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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________________
FORM 10-Q
_________________________
(Mark One)

x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2025
OR

o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to
Commission file number 001-42499
_________________________
INFINITY NATURAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
_________________________

Delaware | 99-3407012
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.)
2605 Cranberry Square, Morgantown, West Virginia | 26508
(Address of Principal Executive Offices) | (Zip Code)

(304) 212-2350
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

Title of each class | Trading Symbol(s) | Name of each exchange on which registered
Class A common stock, par value $0.01 per share | INR | The New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No o

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Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | o |  | Accelerated filer | o
Non-accelerated filer | x |  | Smaller reporting company | o
|  |  | Emerging growth company | x

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes o No x
The number of shares of the Registrant’s Class A common stock and Class B common stock outstanding as of May 9, 2025 was 15,237,500 and 45,638,889, respectively.

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| Page
Cautionary Statement Regarding Forward-Looking Statements | ii
Glossary of Oil and Natural Gas Terms | iv
Part I - Financial Information | 1
Item 1. Financial Statements | 1
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations | 24
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 35
Item 4. Controls and Procedures | 36
Part II - Other Information | 37
Item 1. Legal Proceedings | 37
Item 1A. Risk Factors | 37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 37
Item 3. Defaults Upon Senior Securities | 37
Item 4. Mine Safety Disclosures | 37
Item 5. Other Information | 37
Item 6. Exhibits | 38
Signatures | 40

i

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Some of the information in this Quarterly Report on Form 10-Q (this “Quarterly Report”) may contain “forward-looking statements.” All statements, other than statements of historical fact included in this Quarterly Report regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events at the time such statement was made. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in our Annual Report on Form 10-K for the year ended December 31, 2024 (the “2024 Form 10-K”) and in this Quarterly Report. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
•oil, natural gas and NGL prices;
•our business strategy;
•the timing and amount of our future production of oil, natural gas and NGLs;
•our estimated proved reserves;
•our ability to achieve or maintain certain financial and operational metrics;
•our drilling prospects, inventories, projects and programs;
•actions taken by the OPEC and other allied countries (collectively known as “OPEC+”) as it pertains to the global supply and demand of, and prices for, oil, natural gas and NGLs;
•armed conflict, political instability or civil unrest in oil and gas producing regions, including instability in the Middle East and the conflict between Russia and Ukraine, and the related potential effects on laws and regulations, or the imposition of economic or trade sanctions;
•our ability to replace the reserves we produce through drilling and property acquisitions;
•the occurrence or threat of epidemic or pandemic diseases, or any government response to such occurrence or threat;
•our financial strategy, leverage, liquidity and capital required for our development program;
•our pending legal matters;
•our ability to comply with environmental, health and safety laws, regulations and obligations;
•our price differentials;
•our ability to reduce or offset our GHG emissions, including our ability to achieve carbon neutrality;
•our hedging strategy and results;
•our competition and government regulations;
•our ability to obtain permits and governmental approvals;
•our marketing of oil, natural gas and NGLs;
•our leasehold or business acquisitions;
ii

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•our costs of developing our properties;
•general global political and economic conditions;
•credit markets;
•uncertainty regarding our future operating results; and
•our plans, objectives, expectations and intentions contained in this Quarterly Report.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties incident to the development, production, gathering and sale of oil, natural gas and NGLs, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility; inflation; lack of availability and cost of drilling, completion and production equipment and services; supply chain disruption; project construction delays; environmental risks; drilling, completion and other operating risks; lack of availability or capacity of midstream gathering and transportation infrastructure; regulatory changes; the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital; the timing of development expenditures, impacts of geopolitical and world health events, including trade wars; cybersecurity risks; and the other risks described under “Item 1A. Risk Factors” in this Quarterly Report and in our 2024 Form 10-K.
Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimates depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any future production and development program. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described in this Quarterly Report or our 2024 Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.
iii

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GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:
•“basis” means when referring to commodity pricing, the difference between the NYMEX WTI, for oil prices, and NYMEX Henry Hub, for gas prices, and the corresponding sales price at various regional sales points. The differential commonly is related to factors such as product quality, location, transportation capacity availability and contract pricing;
•“Bbl” means one stock tank barrel or 42 U.S. gallons liquid volume;
•“Boe” means one barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil equivalent. This is an energy content correlation and does not reflect a value or price relationship between the commodities;
•“Boe/d” means one Boe per day;
•“British thermal unit” or “Btu” means a measure of the amount of energy required to raise the temperature of one pound of water by one-degree Fahrenheit;
•“collar” means a financial arrangement that effectively establishes a price range for the underlying commodity. The producer bears the risk and benefit of fluctuation between the minimum (floor) price and the maximum (ceiling) price;
•“drilled and uncompleted well” or “DUC” means a wellbore in which horizontal drilling has been completed but has yet to be stimulated through hydraulic fracturing;
•“drilling locations” means total gross locations that may be able to be drilled on our existing acreage. A portion of our drilling locations constitute estimated locations based on our acreage and spacing assumptions, as described in “Item 1. Business” of the 2024 Form 10-K;
•“gas” means natural gas;
•“hedging” means the use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility;
•“Henry Hub” means the distribution hub on the natural gas pipeline system in Erath, Louisiana, owned by Sabine Pipe Line LLC;
•“horizontal drilling” means drilling that ultimately is horizontal or near horizontal to increase the length of the wellbore penetrating the target formation;
•“horizontal wells” means wells that are drilled horizontal or near horizontal to increase the length of the wellbore penetrating the target formation;
•“LNG” means liquified natural gas;
•“MBoe” means one thousand barrels of oil equivalent;
•“MBoe/d” means one thousand barrels of oil equivalent per day;
•“Mcf” means one thousand standard cubic feet of natural gas;
•“MMBtu” means one million British thermal units;
•“MMBtu/d” means one MMBtu per day;
•“MMcf” means one million standard cubic feet of natural gas;
•“natural gas liquids” or “NGLs” means hydrocarbons, in the same family of molecules as natural gas and crude oil, composed exclusively of carbon and hydrogen. Ethane, propane, butane, isobutane, and pentane are all NGLs;
•“net acres” means the percentage of total acres an owner owns or has leased out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres;
•“NYMEX” means the New York Mercantile Exchange;
•“option” means a contract that gives the buyer the right, but not the obligation, to buy or sell a specified quantity of a commodity or other instrument at a specific price within a specified period of time;
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•“proved developed nonproducing reserves” or “PDNP” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods but are not yet producing;
•“proved developed producing reserves” or “PDP” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, according to the Securities and Exchange Commission or Society of Petroleum Engineers definitions of proved reserves;
•“proved reserves” means the summation of reserves within the PDP, PDNP and PUD reservoir categories;
•“proved undeveloped reserves” or “PUDs” means proved reserves that are expected to be recovered from undrilled well locations on existing acreage or from existing wells where a relatively major expenditure is required for recompletion within the five-year development window, according to the Securities and Exchange Commission or Society of Petroleum Engineers definition of PUD;
•“reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock and is separate from other reservoirs;
•“undeveloped acreage” means acreage under lease on which wells have not been drilled or completed;
•“well pad” or “pad” means an area of land that has been cleared and leveled to enable a drilling rig to operate in the exploration and development of a natural gas or oil well;
•“wellbore” or “well” means a drilled hole that is equipped for the production of hydrocarbons;
•“working interest” means the right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis; and
•“WTI” means West Texas Intermediate.
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Part I - Financial Information
Item 1. Financial Statements
INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets (Unaudited)
(amounts in thousands, except share and per share amounts)

