INFINITY NATURAL RESOURCES, INC.
For the period ended Dec 31, 2025. Filed Mar 10, 2026.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Mar 10, 2026
INR$12.79+4.4%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-03-28.
0001193125-25-067100
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-03-10.
0002029118-26-000014
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 129 previous paragraphs and 135 current paragraphs.
73 unchanged; 30 reworded; 30 added; 26 removed; 0 previous and 2 current paragraphs rearranged.
Tables are not compared: 28 previous and 17 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (30)
Current report
Antero Acquisition
Current report
On February 23, 2026, we and Northern completed the Antero Acquisition of the Upstream Assets from the Upstream Sellers and the Midstream Assets from the Midstream Sellers. The Upstream Assets include approximately 42,500 net surface acres in the Ohio Utica Shale across Guernsey, Noble, Belmont, and Monroe Counties, which are highly contiguous with and complementary to our existing Ohio operations. The assets include an estimated 370.1 Bcfe of proved reserves and approximately 110 identified undeveloped drilling locations across multiple phase windows. The Midstream Assets include approximately 141 miles of natural gas gathering pipelines, with capacity to support up to 600 MMcf/d, and approximately 90 miles of freshwater and produced‑water infrastructure. These assets enhance our vertical integration and are expected to reduce operating costs, improve margins, and enable efficient full‑field development.
Current report
Infinity will operate substantially all of the Antero Ohio Assets pursuant to joint development and cooperation agreements entered into with Northern at closing. We funded the transaction with cash on hand, the proceeds of the Preferred Investment and borrowings under our Credit Facility, which was amended and expanded in connection with closing.
Current report
Chase Acquisition
Current report
On January 20, 2026, the Company and INR Holdings entered into a purchase and sale agreement (the “Chase Purchase Agreement”) with Chase Oil Corporation, a New Mexico corporation, and certain other sellers (each a “Chase Seller” and, collectively, “Chase Sellers”) for the acquisition of certain non-operated rights, title and interests in oil and gas properties, rights and related assets located in the State of Pennsylvania from the Chase Sellers (the “Chase Acquisition”), for consideration of 2,517,194 shares of the Company’s Class A common stock. The Chase Acquisition closed on January 20, 2026, simultaneously with the execution of the Chase Purchase Agreement.
Current report
Share Repurchase Program
Current report
On November 10, 2025, our board of directors authorized the Share Repurchase Program, whereby we may purchase up to an aggregate of $75 million of our Class A common stock. The Company repurchased 87,132 shares for a total of $1.2 million during the quarter ended December 31, 2025. As of December 31, 2025, we had $73.8 million remaining under the Share Repurchase Program. Repurchases under the Share Repurchase Program may be made from time to time in the open market, in privately negotiated transactions, through purchases made in accordance with Rule 10b5-1 of the Exchange Act, or by such other means as will comply with applicable state and federal securities laws.The timing of any such repurchases will depend on market conditions, contractual limitations and other considerations. The Share Repurchase Program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.
Current report
Amendments to Credit Agreement
Current report
On December 5, 2025, INR Holdings entered into that certain Third Amendment to Credit Agreement (the “Third Credit Agreement Amendment”). The Third Credit Agreement Amendment, among other things, amended certain provisions relating to hedging requirements and restrictions, debt incurrences and permitted acquisitions in the Credit Agreement.
Current report
On February 23, 2026, INR Holdings entered into that certain Fourth Amendment to Credit Agreement (the “Fourth Credit Agreement Amendment”). The Fourth Credit Agreement Amendment, among other things, amends certain provisions to (i) increase the aggregate elected commitment amount from $375.0 million to $875.0 million, (ii) increase the borrowing base from $375.0 million to $875.0 million and (iii) remove the credit spread adjustment that was previously applicable to all Secured Overnight Financing Rate (“SOFR”) borrowings under the Credit Agreement.
Current report
Preferred Investment
Current report
On February 23, 2026, we issued and sold, pursuant to the Securities Purchase Agreement an aggregate 350,000 shares of Series A Preferred Stock to affiliates of Quantum and affiliates of Carnelian for consideration of $350 million. After deducting placement agent fees, Infinity received net proceeds of approximately $337.1 million. Quantum acquired 275,000 shares of Series A Preferred Stock and Carnelian acquired 75,000 shares of Series A Preferred Stock. The Company used the proceeds of the Preferred Investment to fund a portion of the Antero Acquisitions and will use any remaining proceeds for general corporate purposes.
Current report
(1)Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Current report
(2)Based on Netherland, Sewell and Associates Inc. (“NSAI”) found athttps://netherlandsewell.com/resources/pricing-data/ and U.S. Energy Information Administration commodity pricing.
Current report
(3)Weighted average is based on INR’s production in a given month during the course of the calendar year.
Current report
Net production volumes for oil increased 29%, natural gas increased 61% and NGLs increased 28%, respectively, between periods. The oil, natural gas and NGL production volume increase resulted from placing 23 wells on production across our oil weighted assets in the Ohio Utica’s volatile oil window and our natural gas weighted assets in the Marcellus Shale in Pennsylvania during the fourth quarter of 2024 and 2025. The addition of these wells contributed to the overall increase of 11.2 MBoe/d, or 46%, in production relative to the prior period.
