryforward 804 0
Total deferred tax assets: 7,157 0
Deferred tax liabilities:    
Valuation allowance (2,298) 0
Net deferred tax asset (liabilities) $ 4,858 $ 0
v3.25.4
Stockholders' Equity and Noncontrolling Interest (Details)
 12 Months Ended
Jan. 30, 2025
shares
Dec. 31, 2025
vote
Schedule of Capitalization [Line Items]    
Stock exchanged during period (in shares) | shares 45,638,889  
Common Class A    
Schedule of Capitalization [Line Items]    
Common stock, voting rights | vote   1
Common Class B    
Schedule of Capitalization [Line Items]    
Common stock, voting rights | vote   1
INR Holdings    
Schedule of Capitalization [Line Items]    
Ownership interest (as a percent)   74.40%
INR Holdings | Legacy Owners    
Schedule of Capitalization [Line Items]    
Ownership interest (as a percent)   25.60%
INR Holdings    
Schedule of Capitalization [Line Items]    
Shares issued in transaction (in shares) | shares 15,237,500  
v3.25.4
Share-based Compensation - Narrative (Details) - USD ($)
$ / shares in Units, $ in Millions
 1 Months Ended 2 Months Ended 12 Months Ended
Jul. 31, 2025
Mar. 31, 2025
Feb. 28, 2025
Aug. 31, 2025
Dec. 31, 2025
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]          
Compensation expense         $ 126.1
Share reserved for future issuance in shares)         5,888,889
INR Units          
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]          
Grant date valuation price (in dollars per share)         $ 20.00
Compensation expense         $ 126.1
RSUs          
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]          
Grant date valuation price (in dollars per share)         $ 18.12
Compensation expense         $ 4.7
Equity awards granted (in shares) 10,086 311,991 162,500 1,238 485,558,000
Equity award vesting period   3 years 1 year    
Vested (in shares)       1,779 1,779,000
Unrecognized compensation expense         $ 3.2
Unrecognized compensation expense, period for recognition         1 year 1 month 6 days
PSUs          
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]          
Grant date valuation price (in dollars per share)         $ 22.20
Compensation expense         $ 2.5
Equity awards granted (in shares)   455,601     455,601,000
Vested (in shares)         0
Unrecognized compensation expense         $ 6.9
Unrecognized compensation expense, period for recognition         2 years 2 months 12 days
PSUs | Minimum          
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]          
Award vesting rights, percentage         0.00%
PSUs | Maximum          
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]          
Award vesting rights, percentage         300.00%
v3.25.4
Share-based Compensation - Summary of RSU Activity (Details) - RSUs - $ / shares
 1 Months Ended 2 Months Ended 12 Months Ended
Jul. 31, 2025
Mar. 31, 2025
Feb. 28, 2025
Aug. 31, 2025
Dec. 31, 2025
PSUs          
Unvested as of beginning of period (in shares)         0
Granted (in shares) 10,086 311,991 162,500 1,238 485,558,000
Vested (in shares)       (1,779) (1,779,000)
Canceled/Forfeited (in shares)         (50,297,000)
Unvested as of end of period (in shares)         433,482,000
Weighted-average grant date fair value          
Unvested as of beginning of period (in dollars per share)        
Granted (in dollars per share)         18.12
Vested (in dollars per share)         18.33
Canceled/Forfeited (in dollars per share)         17.67
Unvested as of end of period (in dollars per share)         $ 18.17
v3.25.4
Share-based Compensation - Fair Value Assumptions for RSUs (Details) - PSUs
 12 Months Ended
Dec. 31, 2025
USD ($)
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]  
Expected volatility 40.00%
Risk-free rate 4.04%
Expected dividend yield $ 0
Minimum  
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]  
Correlation with peer group range 45.00%
Maximum  
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]  
Correlation with peer group range 68.00%
v3.25.4
Share-based Compensation - Summary of PSU Activity (Details) - PSUs - $ / shares
 1 Months Ended 12 Months Ended
Mar. 31, 2025
Dec. 31, 2025
PSUs    
Unvested as of beginning of period (in shares)   0
Granted (in shares) 455,601 455,601,000
Vested (in shares)   0
Canceled/Forfeited (in shares)   (29,019,000)
Unvested as of end of period (in shares)   426,582,000
Weighted-average grant date fair value    