| March 31, 2025 |  | December 31, 2024
Assets |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 4,859 |  | $ | 2,203
Accounts receivable: |  |  |
Oil and natural gas sales, net | 34,044 |  | 39,314
Joint interest and other, net | 15,486 |  | 32,229
Prepaid expenses and other current assets | 3,362 |  | 11,822
Commodity derivative assets, short term | 763 |  | —
Total current assets | $ | 58,514 |  | $ | 85,568
Oil and natural gas properties, full cost method (including $86.8 million and $86.5 million as of March 31, 2025 and December 31, 2024, respectively excluded from amortization) | 1,017,189 |  | 933,228
Midstream and other property and equipment | 43,589 |  | 40,053
Less: Accumulated depreciation, depletion, and amortization | (174,429) |  | (153,233)
Property and equipment, net | $ | 886,349 |  | $ | 820,048
Operating lease right-of-use assets, net | 1,309 |  | 1,389
Other assets | 7,745 |  | 8,461
Total assets | $ | 953,917 |  | $ | 915,466
Liabilities, Redeemable Interest and Stockholders’ Deficit / Members’ Equity |  |  |
Current liabilities: |  |  |
Accounts payable | $ | 46,583 |  | $ | 51,370
Royalties payable | 26,448 |  | 23,129
Accrued liabilities | 25,567 |  | 45,903
Current portion of long-term debt | 80 |  | 101
Operating lease liabilities | 209 |  | 247
Commodity derivative liabilities, short-term | 38,664 |  | 12,596
Total current liabilities | $ | 137,551 |  | $ | 133,346
Long-term debt | 11,391 |  | 259,406
Operating lease liabilities, net of current portion | 1,098 |  | 1,142
Asset retirement obligations | 3,130 |  | 2,988
Commodity derivative liabilities, long-term | 18,670 |  | 10,342
Deferred tax liability, net | 35 |  | —
Total liabilities | $ | 171,875 |  | $ | 407,224
Commitments and contingencies (Note 14) |  |  |
Redeemable non-controlling interest | 834,279 |  | —
Stockholders’ deficit / members’ equity |  |  |
Members’ equity | — |  | 508,242
Class A common stock—$0.01 par value; 400,000,000 shares authorized, 15,237,500 and 0 shares issued and outstanding as of March 31, 2025 and December 31, 2024, respectively | 152 |  | —
Class B common stock—$0.01 par value; 150,000,000 shares authorized, 45,638,889 and 0 shares issued and outstanding as of March 31, 2025 and December 31, 2024, respectively | 456 |  | —
Additional paid-in capital | — |  | —
Accumulated deficit | (52,845) |  | —
Total stockholders’ deficit/ members’ equity | (52,237) |  | 508,242
Total liabilities, redeemable interest and stockholders’ deficit / members’ equity | $ | 953,917 |  | $ | 915,466

The accompanying notes are an integral part of these condensed consolidated financial statements.
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Operations (Unaudited)
(amounts in thousands, except share and per share amounts)

| Three Months Ended March 31,
| 2025 |  | 2024
Revenues: |  |  |
Oil, natural gas, and natural gas liquids sales | $ | 84,184 |  | $ | 49,839
Midstream activities | 981 |  | 386
Total revenues | 85,165 |  | 50,225
Operating expenses: |  |  |
Gathering, processing, and transportation | 12,070 |  | 10,456
Lease operating | 7,434 |  | 7,288
Production and ad valorem taxes | 632 |  | 359
Depreciation, depletion and amortization | 21,258 |  | 15,555
General and administrative (including share-based compensation of $126.9 million and $0.0 for the three months ended March 31, 2025 and 2024, respectively) | 131,750 |  | 2,128
Total operating expenses | $ | 173,144 |  | $ | 35,786
Operating income | (87,979) |  | 14,439
Other income (expense): |  |  |
Interest, net | (3,067) |  | (4,573)
Loss on derivative instruments | (37,218) |  | (23,455)
Other (expense) income | (63) |  | (467)
Net loss before income tax expense (benefit) | (128,327) |  | (14,056)
Income tax expense | 35 |  | —
Net loss | $ | (128,362) |  | $ | (14,056)
Net income attributable to Infinity Natural Resources, LLC prior to the reorganization | 9,914 |  |
Net loss attributable to redeemable non-controlling interests | (103,707) |  |
Net loss attributable to Infinity Natural Resources, Inc. | $ | (34,569) |  |
Net loss attributable to Infinity Natural Resources, Inc. per share of Class A common stock—basic and diluted | $ | (2.27) |  |
Weighted-average shares of Class A common stock outstanding—basic and diluted | 15,237,500 |  |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Redeemable Non-controlling Interest and Stockholders’ Deficit / Members’ Equity (Unaudited)
(amounts in thousands, except share amounts)

| INR Holdings Members' Equity | Class A | Class B | Additional Paid in Capital | Accumulated Deficit | Total | Redeemable Non-controlling Interest
Three Months Ended March 31, 2025 | Shares | Amount | Shares | Amount
Balance as of December 31, 2024 | $ | 508,242 | — | $ | — | — | $ | — | $ | — | $ | — | $ | — | $ | —
Net income prior to reorganization transactions | 9,914 | — | — | — | — | — | — | — |
Effect of the reorganization transactions | (518,156) | — | — | 45,638,889 | 456 |  | — | 456 | 517,700
Issuance of common stock in connection with initial public offering, net of underwriting discounts, commissions and other offering costs | — | 15,237,500 | 152 | — | — | 198,204 | — | 198,356 | 76,911
Share-based compensation expense subsequent to reorganization transactions | — | — | — | — | — | 126,895 | — | 126,895 |
Net loss subsequent to reorganization transactions | — | — | — | — | — | — | (34,569) | (34,569) | (103,707)
Adjustment of redeemable non-controlling interest to redemption value | — | — | — | — | — | (325,099) | (18,276) | (343,375) | 343,375
Balance as of March 31, 2025 | $ | — | 15,237,500 | $ | 152 | 45,638,889 | $ | 456 | $ | — | $ | (52,845) | $ | (52,237) | $ | 834,279

| INR Holdings Members' Equity | Class A | Class B | Additional Paid in Capital | Accumulated Deficit | Total | Redeemable Non-controlling Interest
Three Months Ended March 31, 2024 | Shares | Amount | Shares | Amount
Balance as of December 31, 2023 | $ | 458,456 | — | $ | — | — | $ | — | $ | — | $ | — | $ | 458,456 | $ | —
Contribution | 500 | — | — | — | — | — | — | 500 | —
Net loss | (14,056) | — | — | — | — | — | — | (14,056) | —
Balance as of March 31, 2024 | $ | 444,900 | — | $ | — | — | $ | — | $ | — | $ | — | $ | 444,900 | $ | —

The accompanying notes are an integral part of these condensed consolidated financial statements.
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows (Unaudited)
(amounts in thousands)

| Three Months Ended March 31,
| 2025 |  | 2024
Cash flows from operating activities: |  |  |
Net loss | $ | (128,362) |  |  | $ | (14,056)
Adjustments to reconcile net loss to net cash provided by operating activities: |  |  |
Depreciation, depletion, and amortization | 21,258 |  | 15,555
Amortization of debt issuance costs | 527 |  | 477
Share-based compensation expense | 126,895 |  | — |
Loss on derivative instruments | 37,218 |  | 23,455
Cash received (paid) on settlement of derivative instruments | (3,585) |  | 13,263
Non-cash lease expense | 80 |  | (5)
Deferred income tax | 35 |  | — |
Changes in operating assets and liabilities: |  |  |
Accounts receivable | 22,013 |  | 15,240
Prepaid expenses and other assets | (1,151) |  | 33
Accounts payable | (978) |  | (21,598)
Royalties payable | 3,319 |  | (3,382)
Accrued and other expenses | (4,707) |  | 1,046
Other assets and liabilities | 1,667 |  | 127
Net cash provided by operating activities | $ | 74,229 |  | $ | 30,155
Cash flows from investing activities: |  |  |
Additions to oil and gas properties | (105,665) |  | (36,327)
Additions to midstream and other property and equipment | (2,766) |  | (1,856)
Net cash used in investing activities | $ | (108,431) |  | $ | (38,183)
Cash flows from financing activities: |  |  |
Proceeds from capital contributions | — |  |  | 500
Borrowings under revolving credit facility | 56,000 |  | 43,500
Payments on revolving credit facility | (304,000) |  | (34,000)
Proceeds issuance of Class A common stock in initial public offering, net of underwriting discounts and commissions | 286,465 |  | — |
Payments of debt issuance costs | (645) |  | — |
Payments of initial public offering costs | (925) |  | — |
Payments on notes payable | (37) |  | (33)
Net cash provided by financing activities | $ | 36,858 |  | $ | 9,967
Net increase in cash and cash equivalents | 2,656 |  | 1,939
Cash and cash equivalents at beginning of period | 2,203 |  | 1,504
Cash and cash equivalents at end of period | $ | 4,859 |  | $ | 3,443