Current report
Average realized natural gas prices rose 54% during the period driven by higher NYMEX prices and improved differentials. Oil prices fell 17%, reflecting lower NYMEX WTI prices. NGL prices decreased 15% due to lower Mont Belvieu spot prices and changes in product mix.
Current report
On February 23, 2026, we closed the Antero Acquisition for consideration of approximately $720 million net to Infinity. See “Item 1. Business—Recent Acquisition—Antero Acquisition.” We funded the transaction with cash on hand, the proceeds of the Preferred Investment and borrowings under our Credit Facility, the borrowing base and aggregate elected commitment amount of which increased from $375.0 million to $875.0 million in connection with closing.
Current report
In connection with the closing of the Antero Acquisition, we also completed a private placement of Series A Convertible Preferred Stock, which generated gross proceeds of $350 million and net proceeds of $337.1 million after deducting placement agent fees. The proceeds from the Preferred Investment were used to fund a portion of the acquisition. The Series A Preferred Stock provides long‑term capital with no stated maturity; however, it accrues cumulative dividends that may be paid in kind for a limited period, after which dividends must be paid in cash, subject to restrictions under our Credit Facility. Any dividends paid in kind increase the liquidation preference of the Series A Preferred Stock and may increase future cash requirements. We believe the Preferred Investment enhances our overall liquidity and financial flexibility while supporting the execution of our development and acquisition strategy.
Current report
(1)These natural gas basis swap contracts are settled based on the difference between Dominion South, REX Zone 3 or TETCO M2 price and the NYMEX price of natural gas during each applicable monthly settlement period.
Current report
(1)At inception, new derivative contracts entered into by us have no intrinsic value.
Current report
On September 25, 2024, we entered into a new credit facility led by Citibank, N.A. (the “Credit Facility”). The Credit Facility has a total facility size of $1.5 billion, subject to lender commitments and borrowing base limitations. As of December 31, 2025, our elected commitments and borrowing base were $375.0 million of which $150.9 million was outstanding. On February 23, 2026, in connection with the closing of the Antero Acquisition, we amended our Credit Facility to, among other things, increase the aggregate elected commitment amount from $375.0 million to $875.0 million and increase the borrowing base from $375.0 million to $875.0 million.
Current report
•Current ratio – the ratio of consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Amended and Restated Credit Facility and non-cash derivative liabilities) of not less than 1.0 to 1.0 ; and
Current report
•Leverage ratio – the ratio of total funded debt to consolidated EBITDAX of not greater than 3.0 to 1.0 .
Current report
•Current ratio – the ratio of consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Amended and Restated Credit Facility and non-cash derivative liabilities) of not less than 1.0 to 1.0; and
Current report
Recently Issued Accounting Standards
Current report
Refer to Note 2-Summary of Significant Accounting Policies, in Part II, Item 8. Financial Statements and Supplementary Data in this Annual Report for a discussion of recently issued accounting standards and their anticipated effect on our business.
Current report
(1)This reflects borrowings outstanding under our Credit Facility as of December 31, 2025; Credit Facility borrowings may be repaid and reborrowed prior to maturity.
Current report
(2)This debt bears interest at the SOFR plus a borrowing spread. In determining future interest, we used outstanding amounts at December 31, 2025 and the average borrowing cost for calendar year 2025.
Current report
(3)This amount includes commitments from drilling rig contracts, vehicle notes, and operating leases.
Removed paragraphs (26)
Previous report
Initial Public Offering
Previous report
Corporate Reorganization
Previous report
In connection with the IPO we underwent a Corporate Reorganization whereby: (a) the membership interests of the Legacy Owners in INR Holdings (including the Incentive Units, as defined in Item 11. “Executive Compensation—Narrative Disclosure to Summary Compensation Table—Long-Term Equity Incentive Compensation”) 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 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. After giving effect to the Corporate Reorganization and the IPO, we own an approximate 25.0% interest in INR Holdings and the Legacy Owners own an approximate 75.0% interest in INR Holdings.
Previous report
Infinity is a holding company whose sole material asset consists of membership interests in INR Holdings. Infinity is the managing member of INR Holdings and controls and is responsible for all operational, management and administrative decisions relating to INR Holdings’ business and consolidates the financial results of INR Holdings and reportsnon-controlling interests in its consolidated financial statements related to the INR Units that the Legacy Owners own in INR Holdings. In connection with the Corporate Reorganization, INR Holdings and Infinity entered into the INR Holdings LLC Agreement and a Tax Receivable Agreement. For additional information on the INR Holdings LLC Agreement and Tax Receivable Agreement, see “Item 13. Certain Relationships and Related Transactions, and Director Independence.”
Previous report
Muskingum Watershed Lease
Previous report
In December 2024, we closed on a lease with Muskingum Watershed Conservancy District for approximately 1,900 acres in Guernsey and Noble Counties, Ohio.