Unvested as of beginning of period (in dollars per share)  
Granted (in dollars per share)   22.20
Vested (in dollars per share)  
Canceled/Forfeited (in dollars per share)   22.2
Unvested as of end of period (in dollars per share)   $ 22.20
v3.25.4
Earnings Per Share - Computation of Loss Per Share (Details) - USD ($)
$ / shares in Units, $ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]      
Net income attributable to Infinity Natural Resources, Inc. $ 13,836 $ 0  
Net income attributable to redeemable non-controlling interests 40,209 0  
Diluted net income attributable to Infinity Natural Resources, Inc. $ 54,045 $ 0  
Weighted average number of Class A common stock outstanding:      
Weighted-average common stock outstanding—basic (in shares) 15,382,681 0 0
Weighted-average shares of Class A common stock outstanding—diluted (in shares) 60,954,639 0 0
Net loss attributable to Infinity Natural Resources, Inc. per share of Class A common stock -basic (in dollars per share) $ 0.90 $ 0 $ 0
Net loss attributable to Infinity Natural Resources, Inc. per share of Class A common stock (in dollars per share) $ 0.89 $ 0 $ 0
INR Units      
Weighted average number of Class A common stock outstanding:      
Effect of dilutive securities (in shares) 45,491,091 0  
RSUs      
Weighted average number of Class A common stock outstanding:      
Effect of dilutive securities (in shares) 80,867 0  
PSUs      
Weighted average number of Class A common stock outstanding:      
Effect of dilutive securities (in shares) 0 0  
v3.25.4
Earnings Per Share - Narrative (Details)
 12 Months Ended
Dec. 31, 2025
shares
RSUs  
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]  
Antidilutive securities excluded from the calculation of loss per share (in shares) 433,482
PSUs  
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]  
Antidilutive securities excluded from the calculation of loss per share (in shares) 426,582
v3.25.4
Commitment and Contingencies - Additional Information (Details) - South Bend Utica Farmout Agreement
 12 Months Ended
Mar. 02, 2018
a
lateral
ft
Dec. 31, 2025
Other Commitments [Line Items]    
Acreage committed | a 11,000  
Initial term for acreage development 15 years  
Number of seven thousand foot laterals | lateral 1  
Square footage of lateral (in square feet) | ft 7,000,000  
Remaining term to develop acreage   9 years
v3.25.4
Commitment and Contingencies - Schedule of Other Commitments (Details)
$ in Thousands
Dec. 31, 2025
USD ($)
Other Commitments [Line Items]  
2026 $ 19,943
2027 13,346
2028 13,962
2029 12,677
Thereafter 13,418
Total 73,346
Total minimum future volume commitments  
Other Commitments [Line Items]  
2026 14,093
2027 13,346
2028 13,962
2029 12,677
Thereafter 13,418
Total 67,496
Total minimum future service commitments  
Other Commitments [Line Items]  
2026 5,850
2027 0
2028 0
2029 0
Thereafter 0
Total $ 5,850
v3.25.4
Segment Information - Additional Information (Details)
 12 Months Ended
Dec. 31, 2025
segment
Segment Reporting [Abstract]  
Number of operating segments 1
Number of reportable segments 1
v3.25.4
Segment Information - Schedule of Segment Activity (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting Information [Line Items]      
Total revenues $ 356,431 $ 259,022 $ 161,730
Lease operating 26,675 28,154 18,371
Depreciation, depletion, and amortization 103,751 73,726 53,796
General and administrative expense [1] 153,413 13,045 4,885
Net income 13,836 0  
Gain (loss) on derivative instruments 58,407 (22,047) 45,322
Income tax expense (benefit) (4,858) 0 0
Reportable Segment      
Segment Reporting Information [Line Items]      
Total revenues 356,431 259,022 161,730
Gathering, processing, and transportation 54,779 49,290 31,097
Lease operating 26,675 28,154 18,371
Production and ad valorem taxes 5,918 1,071 886
Depreciation, depletion, and amortization 103,751 73,726 53,796
General and administrative expense 153,413 13,045 4,885
Other income (expense) (52,064) 44,450 (33,977)
Net income 63,959 49,286 86,672
Interest, net 9,666 21,529 11,910
Gain (loss) on derivative instruments 58,407 (22,047) 45,322
Other income (expense) (1,535) (874) 565
Income tax expense (benefit) $ (4,858) $ 0 $ 0
[1] General and administrative expense includes a one-time share-based compensation expense of $126.1 million for the year ended December 31, 2025, incurred in connection with the IPO (as defined herein).