The accompanying notes are an integral part of these condensed consolidated financial statements
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
Note 1 – Description of the Business and Basis of Presentation
Description of Business. Infinity Natural Resources, Inc., together with its subsidiaries (collectively referred to as “INR”, 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 oil and natural gas exploration and production company engaged in the acquisition, exploration, and development of properties for the production of oil, natural gas, and natural gas liquids (“NGLs”) from underground reservoirs. 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”). 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. Pursuant to the Second Amended and Restated Limited Liability Company Agreement of INR Holdings (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.
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 and is responsible for all operational, management and administrative decisions relating to INR Holdings’ business and consolidates the financial results of INR Holdings and reports redeemable non-controlling interests in its consolidated financial statements related to the INR Units that the Legacy Owners own in INR Holdings.
The historical consolidated financial statements included in this Quarterly Report for periods prior to the Corporate Reorganization and IPO are based on the financial statements of our predecessor, INR Holdings. The historical financial data of our predecessor may not yield an accurate indication of what our actual results would have been if the Corporate Reorganization and IPO had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.
Basis of Accounting and Presentation. The accompanying unaudited condensed consolidated financial statements present the financial position, results of operations, and cash flows of the Company in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) and regulations of the SEC for interim financial information. Certain information and disclosures normally included in consolidated financial statements prepared in accordance with U.S. GAAP have been condensed or omitted. Accordingly, these unaudited condensed consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements for the year ended December 31, 2024 and the related notes included in the Company’s 2024 Form 10-K. The December 31, 2024, condensed consolidated balance sheet was derived from the Company’s audited consolidated financial statements as of that date. In the opinion of management, all adjustments, consisting of normal recurring adjustments considered necessary for a fair presentation of interim financial information, have been included. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year.
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
The Company had no material other comprehensive income or loss items. Accordingly, a separate statement of comprehensive loss has not been presented in these unaudited condensed consolidated financial statements. All intercompany balances and transactions are eliminated upon consolidation.
Note 2 – Summary of Significant Accounting Policies
The selected significant accounting policies included below are policies that were adopted or modified during the three months ended March 31, 2025, as a result of the IPO or the adoption of new accounting policies. Refer to Note 2 – Summary of Significant Accounting Policies of our 2024 Form 10-K for the full list of our 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. The Company 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;
•asset retirement obligations;
•the fair value of share-based compensation awards; and
•estimates related to the tax receivable agreement.
Redeemable Non-controlling Interest. Redeemable non-controlling interests are presented within our unaudited condensed consolidated balance sheet as of March 31, 2025 as mezzanine equity as they are redeemable upon the occurrence of an event that is not solely within our control. The carrying amount of the redeemable non-controlling interest is equal to the greater of (1) the carrying value of the non-controlling interest adjusted each reporting period for income or loss attributable to the non-controlling interest or (2) the redemption value. Remeasurements to the redemption value of the redeemable non-controlling interest are recognized in additional paid-in capital within the unaudited condensed consolidated balance sheet as of March 31, 2025. The redemption amount is calculated based on the 5-day volume-weighted average closing price (“VWAP”) of Class A common stock at the end of each reporting period. The portion of the net income or loss attributable to redeemable non-controlling interest is reported as net income or loss attributable to redeemable non-controlling interests on our unaudited condensed consolidated statement of operations for the three months ended March 31, 2025.
Income Taxes. Following the completion of the IPO, the Company became subject to U.S. federal, state, and local income taxes on its share of taxable income earned through its interest in INR Holdings, which is treated as a pass-through entity for income tax purposes. INR Holdings itself is generally not subject to federal income tax, and instead, its income or loss is allocated to its members. INR Holdings may be subject to certain entity-level taxes imposed by specific states or jurisdictions. The Company uses the liability method to account for income taxes in accordance with ASC 740. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences of differences between the financial reporting and tax bases of assets and liabilities. Deferred tax amounts are calculated using the enacted tax rates expected to be in effect when the temporary differences reverse. Deferred tax assets are recorded when it is considered more likely than not that they will be realized. The Company evaluates the need for a valuation allowance by considering all available evidence, including projections of future taxable income, the timing of temporary difference reversals, the existence of tax planning strategies and historical operating results. The Company evaluates uncertain tax positions using a recognition and measurement approach. A tax position is recognized in the financial statements only if it is more likely than not that the position would be sustained upon examination by the relevant taxing authority. The amount recognized is based on the largest amount of tax benefit that has a greater than 50% likelihood of being realized. Changes in recognition
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
or measurement are reflected in the period in which the change in judgment occurs. Interest and penalties, if incurred, are recorded in income tax expense.
Tax Receivable Agreement. In connection with the IPO and related transactions, the Company entered into a Tax Receivable Agreement (“TRA”) with the Legacy Owners, which 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. 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 liability is measured using a “with and without” approach and is reassessed at each reporting period, with changes in estimates recognized in income tax expense. See Note 9 – Income Taxes and Tax Receivable Agreement for further details.
(Loss) Earnings per Share. Basic (loss) earnings 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 restricted stock units and performance stock units granted under the Plan (as defined in Note 11 – Share-based Compensation) and the exchange of 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 Company uses the “if-converted” method to determine the potential dilutive effect of exchanges of INR Units (and the cancellation of an equal number of shares of Class B common stock), and the treasury stock method to determine the potential dilutive effect of vesting of outstanding equity awards.
Share-based Compensation. The Company accounts for share-based compensation in accordance with ASC 718, Compensation — Stock Compensation (“ASC 718”). Share-based awards, including restricted stock units and performance stock units, are measured at their grant-date fair value and recognized as compensation expense on a straight-line basis over the requisite service period, which generally corresponds to the vesting period of the award.
For restricted stock units, fair value is determined based on the closing stock price of the Company’s Class A common stock on the grant date. For performance stock units with market-based vesting conditions, fair value is estimated using a Monte Carlo simulation model and is not subsequently remeasured. Compensation expense for market-based awards is recognized regardless of whether the market condition is ultimately satisfied, provided the requisite service condition is met. The Company accounts for forfeitures as they occur.
Adoption of New Accounting Standards. 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 arrangement 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 March 31, 2025, we adopted the provisions of this amendment in our condensed consolidated financial statements. See Note 11 – Share-based Compensation for further details.
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. While the adoption of this ASU will modify the Company’s disclosures, it will not have an impact on the Company’s condensed consolidated balance sheets or statements of income or cash flows in its condensed consolidated financial statements. Please see Note 9 – Income Taxes and Tax Receivable Agreement for further details.
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
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.
Note 3 – Revenues
Crude oil, natural gas, and NGL sales are recognized at the point that control of the product is transferred to the customer. Virtually all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials.
Commodity sales revenues presented within the consolidated statements of operations relate to the sale of oil, natural gas, and NGLs as shown below:

| For the Three Months Ended March 31,
| 2025 |  | 2024
(in thousands) |  |  |
Oil revenues | $ | 47,046 |  | $ | 27,141
Natural gas revenues | 22,849 |  | 13,317
NGL revenues | 14,289 |  | 9,381
Oil, natural gas, and NGL sales | $ | 84,184 |  | $ | 49,839

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 or at the inlet of a transportation pipeline. 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 the Company’s 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 the Company. For these contracts, the Company evaluates 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 the Company elects 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 the Company does not take its 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.
Performance Obligations
The Company’s commodity sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of its commodity sales contracts. Under our revenue agreements, each delivery generally represents a separate performance
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
obligation; therefore, future volumes delivered are wholly unsatisfied and 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 condensed consolidated balance sheets. As of March 31, 2025 and December 31, 2024, such receivable balances were $34.0 million and $39.3 million, respectively.
The Company has certain gathering service agreements that are structured with minimum volume commitments (“MVCs”), which specify minimum quantities that the customer will be charged regardless of whether such quantities are gathered. Revenue is recognized for MVCs when the performance obligation has been met, which is the earlier of when the gas is gathered or when the likelihood that the customer will be able to meet its MVC is remote. If a customer fails to meet its MVC for a specified period, the customer is obligated to pay a contractually-determined fee based on the shortfall between actual volume gathered and the MVC.
Note 4 – 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 March 31, 2025 and December 31, 2024 are as follows:

| March 31, 2025 |  | December 31, 2024
(in thousands) |  |
Oil and natural gas properties: |  |  |
Proved properties | $ | 930,402 |  | $ | 846,738
Unproved properties | 86,787 |  | 86,490
Gross oil and natural gas properties | 1,017,189 |  | 933,228
Less: accumulated depreciation, depletion, and amortization | (169,215) |  | (148,638)
Oil and natural gas properties, net | $ | 847,974 |  | $ | 784,590