Previous report
We utilize unaffiliated third parties to market a portion of our oil, natural gas, and NGL production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations and super majors in our industry. The third parties collect proceeds directly from these purchasers and remit to us the total of all amounts collected on our behalf less the third party’s fee for making such sales. We do not believe the loss of any purchaser would have a material adverse effect on our business, as other purchasers or markets are currently accessible to us.
Previous report
Principal Components of Our Cost Structure
Previous report
Lease operating. LOE are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water disposal, materials, and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor, materials, and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our well equipment or surface facilities result in increased LOE in periods during which they are performed. Certain operating cost components are variable and fluctuate based on production levels. For example, the disposal of produced water usually increases in conjunction with increased production. Also, we monitor our LOE in absolute dollar terms and on a per Boe and/or Mcfe basis to assess our performance and to determine if any wells or properties should be shut in, repaired or recompleted.
Previous report
Gathering, processing, and transportation. Gathering, processing, and transportation expense includes fees paid to third parties who operatelow- and high-pressure gathering systems that transport our gas. It also includes costs to process, extract, and fractionate NGLs from our liquids-rich gas and transport our natural gas and NGLs to market.
Previous report
Production and ad valorem taxes. Pennsylvania imposes an annual impact fee on each producing shale well for a period of 15 years beginning in the year the well is spud. Ohio imposes a production tax which is based upon annual production. The proportion of our production and producing wells from each state may change over time and, as a result, the proportion of our production taxes and impact fees will vary depending on volumes produced from the Utica Shale, the number of producing shale wells in Pennsylvania, and the applicable production tax rates and impact fees then in effect. In addition, we are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties as well as the value of property and equipment.
Previous report
Depreciation, depletion, and amortization. Depreciation, depletion, and amortization includes the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas. Under the full- cost method of accounting, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization. Accretion expense related to our asset retirement obligations is also included within this balance.
Previous report
General and administrative. General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, IT expenses, legal, audit and other fees for professional services. G&A expenses are offset by recoveries for overhead that are billed to our joint-interest partners as outlined in a joint operating agreement or other similar documents.
Previous report
Interest expense. We have financed a portion of our working capital requirements and property acquisitions with borrowings under our prior credit facility and Credit Facility. As a result, we incur interest expense that is affected by fluctuations in interest rates and, in the case of the prior credit facility and Credit Facility based on outstanding borrowings. We expect to see a reduction in cash interest expense following the completion of the IPO in February 2025 as we repaid substantially all of our outstanding borrowings under the Credit Facility with the net proceeds of the IPO.
Previous report
Gains and losses on derivatives. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of oil, natural gas, and NGLs. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are recorded at fair value as of the balance sheet date with changes in fair value recognized as a gain or loss in our results of operations. Our operating cash flows are impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.
Previous report
Public Company Expenses. We expect to incur direct, incremental G&A expenses as a result of being a public company, including costs associated with Exchange Act compliance, tax compliance, PCAOB support fees, SOX compliance costs, investor relations activities, listing fees, registrar and transfer agent fees, stock-based compensation, incremental director and officer liability insurance costs, and independent director compensation. We estimate these direct, incremental G&A expenses could total approximately $4 million to $6 million per year, which are not included in our historical results of operations.
Previous report
Net production volumes for oil, natural gas, and NGLs increased 98%, 3% and 55%, respectively, between periods. The oil and NGL production volume increase resulted from placing fourteen (14) wells on production from the Ohio Utica’s Volatile Oil Window since December 31, 2023. The higher increase in natural gas volumes between periods was due to the fourteen (14) wells that were placed on production during the year 2024, offset from the normal production decline across existing wells. The combination of a full year of production from the wells acquired from Utica Resource Ventures and PEO Ohio and wells placed into production throughout 2024 contributed to the overall increase of 1.9 MMBoe in production, or of 28% relative to the prior year.
Previous report
Average realized sales prices for NGLs increased 18% during the period while average realized oil and natural gas sales prices decreased 4% and 2%, respectively, for the year ended December 31, 2024 compared to the prior year. Average realized natural gas prices remained consistent when compared to the same period a year earlier. The 4% decrease in the average realized oil price was mainly driven by lower NYMEX WTI oil prices during the period along with higher regional differentials compared to the same period a year earlier. The average realized natural gas price decreased 2% due to 19% lower average NYMEX gas prices between periods offset by lower natural gas differentials. The 18% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in 2024 compared to 2023 and changes in product composition between periods.
Previous report
We used all of the net proceeds after paying certain offering expenses of the IPO to repay outstanding borrowings under the Credit Facility. Following such repayment, as of February 28, 2024, we had $2.4 million of borrowings outstanding under the Credit Facility.
Previous report
Adoption of New Accounting Standards
Previous report
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280)—Improvements to Reportable Segment Disclosures (“ASU 2023-07”), which updates reportable segment disclosure requirements primarily by enhancing disclosures about significant segment expenses and information used to assess segment performance. Additionally, ASU 2023-07 enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss and provides new segment disclosure requirements for entities with a single reportable segment. The amendments are effective for annual periods beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. We adopted this ASU and applied the amendments retrospectively to all prior periods presented in our consolidated financial statements. Refer to* Note 15 - Segment Information*for additional discussion.