v3.25.4
Subsequent Events (Details) - USD ($)
$ in Millions
Feb. 23, 2026
Jan. 20, 2026
Jan. 30, 2025
Dec. 31, 2025
Oct. 01, 2025
Sep. 30, 2025
Mar. 31, 2025
Sep. 24, 2024
INR Holdings                
Subsequent Event [Line Items]                
Shares issued in transaction (in shares)     15,237,500          
Line of Credit | Credit Facility                
Subsequent Event [Line Items]                
Maximum borrowing capacity       $ 375.0 $ 375.0 $ 350.0 $ 350.0 $ 325.0
Subsequent Event                
Subsequent Event [Line Items]                
Aggregate net proceeds from stock offering $ 337.1              
Subsequent Event | Quantum Capital Group                
Subsequent Event [Line Items]                
Shares issued in transaction (in shares) 275,000              
Subsequent Event | Camelian Energy Capital Management                
Subsequent Event [Line Items]                
Shares issued in transaction (in shares) 75,000              
Subsequent Event | INR Holdings | Upstream Assets                
Subsequent Event [Line Items]                
Assets acquired (as a percent) 60.00%              
Subsequent Event | INR Holdings | Midstream assets                
Subsequent Event [Line Items]                
Assets acquired (as a percent) 60.00%              
Subsequent Event | Northern Oil and Gas, Inc. | Upstream Assets                
Subsequent Event [Line Items]                
Assets acquired (as a percent) 40.00%              
Subsequent Event | Northern Oil and Gas, Inc. | Midstream assets                
Subsequent Event [Line Items]                
Assets acquired (as a percent) 40.00%              
Subsequent Event | INR Holdings and Norther Oil and Gas, Inc. | Upstream Assets                
Subsequent Event [Line Items]                
Consideration transferred $ 800.0              
Subsequent Event | INR Holdings and Norther Oil and Gas, Inc. | Midstream assets                
Subsequent Event [Line Items]                
Consideration transferred 400.0              
Subsequent Event | Line of Credit | Credit Facility                
Subsequent Event [Line Items]                
Maximum borrowing capacity $ 875.0              
Series A Preferred Stock | Subsequent Event                
Subsequent Event [Line Items]                
Shares issued in transaction (in shares) 350,000              
Aggregate net proceeds from stock offering $ 350.0              
Chase Acquisition | Common Class A | Subsequent Event                
Subsequent Event [Line Items]                
Issuance of shares (in shares)   2,517,194            
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Capitalized Costs (Details) - USD ($)
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Extractive Industries [Abstract]        
Proved properties $ 1,175,523,000 $ 846,738,000   $ 615,456,000
Unproved properties 88,689,000 86,490,000   37,189,000
Gross oil and natural gas properties 1,264,212,000 933,228,000   652,645,000
Accumulated depreciation, depletion, and amortization (249,296,000) (148,638,000)   (77,085,000)
Net capitalized costs 1,014,916,000 784,590,000   $ 575,560,000
Oil and Gas, Capitalized Cost, before Accumulated Depreciation, Depletion, Amortization, and Valuation Allowance, Asset Retirement $ 3,300,000 $ 2,700,000 $ 800,000  