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter which determines a limit, or ceiling, on the book value of proved oil and natural gas properties. No impairment expense was recorded for the three months ended March 31, 2025 based on the results of the respective quarterly ceiling tests.
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 average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of reserves. Historically, we have not designated any of our derivative contracts as cash flow hedges.
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 depletion expense for the three months ended March 31, 2025 and 2024 related to oil and gas properties and average depletion rate per Boe:
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Notes to Condensed Consolidated Financial Statements

| For the Three Months Ended March 31,
(in thousands, except per Boe amounts) | 2025 |  | 2024
Depletion of Proved Oil and Natural Gas Properties | $ | 20,577 |  | $ | 15,049
Average Depletion Rate per Boe | $ | 8.68 |  | $ | 7.83

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.

| March 31, 2025 |  | December 31, 2024
(in thousands) |  |
Midstream assets | $ | 40,334 |  | $ | 36,880
Vehicles | 1,878 |  | 1,815
Furniture, fixtures, and office equipment | 770 |  | 751
Leasehold improvements | 607 |  | 607
Gross midstream and other property and equipment | 43,589 |  | 40,053
Less: Accumulated depreciation | (5,214) |  | (4,595)
Total midstream and other property and equipment, net | $ | 38,375 |  | $ | 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 the Company’s 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 three months ended March 31, 2025 and 2024. Total depreciation expense for the three months ended March 31, 2025 and 2024 totaled approximately $0.6 million and $0.5 million, respectively.
Note 5 – Accrued Liabilities
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Notes to Condensed Consolidated Financial Statements
The Company’s accrued liabilities as of March 31, 2025 and December 31, 2024 consisted of the following amounts:

| March 31, 2025 |  | December 31, 2024
(in thousands) |  |  |
Accrued interest expense | $ | 88 |  | $ | 261
Accrued capital expenditures | 10,832 |  | 27,234
Accrued lease operating expenses | 976 |  | 1,898
Accrued offering costs | 5,284 |  | 4,849
Accrued general and administrative expenses | 1,835 |  | 3,293
Accrued severance and ad valorem taxes | 318 |  | 1,263
JIB advance deposits | 5,457 |  | 6,188
Other accrued liabilities | 777 |  | 917
Total accrued liabilities | $ | 25,567 |  | $ | 45,903

Note 6 – 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, the “Credit Agreement”) with a syndicate of financial institutions with an initial aggregate elected commitment amount and initial borrowing base of $325,000,000. 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 $325,000,000 to $350,000,000. 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 March 31, 2025, the Company’s reserves supported a $350.0 million borrowing base of which $11.3 million was outstanding, leaving $338.7 million of unused capacity.
For the three months ended March 31, 2025 and 2024, total interest expense on the Credit Facility was $2.6 million and $4.1 million, respectively. We did not capitalize any interest expense for the three months ended March 31, 2025 and 2024. For the three months ended March 31, 2025 and 2024, the Company’s weighted-average interest rate was 5.2% and 8.9%, respectively.
Debt issuance costs associated with the Credit Facility are capitalized and presented as other assets within the unaudited condensed consolidated balance sheets. Because debt issuance costs are related to a line of credit, they are presented as an asset, rather than an offset to the corresponding liability. Debt issuance costs are amortized using the straight-line method over the term of the related agreement. We did not capitalize additional debt issuance costs related to the Credit Facility for the three months ended March 31, 2025. As of March 31, 2025 and December 31, 2024, capitalized debt issuance costs were approximately $7.7 million and $7.9 million, respectively. Amortization of debt issuance costs, which is included within interest expense in the condensed consolidated statements of operations, was approximately $0.5 million and $0.6 million for the three months ended March 31, 2025 and 2024, respectively.
The Credit Facility also requires us to maintain compliance as of the end of each fiscal quarter with financial covenants consisting of 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 Facility. We were in compliance with the covenants and financial ratios under the
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Notes to Condensed Consolidated Financial Statements
Credit Facility described above through the date these unaudited condensed consolidated financial statements were available to be issued.
Other Long-Term Debt
Other long-term debt principally relates to car loans associated with the Company’s car fleet to support service and maintenance of our operated wells.
Payments due by fiscal year related to other long-term debt as of March 31, 2025 are as follows:

| Notes Payable
(in thousands) |
Remainder of 2025 | $ | 64
2026 | 45
2027 | 14
2028 | —
2029 | —
Total payments | $ | 123

Note 7 – Derivatives and Risk Management
The Company is 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 the Company’s 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 revolving credit facility. As of March 31, 2025 and December 31, 2024, we did not have any cash or letters of credit posted as collateral for our derivative financial instruments.
The Company does 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 netting arrangements with our counterparties that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities.
Contracts that result in physical delivery of a commodity expected to be sold by the Company 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 the Company’s derivative financial instruments. The tables present the notional amount, the weighted average contract prices and the fair values by expected maturity dates as of March 31, 2025.
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Notes to Condensed Consolidated Financial Statements

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2025
Oil | (in MBbls) |  | ($ per Bbl) |  | (in thousands)
Fixed price swaps |  |  |  |  |
2025 | 1,425 |  | $ | 71.25 |  | $ | 2,721
2026 | 571 |  | $ | 69.57 |  | 2,079
2027 | 35 |  | $ | 68.04 |  | 116
2028 | — |  | $ | — |  | —
Total | 2,031 |  |  |  | $ | 4,916

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2025
Natural gas | (in MMBtu) |  | ($ per MMBtu) |  | (in thousands)
Fixed price swaps |  |  |  |  |
2025 | 25,262,000 |  | $ | 3.46 |  | $ | (25,434)
2026 | 36,566,500 |  | $ | 3.81 |  | (25,638)
2027 | 14,176,000 |  | $ | 3.79 |  | (2,880)
2028 | 1,070,000 |  | $ | 4.25 |  | 1
Total | 77,074,500 |  |  |  | $ | (53,951)

| Volume |  | Basis Differential |  | Fair Value as of March 31, 2025
Natural gas | (in MMBtu) |  | ($ per MMBtu) |  | (in thousands)
Basis swaps |  |  |  |  |
2025 | 34,535,500 |  | $ | (1.10) |  | $ | (2,347)
2026 | 37,345,000 |  | $ | (1.00) |  | (823)
2027 | 14,005,000 |  | $ | (0.92) |  | 538
2028 | 1,070,000 |  | $ | (0.83) |  | 72
Total | 86,955,500 |  |  |  | $ | (2,560)

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2025
Ethane | (in gallons) |  | ($ per gallon) |  | (in thousands)
Fixed price swaps |  |  |  |  |
2025 | 7,622,000 |  | $ | 0.25 |  | $ | (390)
2026 | 8,290,500 |  | $ | 0.28 |  | (159)
2027 | 573,000 |  | $ | 0.30 |  | (4)
2028 | — |  | $ | — |  | —
Total | 16,485,500 |  |  |  | $ | (553)

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Notes to Condensed Consolidated Financial Statements

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2025
Propane | (in gallons) |  | ($ per gallon) |  | (in thousands)
Fixed price swaps |  |  |  |  |
2025 | 11,014,000 |  | $ | 0.70 |  | $ | (1,718)
2026 | 12,032,500 |  | $ | 0.71 |  | (922)
2027 | 813,000 |  | $ | 0.71 |  | (37)
2028 | — |  | $ | — |  | —
Total | 23,859,500 |  |  |  | $ | (2,677)

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2025
Isobutane | (in gallons) |  | ($ per gallon) |  | (in thousands)
Fixed price swaps |  |  |  |  |
2025 | 2,658,500 |  | $ | 0.87 |  | $ | (369)
2026 | 2,523,500 |  | $ | 0.85 |  | (242)
2027 | 166,000 |  | $ | 0.83 |  | (13)
2028 | — |  | $ | — |  | —
Total | 5,348,000 |  |  |  | $ | (624)

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2025
Normal butane | (in gallons) |  | ($ per gallon) |  | (in thousands)
Fixed price swaps |  |  |  |  |
2025 | 4,455,000 |  | $ | 0.83 |  | $ | (608)
2026 | 4,245,000 |  | $ | 0.82 |  | (317)
2027 | 280,000 |  | $ | 0.82 |  | (15)
2028 | — |  | $ | — |  | —
Total | 8,980,000 |  |  |  | $ | (940)