Previous report
Accounting Standards Not Yet Adopted
Previous report
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. Management is currently evaluating this ASU to determine its impact on INR Holdings’ disclosures. The Company is in the process of assessing the impact of this ASU on its consolidated financial statements subsequent to the IPO transaction in February 2025.
Previous report
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. As of December 31, 2024, this is ASU is not applicable to the company due no stock compensation expense. The Company is in the process of assessing the impact of this ASU on its consolidated financial statements subsequent to the IPO transaction in February 2025.
Previous report
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 ofoil- andgas-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***.***
Previous report
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.
Reworded paragraphs (30)
Previous wording
The following should be read in conjunction with our financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks, and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, future market prices for oil, natural gas and NGLs, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, and other uncertainties, as well as those factors discussed in “Cautionary Statement Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise indicated, the historical financial information presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” speaks only with respect to our predecessor, INR Holdings, and does not give pro forma effect to our corporate reorganization described in “Item 1. Business—Corporate Reorganization.”
Current wording
The following should be read in conjunction with our financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks, and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, future market prices for oil, natural gas and NGLs, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, and other uncertainties, as well as those factors discussed in “Cautionary Statement Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Previous wording
We are a growth oriented independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian Basin. We are focused on creating shareholder value through the identification and disciplined development oflow-risk, highly economic oil and natural gas assets while maintaining a strong and flexible balance sheet. We are an early mover into the core of the Utica Shale’s volatile oil window in eastern Ohio as well as the emerging dry gas Utica Shale in southwestern Pennsylvania. Our Marcellus Shale development overlays our deep dry gas Utica assets in Pennsylvania, providing highly economic stacked development inventory that leverages the same company-owned midstream infrastructure. We have amassed approximately 93,000 net surface acres with exposure to the core of these plays providing us a unique and balanced portfolio of high-return oil and natural gas drilling locations. This balance allows us to optimize our development plan across our portfolio to capitalize on changes in commodity pricing over time.
Current wording
We are a growth oriented independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible balance sheet. Our operations are focused on the Utica Shale in eastern Ohio as well as our dry gas assets in both the Marcellus and Utica Shales in southwestern Pennsylvania, providing highly economic stacked development inventory that leverages shared infrastructure and operational efficiencies. Our portfolio is balanced across oil and natural gas assets, allowing us to optimize our development plan to respond to changes in commodity prices over time. Unless expressly stated otherwise, the operating and financial information presented in this Annual Report does not give effect to the completion of the Antero Acquisition or the Preferred Investment (each as defined herein).
Previous wording
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2023 through December 31, 2024, spot prices for NYMEX WTI crude oil ranged from $69.99 per Bbl to $89.43 per Bbl, while the range for NYMEX Henry Hub natural gas spot prices was between $1.57 per MMBtu and $4.75 per MMBtu. We expect that the commodity market will continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. We use a derivative portfolio and firm sales contracts to mitigate the risks of price volatility.
Current wording
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2024 through December 31, 2025, spot prices for NYMEX WTI crude oil ranged from $68.24 per Bbl to $85.35 per Bbl, while the range for NYMEX Henry Hub natural gas spot prices was between $1.57 per MMBtu and $3.91 per MMBtu. We expect that the commodity market will continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. We use a derivative portfolio and firm sales contracts to mitigate the risks of price volatility.
Previous wording
Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Oil, natural gas, and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate. During 2024 and 2023, our oil, natural gas, and NGL revenues were comprised of 63% and 53%, respectively, from the sale of oil, 20% and 31%, respectively, from the sale of natural gas, and 17% and 15%, respectively, from the sale of NGLs.
Current wording
Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Oil, natural gas, and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate. During 2025 and 2024, our oil, natural gas, and NGL revenues were comprised of 50% and 63%, respectively, from the sale of oil, 36% and 20%, respectively, from the sale of natural gas, and 14% and 17%, respectively, from the sale of NGLs.
Previous wording
Corporate Reorganization. The historical consolidated financial statements included in this Annual Report are based on the financial statements of our predecessor, INR Holdings, prior to our reorganization in connection with the IPO as described in “Item 1. Business—Corporate Reorganization.” Our historical financial data may not yield an accurate indication of what our actual results would have been if those transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. In connection with the closing of the IPO, all outstanding performance-based incentive units of INR Holdings vested. Consequently, INR Holdings will recognize $126.1 million ofnon-recurring, non-cash compensation expense related to these awards in the first quarter of 2025, in accordance with the guidance provided by ASC 710.
Current wording
Corporate Reorganization. The 2023 and 2024 consolidated financial statements included in this Annual Report are based on the financial statements of our predecessor, INR Holdings, prior to our Corporate Reorganization in connection with the IPO as described in “Item 1. Business—Corporate Reorganization.” Our historical financial data may not yield an accurate indication of what our actual results would have been if those transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. In connection with the closing of the IPO, all outstanding performance-based incentive units of INR Holdings vested.