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Costs Incurred (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Extractive Industries [Abstract]      
Proved properties $ 44,585 $ 19,172 $ 274,732
Unproved properties 5,236 89,174 1,047
Capitalized cost 274,723 165,795 144,121
Exploration costs 0 0 0
Total costs incurred $ 324,544 $ 274,141 $ 419,900
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Proved Reserves (Details)
 12 Months Ended
Dec. 31, 2025
MBbls
MMcf
Dec. 31, 2024
MBbls
MMcf
Dec. 31, 2023
MMcf
MBbls
Oil and Gas, Proved Reserve, Quantity, Volume [Roll Forward]      
Beginning balance 170,346 141,587 79,788
Extensions 67,159 36,018 44,575
Revisions to previous estimates 366 1,559 (24,069)
Purchases of reserves in place 0 0 48,194
Production (12,882) (8,818) (6,901)
Ending balance 224,989 170,346 141,587
Proved developed reserves: 100,235 68,872 67,954
Proved undeveloped reserves: 124,753 101,474 73,633
Crude Oil      
Oil and Gas, Proved Reserve, Quantity, Volume [Roll Forward]      
Beginning balance 37,354 31,038 5,913
Extensions 3,277 9,997 7,443
Revisions to previous estimates (886) (1,301) 252
Purchases of reserves in place 0 0 18,636
Production (3,074) (2,380) (1,205)
Ending balance 36,671 37,354 31,038
Proved developed reserves: 14,717 14,577 13,172
Proved undeveloped reserves: 21,954 22,777 17,866
Natural gas revenues      
Oil and Gas, Proved Reserve, Quantity, Volume [Roll Forward]      
Beginning balance | MMcf 617,015 508,725 358,337
Extensions | MMcf 362,633 127,429 168,704
Revisions to previous estimates | MMcf (17,428) 9,152 (118,920)
Purchases of reserves in place | MMcf 0 0 128,110
Production | MMcf (45,596) (28,291) (27,506)
Ending balance | MMcf 916,624 617,015 508,725
Proved developed reserves: | MMcf 417,362 248,634 252,832
Proved undeveloped reserves: | MMcf 499,262 368,382 255,893
NGL revenues      
Oil and Gas, Proved Reserve, Quantity, Volume [Roll Forward]      
Beginning balance 30,156 25,762 14,152
Extensions 3,444 4,782 9,015
Revisions to previous estimates 4,157 1,335 (4,501)
Purchases of reserves in place 0 0 8,207
Production (2,209) (1,723) (1,112)
Ending balance 35,548 30,156 25,762
Proved developed reserves: 15,958 12,856 12,644
Proved undeveloped reserves: 19,589 17,300 13,118
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Schedule of Discounted Future Net Cash Flows (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2025
USD ($)
MBbls
Dec. 31, 2024
USD ($)
MBbls
Dec. 31, 2023
USD ($)
MBbls
Dec. 31, 2022
USD ($)
Extractive Industries [Abstract]        
Future cash inflows $ 5,511,802 $ 4,181,440 $ 3,865,302  
Future development costs (764,219) (652,135) (545,803)  
Future production costs (1,824,402) (1,548,957) (1,281,802)  
Future income tax expense (531,584) 0 0  
Future net cash flows 2,391,597 1,980,348 2,037,697  
10% discount to reflect timing of cash flows (1,310,404) (1,007,830) (1,099,313)  
Standardized measure of discounted future net cash flows $ 1,081,193 $ 972,518 $ 938,384 $ 1,017,607
Revisions to previous estimates | MBbls 366 1,559 (24,069)  
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Standardized Measure of Discounted Net Cash Flows Roll Forward (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 of period $ 972,518 $ 938,384 $ 1,017,607