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2025
Pentane | (in gallons) |  | ($ per gallon) |  | (in thousands)
Fixed price swaps |  |  |  |  |
2025 | 2,955,500 |  | $ | 1.40 |  | $ | (200)
2026 | 2,790,500 |  | $ | 1.38 |  | 15
2027 | 190,000 |  | $ | 1.34 |  | 3
2028 | — |  | $ | — |  | —
Total | 5,936,000 |  |  |  | $ | (182)

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 March 31, 2025 and December 31, 2024:
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| March 31, 2025 |
Balance Sheet Classification |  | Gross Amounts |  | Netting Adjustment |  | Net Amounts Presented on Balance Sheet |
(in thousands) |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |
Commodity derivative assets, short-term |  | $ | 5,828 |  | $ | (5,065) |  | $ | 763 |
Commodity derivative assets, long-term |  | 3,044 |  | (3,044) |  | — |
Total assets |  | $ | 8,872 |  | $ | (8,109) |  | $ | 763 |
Liabilities |  |  |  |  |  |  |
Commodity derivative liabilities, short-term |  | $ | (43,730) |  | $ | 5,066 |  | $ | (38,664) |
Commodity derivative liabilities, long-term |  | (21,713) |  | 3,043 |  | (18,670) |
Total liabilities |  | $ | (65,443) |  | $ | 8,109 |  | $ | (57,334) |

| December 31, 2024
Balance Sheet Classification |  | Gross 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-term |  | 2,647 |  | (2,647) |  | —
Total assets |  | $ | 8,736 |  | $ | (8,736) |  | $ | —
Liabilities |  |  |  |  |  |
Commodity derivative liabilities, short-term |  | $ | 18,685 |  | $ | (6,089) |  |  | $ | 12,596 |
Commodity derivative liabilities, long-term |  | 12,989 |  |  | (2,647) |  |  | 10,342 |
Total liabilities |  | $ | 31,674 |  |  | $ | (8,736) |  |  | $ | 22,938 |

Our total derivative gains and losses for the three months ended March 31, 2025 and 2024 were as follows:

| For the Three Months Ended March 31,
(in thousands) | 2025 | 2024
Realized gain (loss) on derivative instruments | $ | (3,585) |  | $ | 13,263
Unrealized gain (loss) on derivative instruments | (33,633) |  | (36,718)
Total gain (loss) on derivative instruments | $ | (37,218) |  | $ | (23,455)

Note 8 – Fair Value Measurements
Certain of the Company’s assets and liabilities are measured at fair value. Fair value is 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. 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. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.
The carrying values of cash and cash equivalents, including accounts receivable, other current assets, accounts payable and other current liabilities on the consolidated balance sheets approximate fair value because of their short-term nature. Additionally, the carrying value of outstanding borrowings under our revolving credit facility approximates fair value because the interest rates are variable and reflective of market rates. We consider the fair value of our revolving credit
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Notes to Condensed Consolidated Financial Statements
facility to be a Level 2 measurement on the fair value hierarchy, as discussed further below. The carrying value of borrowings under our revolving credit facility approximate fair value as interest rates applicable to our borrowings outstanding are based on prevailing market rates.
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, the Company’s net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis.

| March 31, 2025
| Level 1 |  | Level 2 |  | Level 3 |  | Fair Value
(in thousands) |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |
Fixed price swaps | $ | — |  | $ | 4,916 |  | $ | — |  | $ | 4,916
Basis swaps | — |  | — |  | — |  | —
Liabilities |  |  |  |  |  |  |
Fixed price swaps | — |  | (58,927) |  | — |  | (58,927)
Basis swaps | — |  | (2,560) |  | — |  | (2,560)
Total | $ | — |  | $ | (56,571) |  | $ | — |  | $ | (56,571)

| December 31, 2024
| Level 1 |  | Level 2 |  | Level 3 |  | Fair 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
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Notes to Condensed Consolidated Financial Statements
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, we use Level 2 inputs to measure the fair value of commodity derivative contracts.
Note 9 – Income Taxes and Tax Receivable Agreement
The Company recorded income tax expense of $0.0 million for each of the three months ended March 31, 2025 and 2024, respectively.
In calculating the provision for income taxes on an interim basis, the Company uses an estimate of the annual effective tax rate based upon currently known facts and circumstances and applies that rate to its year-to-date earnings or losses. The Company’s effective tax rate is based on expected income and statutory tax rates and takes into consideration permanent differences between financial statement and tax return income applicable to the Company in the various jurisdictions in which the Company operates. The effect of discrete items, such as changes in estimates, changes in enacted tax laws or rates or tax status, and unusual or infrequently occurring events, is recognized in the interim period in which the discrete item occurs. The accounting estimates used to compute the provision for income taxes may change as new events occur, additional information is obtained or as the result of new judicial interpretations or regulatory or tax law changes. The Company’s interim effective tax rate, inclusive of any discrete items, was (0.03)% for the three months ended March 31, 2025. The Company’s effective income tax rate differs from the U.S. statutory rate primarily because the income attributable to the redeemable non-controlling interest is pass-through income not subject to U.S. federal income tax within the entities included in the Company’s condensed consolidated financial statements.
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. INR Holdings continues to be treated as a partnership for U.S. federal income tax purposes and, as such, is not subject to U.S. federal income tax. Instead, taxable income is allocated to members, including the Company, and any taxable income of INR Holdings is reported in the respective tax returns of its members. The Company had no activity or holdings prior to the IPO.
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 as discussed Note 1 – Description of the Business and Basis of Presentation. 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. The Company recognizes deferred tax assets to the extent it believes these assets are more likely than not to be realized. In making such a determination, the Company considers all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax planning strategies and recent results of operations. Based on these factors, we determined that the deferred tax assets are not more likely than not to be recognized 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 stockholders’ deficit and members’ equity. As the deferred tax asset net of valuation allowance amounted to zero, there were no significant impacts to additional paid-in capital on account of establishing deferred tax accounts at the Company in connection with the IPO.
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
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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.
Note 10 – Stockholders’ Deficit/ Members’ Equity
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’ Deficit
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 25.0% interest in INR Holdings and the Legacy Owners own an approximate 75.0% interest in INR Holdings.
As of March 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 March 31, 2025, the Company consolidates the financial results of INR Holdings in its unaudited condensed 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 unaudited condensed consolidated financial statements.
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
Note 11 – 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 three months ended March 31, 2025 and is recorded within the condensed consolidated statement of operations as a component of General and administrative.
Omnibus Incentive Plan
In connection with the IPO, Infinity Natural Resources, Inc. 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 2025, the Company granted an additional 311,991 RSUs to certain employees and non-employee directors 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.
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 three months ended March 31, 2025:

| RSUs |  | Weighted-average grant date fair value
Unvested as of beginning of period | — |  |
Granted | 474,491 |  | $ | 18.19
Vested | — |  |
Canceled/Forfeited | — |  |
Unvested as of end of period | 474,491 |  | $ | 18.19

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 $0.6 million for the three months ended March 31, 2025.
As of March 31, 2025, unrecognized compensation expense related to unvested RSU awards was $8.0 million, which is expected to be recognized over a weighted-average remaining service period of 2.3 years.
Performance Stock Units
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
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 volatility | 40.00%
Risk-free rate | 4.04%
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 three months ended March 31, 2025:

| PSUs |  | Weighted-average grant date fair value
Unvested as of beginning of period | — |  |
Granted | 455,601 |  | $ | 22.20
Vested | — |  |
Canceled/Forfeited | — |  |
Unvested as of end of period | 455,601 |  | $ | 22.20

The Company recognized compensation expense for PSUs of $0.1 million for the three months ended March 31, 2025.
As of March 31, 2025, unrecognized compensation expense related to unvested PSU awards was $9.9 million, which is expected to be recognized over a weighted-average remaining service period of 2.9 years.
Note 12 – Earnings Per Share
Basic (loss) earnings 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:
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements

| For the Three Months Ended March 31, 2025
(in thousands, except per share amounts) |
Net loss attributable to Infinity Natural Resources, Inc. | $ | (34,569)
Weighted average number of Class A common stock outstanding: |
Basic | 15,237,500
Effect of dilutive securities: |
INR Units | —
RSUs | —
PSUs | —
Diluted | 15,237,500
Net loss attributable to Infinity Natural Resources, Inc. per share of Class A common stock |
Basic | $ | (2.27)
Diluted | $ | (2.27)