Previous wording
Interest Expense. In connection with the IPO, we materially reduced our indebtedness through the repayment of substantially all of our outstanding borrowings under the Credit Facility with net proceeds of the IPO. As a result, we expect an immediate reduction in cash interest expense.
Current wording
Interest Expense. In connection with the IPO, we materially reduced our indebtedness through the repayment of substantially all of our outstanding borrowings under the Credit Facility with net proceeds of the IPO. As a result, our cash interest expense was lower in 2025 than 2024.
Previous wording
Income Taxes. Our predecessor, INR Holdings, was organized as a limited liability company not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to our members. Although we are a corporation under the Internal Revenue Code of 1986, as amended (the “Code”), we do not expect to report any income tax benefit or expense prior to the consummation of the IPO.
Current wording
Income Taxes. Our predecessor, INR Holdings, was organized as a limited liability company not subject to federal income taxes. Accordingly, no provision for federal income taxes was provided for in our historical results of operations for 2024 because taxable income was passed through to our members. Following the Corporate Reorganization, we are a corporation under the Internal Revenue Code of 1986, as amended (the “Code”), and we will report income tax benefit or expense for 2025 and going forward.
Previous wording
In February 2025, Infinity completed its IPO of 15,237,500 shares of its Class A common stock (including 1,987,500 shares pursuant to an over-allotment option) at a price to the public of $20.00 per share. The aggregate gross proceeds of the IPO were $304.8 million. After subtracting underwriting discounts and commissions, we received net proceeds of $286.5 million. We contributed all of the net proceeds from the IPO to INR Holdings in exchange for 15,237,500 INR Units. In turn, INR Holdings used all of the net proceeds from the IPO (net of underwriting discounts) after paying certain offering expenses to repay $285.0 million of outstanding borrowings under the Credit Facility. After giving effect to the IPO and the transactions related thereto, we had 15,237,500 shares of Class A common stock and 45,638,889 shares of Class B common stock issued and outstanding. In connection with the closing of the IPO, all outstanding performance-based incentive units of INR Holdings vested. Consequently, INR Holdings will recognize $126.1 million ofnon-recurring, non-cash compensation expense related to these awards in the first quarter of 2025, in accordance with the guidance provided by ASC 710.
Current wording
Non-Cash Compensation Expense. In connection with the closing of the IPO, all outstanding incentive units of INR Holdings vested. Consequently, the Company recognized $126.1 million of non-recurring, non-cash stock compensation expense related to these awards, in accordance with the guidance provided by ASC 710.
Previous wording
*Oil, natural gas, and NGL sales.*Total oil, natural gas and NGL net revenues for the year ended December 31, 2024 increased by $98.2 million, or 62%, compared to the year ended December 31, 2023. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Current wording
Oil, natural gas, and NGL sales. During 2025 and 2024, our oil, natural gas, and NGL revenues were comprised of 50% and 63%, respectively, from the sale of oil, 36% and 20%, respectively, from the sale of natural gas, and 14% and 17%, respectively, from the sale of NGLs. Net revenues for the year ended December 31, 2025 increased by $92.7 million, or 36%, compared to the year ended December 31, 2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Previous wording
Gathering, processing, and transportation.* *Gathering, processing, and transportation (“GP&T”) for the year ended December 31, 2024, increased $18.2 million compared to the year ended December 31, 2023. This increase is attributed to additional wells brought online in Ohio between periods. GP&T per Boe was $5.59 for the year ended December 31, 2024, which represents an increase of $1.08 per Boe or 24% from the prior year. This increase was primarily related to increased gas volumes in Ohio that are on third party gathering systems and lower volumes on INR’s owned gathering system in Pennsylvania.
Current wording
Gathering, processing, and transportation. Gathering, processing, and transportation (“GP&T”) for the year ended December 31, 2025, increased $5.5 million compared to the year ended December 31, 2024. This increase was attributed to additional wells brought online in Ohio between periods. GP&T per Boe was $4.25 for the year ended December 31, 2025, which represents a decrease of $1.34 per Boe, or 24%, from the prior period. The decrease in per-unit GP&T rate was primarily attributable to increased production volumes in our natural gas-weighted areas of Pennsylvania, which are subject to lower GP&T rates on our internal gathering systems. This shift in volume mix reduced our overall average GP&T rate, as these areas incur fewer processing charges compared to our wet gas-weighted areas in Ohio, where the NGLs require additional processing.
Previous wording
Lease operating. Lease operating expense (“LOE”) for the year ended December 31, 2024, increased $9.8 million compared to the prior year. LOE per Boe was $3.19 for the year ended December 31, 2024, which represents an increase of $0.53 per Boe, or 20%, from the prior year. This increase in LOE was primarily related to higher fixed and semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new producing wells drilled or acquired. The higher well count as of December 31, 2024 was primarily due to the acquisition of 50 gross operated horizontal wells from Utica Resources Ventures and PEO Ohio that INR operated for the fourth quarter 2023 and 14 wells INR placed on production since December 31, 2023. In addition, lower natural gas volumes from our assets located in Pennsylvania contributed to the per unit increase.