Sales of oil, natural gas, NGLs, net of production costs (263,003) (176,822) (109,179)
Acquisitions of reserves 0 0 534,927
Extensions, net of future development costs 299,655 200,954 199,378
Net change in price and production costs 238,597 (264,003) (643,905)
Previously estimated development costs incurred 118,750 140,274 68,412
Change in estimated future development costs (27,274) (7,170) 4,734
Revisions of previous quantity estimates 22,064 45,803 (224,318)
Accretion of discount 79,321 93,838 101,761
Net change in income taxes (251,800) 0 0
Net change in timing of production and other (107,635) 1,260 (11,034)
End of period $ 1,081,193 $ 972,518 $ 938,384
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Narrative (Details)
 12 Months Ended
Dec. 31, 2025
USD ($)
MMBoe
well
location
MBbls
Dec. 31, 2024
USD ($)
MMBoe
location
well
MBbls
Dec. 31, 2023
MMBoe
well
location
MBbls
Dec. 31, 2022
USD ($)
Oil and Gas, Proved Reserve, Quantity [Line Items]        
Extensions | MBbls 67,159 36,018 44,575  
Revisions to previous estimates | MBbls 366 1,559 (24,069)  
Proved properties | $ $ 1,175,523,000 $ 846,738,000   $ 615,456,000
Unweighted arithmetic average period 12 months      
Future net cash flows discounted rate 10.00%      
Extensions        
Oil and Gas, Proved Reserve, Quantity [Line Items]        
Proved developed reserves, total extensions     32.5  
PUD locations | location 28      
Acreage initial term 5 years 5 years 5 years  
Natural gas (per MMBtu) 53.0 35.3    
Proved undeveloped reserve, quantity, energy 14.2 0.7 12.0  
Number of wells committed for drilling | well 9 18 6  
Oil and gas development, well, number of producing | well   2 2  
Proved undeveloped locations | location   27    
Addition from extension 67.2 36.0 44.6  
Number of wells added | well     21  
Revisions To Previous Estimates        
Oil and Gas, Proved Reserve, Quantity [Line Items]        
Proved developed reserves, total extensions 0.4 1.5 24.1  
PUD locations | location 2 8 18  
Acreage initial term   5 years 5 years  
Proved developed downward revisions to PUD reserves 4.6 5.2 20.8  
Upward revisions 5.0      
Proved developed producing properties, upward revisions     3.3  
Downward revisions   6.5    
Purchases Of Reserves In Place        
Oil and Gas, Proved Reserve, Quantity [Line Items]        
Natural gas (per MMBtu)     48.2  
Purchases Of Reserves In Place | Ohio Utica        
Oil and Gas, Proved Reserve, Quantity [Line Items]        
Natural gas (per MMBtu)     20.4  
Proved undeveloped reserve, quantity, energy     27.8  
v3.25.4
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Standardized Measure Relating To Proved Oil And Natural Gas Reserves (Details)
 12 Months Ended
Dec. 31, 2025
$ / MMBTU
$ / bbl
Dec. 31, 2024
$ / MMBTU
$ / bbl
Dec. 31, 2023
$ / MMBTU
$ / bbl
Oil revenues      
Oil and Gas, Proved Reserve, Quantity [Line Items]      
Average sale price per unit 58.61 67.98 73.73
Natural gas revenues      
Oil and Gas, Proved Reserve, Quantity [Line Items]      
Average sale price per unit | $ / MMBTU 2.77 1.42 1.74
NGL revenues      
Oil and Gas, Proved Reserve, Quantity [Line Items]      
Average sale price per unit 23.20 25.48 26.87