The calculation of diluted net loss per share for the three months ended March 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) 474,491 and 455,601 unvested RSUs and PSUs, respectively, because their inclusion in the calculation would be anti-dilutive.
Note 13 – 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 three months ended March 31, 2025 and 2024:

| For the Three Months Ended March 31,
| 2025 |  | 2024
(in thousands) |  |  |
Supplemental disclosure of non-cash transactions: |  |  |
Right-of-use assets and lease liabilities | — |  | 27
Additions of asset retirement obligations | 80 |  | 26
Revisions of asset retirement obligations | — |  | 47
Deferred offering costs included in accounts payable and accrued liabilities | (5,856) |  | —
Additions to oil and natural gas properties included in accounts payable and accrued liabilities | 34,753 |  | 48,699
Additions to other property and equipment included in accounts payable | 1,145 |  | 375
Supplemental disclosure of cash flow information |  |  |
Interest paid | $ | 2,800 |  | $ | 4,109

Note 14 – Commitments and Contingencies
South Bend Utica Farmout Agreement. On March 2, 2018, the Company 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.
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
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 March 31, 2025, the Company had yet to satisfy that obligation and has approximately 9 years remaining to meet its obligation.
Firm Transportation. The Company has entered into long-term physical gas sales with BP to move volumes at South Bend. The terms of the agreement supported 25,000 decatherm per day through March 2029.
Maximum Daily Quantity. The Company has commitments from an existing contract with Eureka Midstream for guaranteed pipeline capacity up to a maximum daily quantity (MDQ) of 15,000 decatherm per day expiring October 2025. In connection with this contract we have a minimum reservation fee and gathering fee based on the MDQ of 15,000 decatherm per day.
Minimum Volume Commitment. The Company has minimum volume commitments under an existing contract with Ohio Gathering Company. The terms of the agreement supported an average of 10,600 decatherm per day through 2030.
The following table summarizes our future commitments related to these oil and natural gas transportation and gathering agreements as of March 31, 2025:

| As of March 31, 2025
| Remainder 2025 |  | 2026 |  | 2027 |  | 2028 |  | 2029 and thereafter |  | Total
(in thousands) |  |  |  |  |  |  |  |  |  |  |
Firm Transportation | $ | 671 |  | 894 |  | 894 |  | 894 |  | 225 |  | $ | 3,577
Maximum Daily Quantity | 511 |  | — |  | — |  | — |  | — |  | 511
Minimum Volume Commitment | 4,453 |  | 8,964 |  | 8,964 |  | 8,988 |  | 15,743 |  | 47,112
Total minimum future commitments | $ | 5,635 |  | 9,858 |  | 9,858 |  | 9,882 |  | 15,968 |  | $ | 51,200

Drilling Rig Service Commitments. We entered into a third amendment to our September 2023 drilling contract with Patterson-UTI Energy, Inc. (“Patterson”) in January 2025 to drill eight (8) horizontal lateral wells. The Company has drilled one (1) well as of March 31, 2025 associated with this contract. In the event that we elected to not drill the remaining seven (7) wells under that amendment, the Company would have a minimum payment of $3.2 million.
We entered into an additional drilling contract with Patterson for a separate drilling rig in January 2025 to drill four (4) horizontal lateral wells. The Company has drilled two (2) wells as of March 31, 2025 associated with this contract. In the event that we elected to not drill the remaining two (2) wells under that amendment, the Company would have a minimum payment of $0.9 million.
Lease Commitments. We do not have any finance lease obligations.
Litigation. From time to time, the Company is 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. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.
Note 15 – 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 our oil and natural gas sales come from customers in the
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
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:

| Three Months Ended March 31,
| 2025 |  | 2024
Total revenues | $ | 85,165 |  | $ | 50,225
Less: |  |  |
Gathering, processing, and transportation | 12,070 |  | 10,456
Lease operating | 7,434 |  | 7,288
Production and ad valorem taxes | 632 |  | 359
Depreciation, depletion, and amortization | 21,258 |  | 15,555
General and administrative | 131,750 |  | 2,128
Other segment (income)/expenses (1) | 40,383 |  | 28,495
Segment income | $ | (128,362) |  | $ | (14,056)

_____________
(1) Other segment (income) expenses are comprised of net interest expense of $3,067 and $4,573 for the three months ended March 31, 2025 and 2024, respectively, gain (loss) on derivative instruments of ($37,218) and ($23,455) for the three months ended March 31, 2025 and 2024, respectively, other income (loss) of ($63) and ($467) for the three months ended March 31, 2025 and 2024, respectively and income tax expense (benefit) of $35 for the three months ended March 31, 2025.
Note 16 – Subsequent Events
The Company has evaluated subsequent events that occurred subsequent to March 31, 2025 in the preparation of its unaudited condensed consolidated financial statements.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterly 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 Quarterly Report and the 2024 Form 10-K, 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.
Overview
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. 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.
Market Conditions and Operational Trends
Our revenue, profitability, and ability to return cash to our equity holders can depend on factors beyond our control, such as economic, political, and regulatory developments that impact market supply and demand. Prices for crude oil, natural gas and NGLs have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.
Concerns of global economic growth, inflation, increases in global oil and natural gas supply levels and the potential for a global trade war resulted in oil price deterioration throughout 2024 and 2025. Oil prices have continued to be influenced by geopolitical tensions and trade policies as well as global economic slowdowns resulting in more downward pressure of prices at the end of the first quarter and beginning of the second quarter of 2025. Natural gas prices remained low for the majority of 2024 driven by an over-supply due to mild winter weather, liquefied natural gas project delays and higher than expected natural gas production, but prices have improved during early 2025.
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2024 through March 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.
The following table highlights the quarterly average price trends for NYMEX WTI spot prices for crude oil and NYMEX Henry Hub index price for natural gas since the first quarter of 2024:

| 2024 |  | 2025
| Q1 |  | Q2 |  | Q3 |  | Q4 |  | Q1
Oil (per Bbl) | $ | 77.56 |  | $ | 81.72 |  | $ | 76.24 |  | $ | 70.73 |  | $ | 71.84
Gas (per MMBtu) | $ | 2.25 |  | $ | 1.89 |  | $ | 2.15 |  | $ | 2.79 |  | $ | 3.65