Current wording
Lease operating. Lease operating expense (“LOE”) for the year ended December 31, 2025, decreased $1.5 million compared to the prior period. LOE per Boe was $2.07 for the year ended December 31, 2025, which represents a decrease of $1.12 per Boe, or 35%, from the prior period. This decrease in LOE was primarily related to a combination of (a) lower fixed and semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new producing wells drilled or acquired and (b) higher volumes from our Pennsylvania Marcellus development.
Previous wording
Production and ad valorem taxes*.*Production and ad valorem taxes for the year ended December 31, 2024, increased $0.2 million compared to the prior year. Production taxes in Ohio are based on our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Production taxes in Pennsylvania are assessed on producing wells by imposing an impact fee determined based on the market price for natural gas, which commences on the date the well is initially spud and continues for a period of 15 years.
Current wording
Production and ad valorem taxes. Production and ad valorem taxes for the year ended December 31, 2025, increased $4.8 million compared to the prior year. Production taxes in Ohio are based on our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Production taxes in Pennsylvania are assessed on producing wells by imposing an impact fee determined based on the market price for natural gas, which commences on the date the well is initially spud and continues for a period of 15 years.
Previous wording
***Depreciation, Depletion and Amortization.***For the year ended December 31, 2024, DD&A expense was to $73.7 million, an increase of $19.9 million over the prior year. The primary factor contributing to higher DD&A expense in 2024 was the increase in our overall production volumes between periods, which increased DD&A expense by $13.7 million, while our higher DD&A rate of $8.10 per Boe increased total DD&A expense by $6.5 million between periods. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves.
Current wording
Depreciation, Depletion and Amortization. For the year ended December 31, 2025, depreciation, depletion and amortization (“DD&A”) expense was $103.8 million, an increase of $30.0 million over the prior period. The primary factor contributing to higher DD&A expense in 2025 was the increase in our overall production volumes between periods, which resulted in an average DD&A rate of $7.81 per Boe.
Previous wording
General and Administrative Expenses.* *G&A expenses for the year ended December 31, 2024 were $13.0 million compared to $4.9 million for the prior year. This increase was primarily due to fees related to legal, accounting and auditing services. We also had higher payroll and employee-related costs due to higher headcount, which increased from 49 as of December 31, 2023 to 80 as of December 31, 2024.
Current wording
General and Administrative Expenses. General and administrative (“G&A”) expenses for the year ended December 31, 2025 were $153.4 million compared to $13.0 million for the prior year. This increase was primarily due to higher payroll and employee costs, including a one-time non-cash stock compensation expense of $126.1 million expense recognized at IPO.
Previous wording
Refer to** “* Management’s Discussion and Analysis of Financial Condition and Results of Operations*”** in the Company’s final prospectus filed with the SEC on February 3, 2025 pursuant to Rule 424(b)(4) for a discussion of the results of operations for the year ended December 31, 2023 compared to the year ended December 31, 2022.
Current wording
Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2024 Annual Report on Form 10-K filed with the SEC for a discussion of the results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023.
Previous wording
Historically, our primary sources of liquidity have been cash flows from operations, borrowings incurred under our Credit Facility and proceeds from sales of equity securities. Going forward, we expect our primary sources of liquidity to be cash flows from operations, borrowings incurred under our Credit Facility, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and gas properties. Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary uses of capital have been for drilling and development capital expenditures and the acquisition of oil and natural gas properties.
Current wording
Historically, our primary sources of liquidity have been cash flows from operations, borrowings incurred under our Credit Facility and proceeds from sales of equity securities. Going forward, we expect our primary sources of liquidity to be cash flows from operations, borrowings incurred under our Credit Facility, proceeds from offerings of debt or equity securities, such as the Preferred Investment, or proceeds from the sale of oil and gas properties. Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary uses of capital have been for drilling and development capital expenditures and the acquisition of oil and natural gas properties.
Previous wording
We continually evaluate our capital needs and compare them to our capital resources. Our total cash capital expenditures incurred for development during the year ended December 31, 2024 were $279.7 million, which includes $165.8 million on drilling and completion activities, $5.5 million on midstream and $108.3 on maintenance leasehold and land investment. We funded our capital expenditures for the year ended December 31, 2024 from cash flows from operations and borrowings incurred under our Credit Facility. Our drilling and completion capital budget for 2025 is $240 million to $280 million, along with $9 million to $12 million of midstream capital expenditures. We expect to fund our 2025 capital expenditures budget through a combination of cash flows from operations and additional borrowings under our Credit Facility. Our ability to utilize cash flows from operations to fund our development program is driven by our oil and gas production, current commodity prices and our commodity hedge positions in place.
Current wording
We continually evaluate our capital needs and compare them to our capital resources. Our total capital expenditures incurred for development during the year ended December 31, 2025 were $326.2 million, which includes $274.7 million on drilling and completion activities, $16.1 million on midstream and $35.5 million on land activities. We funded our capital expenditures for the year ended December 31, 2025 from cash flows from operations and borrowings incurred under our Credit Facility. Our development capital budget for 2026 is $450 million to $500 million, which includes drilling and completions and midstream capital expenditures. We expect to fund our 2026 capital expenditures budget through a combination of cash flows from operations and additional borrowings under our Credit Facility, as well as the proceeds of the Preferred Investment. Our ability to utilize cash flows from operations to fund our development program is driven by our oil and gas production, current commodity prices and our commodity hedge positions in place.
Previous wording
Our liquidity requirements also include operating expenses, which have been impacted by elevated levels of inflation. High oil prices have historically led to more development activity inoil-focused shale basins and resulted in service cost inflation across all U.S. shale basins, including our areas of operation. Ongoing inflationary pressures may result in increases to the costs of our oilfield goods, services and personnel, which would, in turn, cause our capital expenditures and operating costs to rise. We closely monitor costs and are cost conscious in managing our operations. We may solicit bids from multiple vendors or contractors or source materials from multiple suppliers to take advantage of cost competition, and we may buy surplus materials if we can acquire them on attractive terms. Where we anticipate elevated costs may be more sustained, such as in the cost of services, we may enter into contracts with certain service providers to lock in rates. We are also strategic in the duration of our contracts to provide flexibility to take advantage of cost declines when they occur. Sustained levels of high inflation have also caused the U.S. Federal Reserve and other central banks to increase interest rates, which has raised the cost of capital and increased our interest expense.
Current wording
Our liquidity requirements also include operating expenses, which have been impacted by elevated levels of inflation. High oil prices have historically led to more development activity in oil-focused shale basins and resulted in service cost inflation across all U.S. shale basins, including our areas of operation. Ongoing inflationary pressures may result in increases to the costs of our oilfield goods, services and personnel, which would, in turn, cause our capital expenditures and operating costs to rise. We closely monitor costs and are cost conscious in managing our operations. We may solicit bids from multiple vendors or contractors or source materials from multiple suppliers to take advantage of cost competition, and we may buy surplus materials if we can acquire them on attractive terms. Where we anticipate elevated costs may be more sustained, such as in the cost of services, we may enter into contracts with certain service providers to lock in rates. We are also strategic in the duration of our contracts to provide flexibility to take advantage of cost declines when they occur. Sustained levels of high inflation have also caused the U.S. Federal Reserve and other central banks to increase interest rates, which has raised the cost of capital and increased our interest expense.
Previous wording
For the year ended December 31, 2023, we spent $146.0 million on capital expenditures in conjunction with our drilling and completion activities in which we drilled and brought online 10 gross operated wells and land and leasehold costs, and $279.0 million to complete the Utica Resource Acquisition and PEO Ohio Acquisition, which included 50 gross operated wells. We also spent $11.7 million on other property and equipment.
Current wording
For the year ended December 31, 2025, we spent $356.4 million on capital expenditures in conjunction with our development activities in which we drilled and brought online 23 gross operated wells and land and leasehold costs, and $61.2 million on deposits related to the Antero Acquisition. We also spent $12.6 million on other property and equipment largely related to midstream activities.
Previous wording
For the year ended December 31, 2024, we spent $249.5 million on capital expenditures in conjunction with our drilling and completion activities in which we drilled and brought online 14 gross operated wells and land and leasehold costs. We also spent $6.6 million on other property and equipment largely related to midstream activities.
Current wording
For the year ended December 31, 2024, we spent $249.5 million on capital expenditures in conjunction with our development activities in which we drilled and brought online 14 gross operated wells and land and leasehold costs. We also spent $6.6 million on other property and equipment largely related to midstream activities.
Previous wording
For the year ended December 31, 2024, the change in financing activity was primarily related to borrowing $168.1 million under our credit facility and repaying $79.7 million of borrowings. In September 2024, as part of entering into the new Credit Facility, we used funds from the new Credit Facility of $243.4 million for the repayment of the outstanding balance on the prior credit facility. We also paid approximately $5.2 million of syndication fees associated with the new Credit Facility.
Current wording
For the year ended December 31, 2025, the change in financing activity was primarily related to borrowing $253.5 million under our credit facility and repaying $362.0 of borrowings. We received approximately $286.5 million of funds associated with the IPO used in the repayment of borrowings.
Previous wording
For the year ended December 31, 2023, the change in financing activity was primarily related to borrowing $203.9 million under our prior credit facility and repaying $90.8 million of borrowings. Additionally, there was a capital raise for $222.3 million used to partially fund the Utica Resource Acquisition and PEO Ohio Acquisition. We also paid approximately $4.3 million in syndication fees associated with the prior credit facility.
Current wording
For the year ended December 31, 2024, the change in financing activity was primarily related to borrowing $168.1 million under our prior credit facility and repaying $79.7 million of borrowings. We also paid approximately $5.2 million in syndication fees associated with the prior credit facility.
Previous wording
Analysis of Cash Flow Changes Between the Year Ended December 31, 2023 and 2022
Current wording
Analysis of Cash Flow Changes Between the Years Ended December 31, 2024 and 2023
Previous wording
Refer to** “Management’s Discussion and Analysis of Financial Condition and Results of Operations”** in the Company’s final prospectus filed with the SEC on February 3, 2025 pursuant to Rule 424(b)(4) for a discussion of the cash flows for the year ended December 31, 2023 compared to the year ended December 31, 2022.