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Lower commodity prices and lower futures curves for oil and natural gas prices may result in impairments of our proved oil and natural gas properties or undeveloped acreage and may materially and adversely affect our operating cash flows, liquidity, financial condition, results of operations, future business and operations, and/or our ability to finance planned capital expenditures, which could in turn impact our ability to comply with covenants under our Credit Agreement. Lower realized prices may also reduce the borrowing base under our Credit Agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that has been mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under the Credit Agreement.
Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, costs of oilfield goods and services generally also increase; however, during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as commodity prices do. In addition, the United States saw higher levels of inflation during 2024 and the beginning of 2025, which is expected to remain heightened throughout 2025 due to concerns over global trade wars and changes in tariff policies. Inflationary pressures such as these may also result in increases to the costs of our oilfield goods, services and personnel, which can in turn cause our capital expenditures and operating costs to rise.
Recent Developments
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 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 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 Infinity Natural Resources, LLC (“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 our 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.
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 and is responsible for all operational, management and administrative decisions relating to INR Holdings’ business and consolidates the financial results of INR Holdings and reports redeemable non-controlling interests in its consolidated financial statements related to the INR Units that the Legacy Owners own in INR Holdings.
Sources of Revenues
We derive our revenues predominantly from the sale of our oil and natural gas production and the sale of NGLs that are extracted from our natural gas during processing. Our production is entirely from within the continental United States and is similarly sold to purchasers within the United States; however, some of our production revenues are attributable to customers who may export our products.
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 the three months ended March 31, 2025 and 2024, our oil, natural gas, and NGL revenues were comprised of 56% and 54%, respectively, from the sale of oil, 27% from the sale of natural gas in each period, and 17% and 19%, respectively, from the sale of NGLs.
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
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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.
Midstream activities revenues, which consist of gathering, compression, and water handling, are derived from our ownership of INR Midstream, LLC, a subsidiary of INR Holdings. Our gathering and compression revenues relate to activities located within the dry gas areas of southwestern Pennsylvania. Our water handling revenues relate to activities associated with delivering water for stimulation activities in both eastern Ohio and southwestern Pennsylvania.
Principal Components of Our Cost Structure
Lease operating. Lease operating expenses (“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.
Gathering, processing, and transportation. Gathering, processing, and transportation (“GP&T”) expense includes fees paid to third parties who operate low- 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.
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.
Depreciation, depletion, and amortization. Depreciation, depletion, and amortization (“DD&A”) 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.
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.
Interest expense. We have financed a portion of our working capital requirements and property acquisitions with borrowings under the 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 have seen 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.
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
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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.
Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations
Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:
Public Company Expenses. We expect to incur direct, incremental G&A expenses as a result of being a public company, including costs associated with compliance with the Securities Exchange Act of 1934, as amended (the "Exchange Act"), tax compliance, PCAOB support fees, the Sarbanes-Oxley Act 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.
Corporate Reorganization. The historical consolidated financial statements included in this Quarterly Report for periods prior to the Corporate Reorganization and IPO are based on the financial statements of our predecessor, INR Holdings. The historical financial data of our predecessor may not yield an accurate indication of what our actual results would have been if the Corporate Reorganization and IPO had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.
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.
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 for periods prior to the Corporate Reorganization and IPO because taxable income was passed through to our members.
Non-Cash Compensation Expense. In connection with the closing of the IPO, all outstanding performance-based incentive units of INR Holdings vested. Consequently, INR Holdings 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.
Results of Operations
For the Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024
The following table provides the components of our net revenues and net production for the periods indicated, as well as each period’s average prices (before and after the effects of derivatives) and average daily production volumes:
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| For the Three Months Ended March 31, |  | Increase / (Decrease)
| 2025 |  | 2024 |  | $ |  | %
Net revenues (in thousands): |  |  |  |  |  |  |
Oil sales | $47,046 |  | $27,141 |  | $19,905 |  | 73%
Natural gas sales | $22,849 |  | $13,317 |  | $9,532 |  | 72%
Natural gas liquids sales | $14,289 |  | $9,381 |  | $4,908 |  | 52%
Oil, natural gas, and natural gas liquids sales | $84,184 |  | $49,839 |  | $34,345 |  | 69%
Average sales prices: |  |  |  |  |  |  |
Oil price (per Bbl) | $63.40 |  | $68.42 |  | ($5.02) |  | (7%)
Effects of derivative settlements on average price (per Bbl) | $1.30 |  | $0.89 |  | $0.41 |  | 46%
Oil price including the effects of derivatives (per Bbl) | $64.70 |  | $69.31 |  | ($4.61) |  | (7%)
Wtd. Average NYMEX WTI price for oil (per Bbl) (2) | $71.97 |  | $77.27 |  | ($5.30) |  | (7%)
Oil differential to NYMEX | ($8.57) |  | ($8.85) |  | $0.28 |  | 3%
Natural gas price (per Mcf) | $3.51 |  | $1.93 |  | $1.58 |  | 82%
Effects of derivative settlements on average price (per Mcf) | ($0.21) |  | $0.61 |  | ($0.82) |  | (134%)
Natural gas price including the effects of derivatives (per Mcf) | $3.30 |  | $2.54 |  | $0.76 |  | 30%
Wtd. Average NYMEX Henry Hub price for natural gas (per MMBtu)(2) | $3.65 |  | $2.30 |  | $1.35 |  | 59%
Natural gas differential to NYMEX | ($0.14) |  | ($0.37) |  | $0.23 |  | 62%
NGL price excluding GP&T (per Bbl) | $25.49 |  | $24.70 |  | $0.79 |  | 3%
Effects of derivative settlements on average price (per Bbl) | ($0.22) |  | $2.09 |  | ($2.31) |  | (111%)
NGL price including the effects of derivatives (per Bbl) | $25.27 |  | $26.79 |  | ($1.52) |  | (6%)
Net production |  |  |  |  |  |  |
Oil (MBbls) | 742 |  | 397 |  | 345 |  | 87%
Natural gas (MMcf) | 6,519 |  | 6,892 |  | (373) |  | (5%)
NGL (Bbls) | 561 |  | 380 |  | 181 |  | 48%
Net production (MBoe)(1) | 2,389 |  | 1,925 |  | 464 |  | 24%
Average daily net production |  |  |  |  |  |  |
Oil (Bbls/d) | 8,244 |  | 4,359 |  | 3,885 |  | 89%
Natural gas (Mcf/d) | 72,429 |  | 75,742 |  | (3,313) |  | (4%)
NGLs (Bbls/d) | 6,230 |  | 4,174 |  | 2,056 |  | 49%
Average daily net production (Boe/d)(1) | 26,546 |  | 21,157 |  | 5,389 |  | 25%

_____________
(1)Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
(2)Based on Netherland, Sewell and Associates Inc. (“NSAI”) found at https://netherlandsewell.com/resources/pricing-data/ and EIA commodity pricing. (“NSAI”) found at https://netherlandsewell.com/resources/pricing-data/ and U.S. Energy Information Administration (“EIA”). Weighted average is based on INR’s production in a given month during the course of the calendar year.
Revenues
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Oil, natural gas, and NGL sales. Total oil, natural gas and NGL net revenues for the three months ended March 31, 2025 increased by $34.3 million, or 69%, compared to the three months ended March 31, 2024. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Net production volumes for oil and NGLs increased 87% and 48%, respectively, between periods. Net production volumes for natural gas declined 5% between the three months ended March 31, 2025 and 2024. The oil and NGL production volume increase resulted from placing six (6) wells on production from the Ohio Utica’s Volatile Oil Window in late 2024 and one (1) well in early 2025. The decrease in natural gas volumes between periods was due primarily to the normal production decline across existing wells offset by turning into sales five (5) Marcellus Shale wells in Pennsylvania at the end of March 2025. The combination of a full quarter of production from the wells placed into production in late 2024 and new wells placed into production in the first quarter of 2025 contributed to the overall increase of 5.4 Mboe/d, or 25%, in production relative to the prior period.
Average realized sales prices for natural gas and NGLs increased 82% and 3%, respectively, during the period while average realized oil prices decreased 7% for the three months ended March 31, 2025 compared to the prior period. The 7% 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 increased 81% due to 59% higher average NYMEX gas prices between periods and lower natural gas differentials. The 3% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in 2025 compared to 2024 and changes in product composition between periods.
Operating Expenses

| For the Three Months Ended March 31, |  | Change
| 2025 |  | 2024 |  | Amount |  | Percent
(in thousands) |  |  |  |  |  |  |
Gathering, processing, and transportation | $ | 12,070 |  | $ | 10,456 |  | $ | 1,614 |  | 15%
Lease operating | 7,434 |  | 7,288 |  | 146 |  | 2%
Production and ad valorem taxes | 632 |  | 359 |  | 273 |  | 76%
Depreciation, depletion and amortization | 21,258 |  | 15,555 |  | 5,703 |  | 37%
General and administrative (excluding share-based compensation) | 4,856 |  | 2,128 |  | 2,728 |  | 128%
Total operating expenses | $ | 46,250 |  | $ | 35,786 |  | $ | 10,464 |  | 29%
($ per Boe) |  |  |  |  |  |  |
Gathering, processing, and transportation | $ | 5.05 |  | $ | 5.43 |  | $ | (0.38) |  | (7%)
Lease operating | 3.11 |  | 3.79 |  | (0.68) |  | (18%)
Production and ad valorem taxes | 0.26 |  | 0.19 |  | 0.07 |  | 37%
Depreciation, depletion and amortization | 8.90 |  | 8.08 |  | 0.82 |  | 10%
General and administrative | 2.03 |  | 1.11 |  | 0.92 |  | 83%
Total operating expenses | $ | 19.36 |  | $ | 18.59 |  | $ | 0.77 |  | 4%