Current wording
Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in the 2024 Annual Report on Form 10-K filed with the SEC for a discussion of the cash flows for the year ended December 31, 2024 compared to the year ended December 31, 2023.
Previous wording
On September 25, 2024, we entered into a new credit facility led by Citibank, N.A. (the “Credit Facility”). The Credit Facility has a total facility size of $1.5 billion, an initial borrowing base of $325.0 million and available capacity of $65.7 million as of December 31, 2024. The Credit Facility replaced our prior credit facility (as defined below), which was terminated in connection with entry into the Credit Facility. As of December 31, 2024, our reserves supported a $325.0 million facility of which $259.3 million was outstanding leaving $65.7 million of unused capacity.
Current wording
The Credit Facility replaced our prior credit facility (as defined below), which was terminated in connection with entry into the Credit Facility.
Previous wording
Our financial statements are prepared in accordance with U.S. GAAP. In connection with preparing of our financial statements, we are required to make assumptions and estimates about future events, and to apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with U.S. GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.
Current wording
Our financial statements are prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). In connection with preparing our financial statements, we are required to make assumptions and estimates about future events, and to apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with U.S. GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.
Previous wording
We account for oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs, includingnon-productive costs and certain general and administrative costs such as salaries, benefits and other internal costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Under the full cost method of accounting, capitalized costs are amortized based onunits-of-production and proved oil and natural gas reserves. If we maintain production levels year over year, our depreciation, depletion, and amortization expense may be significantly different if our estimates of remaining reserves or future development costs change significantly. On a quarterly basis, we review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC, which is referred to as a cost center ceiling test.
Current wording
We account for oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs, including non-productive costs and certain general and administrative costs such as salaries, benefits and other internal costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Under the full cost method of accounting, capitalized costs are amortized based on units-of-production and proved oil and natural gas reserves. If we maintain production levels year over year, our depreciation, depletion, and amortization expense may be significantly different if our estimates of remaining reserves or future development costs change significantly. On a quarterly basis, we review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC, which is referred to as a cost center ceiling test.
Previous wording
We estimate future net cash flows from natural gas, NGLs and oil reserves based on selling prices and costs using a 12-month average price, which is calculated as the unweighted arithmetic average of thefirst-day-of-the- month price for each month within the 12-month period and, as such, is subject to change in subsequent periods. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Income tax expense (which our predecessor, INR Holdings, has not been subject to historically for federal income tax purposes) is based on currently enacted statutory tax rates and tax deductions and credits available under current laws.
Current wording
We estimate future net cash flows from natural gas, NGLs and oil reserves based on selling prices and costs using a 12-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the- month price for each month within the 12-month period and, as such, is subject to change in subsequent periods. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Income tax expense (which our predecessor, INR Holdings, was not subject to historically for federal income tax purposes for periods prior to the Corporate Reorganization) is based on currently enacted statutory tax rates and tax deductions and credits available under current laws.
Previous wording
We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash andnon-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using various inputs and assumptions including established index prices and other sources which are based upon, among other things, futures prices, time to maturity, implied volatilities and counterparty credit risk.
Current wording
We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using various inputs and assumptions including established index prices and other sources which are based upon, among other things, futures prices, time to maturity, implied volatilities and counterparty credit risk.
Previous wording
As described in “Item 1. Business—Corporate Reorganization,” Infinity Natural Resources entered into a Tax Receivable Agreement in connection with the closing of the IPO under which it is contractually committed to pay the Legacy Owners 85% of the net cash savings, if any, in U.S. federal, state and local income tax that Infinity Natural Resources (a) actually realizes with respect to taxable periods ending after the IPO or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the INR board of directors) or the Tax Receivable Agreement 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 Existing Owners for a number of shares of Class A common stock on aone-for-one basis or, at our option, the receipt of an equivalent amount of cash pursuant to the INR Holdings LLC Agreement and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement.
Current wording
As described in “Item 1. Business—Corporate Reorganization,” Infinity Natural Resources entered into a Tax Receivable Agreement in connection with the closing of the IPO under which it is contractually committed to pay the Legacy Owners 85% of the net cash savings, if any, in U.S. federal, state and local income tax that Infinity Natural Resources (a) actually realizes with respect to taxable periods ending after the IPO or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the INR board of directors) or the Tax Receivable Agreement 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) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
For the year ended December 31, 2025, we generated $261.8 million of cash from operating activities, an increase of $84.1 million from the prior year. Cash provided by operating activities increased primarily due to higher production volumes and associated revenues as compared to the prior year. These factors were partially offset by higher severance and ad valorem taxes, GP&T, G&A, and lower realized prices for oil and natural gas liquids during the year ended December 31, 2025 as compared to the prior year. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods.
Current report — wording carried from elsewhere
•Leverage ratio – the ratio of total funded debt to consolidated EBITDAX of not greater than 3.0 to 1.0. We were in compliance with the covenants and applicable financial ratios described above as of December 31, 2023.