Gathering, processing, and transportation. GP&T for the three months ended March 31, 2025, increased $1.6 million compared to the three months ended March 31, 2024. This increase is attributed to additional wells brought online in Ohio between periods. GP&T per Boe was $5.05 for the three months ended March 31, 2025, which represents a decrease of $0.38 per Boe, or 7%, from the prior period. The per unit decrease was attributable to improved weighted average costs associated with various midstream systems in Ohio offset partially by lower volumes on INR's owned gathering system in Pennsylvania.
Lease operating. LOE for the three months ended March 31, 2025, increased $0.1 million compared to the prior period. LOE per Boe was $3.11 for the three months ended March 31, 2025, which represents a decrease of $0.68 per Boe, or 18%, from the prior period. This decrease in LOE was primarily related to 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.
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Production and ad valorem taxes. Production and ad valorem taxes for the three months ended March 31, 2025, increased $0.3 million compared to the prior period. 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.
Depreciation, Depletion and Amortization. For the three months ended March 31, 2025, DD&A expense was $21.3 million, an increase of $5.7 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 increased DD&A expense by $3.6 million, while our higher average DD&A rate of $8.68 per Boe increased total DD&A expense by $2.0 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.
General and Administrative Expenses. G&A expenses for the three months ended March 31, 2025 were $131.8 million compared to $2.1 million for the prior period. This increase was primarily due to non cash stock compensation expense of $126.9 million, of which $126.1 million was a one time charge associated with the IPO. We also had higher payroll and employee-related costs due to higher headcount, which increased from 53 as of March 31, 2024 to 91 as of March 31, 2025.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding; and (ii) monthly cash settlements on any closed out hedge positions during the period.
The following table presents gains and losses on our derivative instruments for the periods indicated:

| Three Months Ended March 31,
| 2025 |  | 2024
(in thousands) |  |  |
Realized cash settlement gains (losses) | $ | (3,585) |  | $ | 13,263
Non-cash mark-to-market derivative gain (losses) | (33,633) |  | (36,718)
Total | $ | (37,218) |  | $ | (23,455)

Liquidity and Capital Resources
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 the 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.
We continually evaluate our capital needs and compare them to our capital resources. Our total capital expenditures incurred for development during the three months ended March 31, 2025 were $88.3 million, which includes $78.2 million on drilling and completion activities, $3.5 million on midstream and $6.6 million on land activities. 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 funded our capital expenditures for the three months ended March 31, 2025 from cash flows from operations and borrowings incurred under the Credit Facility. We expect to fund our 2025 capital expenditures budget through a combination of cash flows from operations and additional borrowings under the 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.
We operate the vast majority of our acreage and therefore can largely control the amount and timing of our capital expenditures. Accordingly, we can choose to defer or accelerate a portion of our planned capital expenditures depending on a variety of factors, including but not limited to: (i) prevailing and anticipated prices for oil and natural gas; (ii) the success
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of our drilling activities; (iii) the availability of necessary equipment, infrastructure and capital; (iv) the receipt and timing of required regulatory permits and approvals; (v) seasonal conditions; (vi) property or land acquisition costs; and (vii) the level of participation by other working interest owners.
In February 2025, we completed our IPO of 15.2 million shares of our Class A common stock at a price to the public of $20.00 per share, resulting in net cash proceeds of $286.5 million after deducting underwriting discounts and commissions. We used all of the net proceeds after paying certain offering expenses to repay borrowings outstanding under the Credit Facility.
Although we cannot provide any assurance that cash flows from operations or other sources of needed capital will be available to us at acceptable terms, or at all, and noting that our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control, we believe that based on our current expectations and projections, we have sufficient liquidity to fund future operations and to meet obligations as they become due for at least one year following the filing of this Quarterly Report and for the foreseeable future.
Cash Flow Activity
Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our oil, natural gas and NGLs and the volumes of oil and natural gas that we produce. Oil, natural gas and NGLs are commodities for which established trading markets exist.
Accordingly, our operating cash flow is sensitive to a number of variables, the most significant of which are the volatility of oil, natural gas and NGL prices and production levels both regionally and across the United States, the availability and price of alternative fuels, infrastructure capacity to reach markets, costs of operations, and other variable factors. We monitor factors that we believe could be likely to influence price movements including new or expanded oil and natural gas markets, gas imports, LNG and other exports, and regional and industry-wide capital intensity levels.
Our produced volumes have a high correlation to our level of capital expenditures such that our ability to fund it through operating and financing cash flows may be affected by multiple factors discussed further herein.
The following summarizes our cash flow activity for the periods indicated:

| Three Months Ended March 31,
| 2025 | 2024
(in thousands) |  |
Net cash provided by operating activities | $ | 74,229 | $ | 30,155
Net cash used in investing activities | (108,431) | (38,183)
Net cash provided by financing activities | 36,858 | 9,967
Net increase (decrease) in cash and cash equivalents | $ | 2,656 | $ | 1,939

Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2025 and 2024
Operating activities
For the three months ended March 31, 2025, we generated $74.2 million of cash from operating activities, an increase of $44.1 million from the prior period. Cash provided by operating activities increased primarily due to higher production volumes and higher realized prices for natural gas and associated revenues as compared to the prior period. These factors were partially offset by higher LOE, severance and ad valorem taxes, GP&T, G&A, and lower realized prices for oil and during the three months ended March 31, 2025 as compared to the prior period. 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.
Investing activities
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For the three months ended March 31, 2025, we spent $105.6 million on capital expenditures in connection with our drilling and completion activities. We also spent $2.8 million on other property and equipment largely related to midstream activities.
For the three months ended March 31, 2024, we spent $36.3 million on capital expenditures in connection with our drilling and completion activities. We also spent $1.9 million on other property and equipment.
Financing activities
For the three months ended March 31, 2025, the change in financing activity was primarily related to the IPO which generated net proceeds of $286.5 million. We used funds from the IPO, along with cash from operating activities to pay down borrowings under the Credit Facility of $304.0 million during the period, and we made borrowings under the Credit Facility of $56.0 million during the period. We also paid approximately $0.9 million of other costs associated with the IPO.
For the three months ended March 31, 2024, the change in financing activity was primarily related to borrowing $43.5 million under our prior credit facility and repaying $34.0 million of borrowings. Additionally, there was a capital raise for $0.5 million.
Derivative Activities
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. Accordingly, to achieve more predictable cash flow and reduce our exposure to adverse fluctuations in commodity prices, we use commodity derivatives, such as swaps, to hedge price risk associated with our anticipated production and to underpin our development program. This helps reduce potential negative effects of reductions in oil and gas prices but also reduces our ability to benefit from increases in oil and gas prices. In certain circumstances, where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to utilize their value to further our strategic pursuits.
A fixed price swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
A basis swap involves swapping variable interest rates based on different reference rates. We receive a fixed price differential and pays the floating market price differential to the counterparty which is calculated based on the differential between NYMEX and the natural gas price at a specific delivery point.
A put option has an established floor price. The buyer of that put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
See Note 7 – Derivatives and Risk Management for more information on our derivative activities.
Changes in the fair value of derivative contracts from December 31, 2024 to March 31, 2025, are presented below:
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(in thousands) | Commodity Derivative Asset (Liability)
Net fair value of oil and gas derivative contracts outstanding as of December 31, 2024 | $ | (22,938)
Commodity hedge contract settlement payments, net of any receipts | 3,585
Cash and non-cash mark-to-market gains (losses) on commodity hedge contracts (1) | (37,218)
Net fair value of oil and gas derivative contracts outstanding as of March 31, 2025 | $ | (56,571)

_____________
(1)At inception, new derivative contracts entered into by us have no intrinsic value.
Financing Agreements
Credit Facility
On September 25, 2024, INR Holdings entered into the Credit Facility. 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. 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 $325,000,000 to $350,000,000. As of March 31, 2025, the Company’s reserves supported a $350.0 million borrowing base of which $11.3 million was outstanding, leaving $338.7 million of unused capacity.
For the three months ended March 31, 2025 and 2024, total interest expense on the Credit Facility was $2.6 million and $4.1 million, respectively. We did not capitalize any interest expense for the three months ended March 31, 2025 and 2024. For the three months ended March 31, 2025 and 2024, the Company’s weighted-average interest rate was 5.2% and 8.9%, respectively.
Critical Accounting Estimates
Our unaudited condensed consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) and involve a significant level of estimation uncertainty. In connection with preparing our unaudited condensed consolidated 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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2024 Form 10-K for information on our critical accounting estimates.
Our significant accounting policies are discussed in Note 2 – Summary of Significant Accounting Policies to our unaudited condensed consolidated financial statements in this Quarterly Report.
Contractual Obligations and Commitments
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We routinely enter into or extend operating and transportation agreements, office and equipment leases, drilling rig contracts, and other agreements, in the ordinary course of business. We have not guaranteed the debt or obligations of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in consolidated debt or losses. Since December 31, 2024, there have not been any significant, non-routine changes in our contractual obligations other than drilling rig contracts entered into as discussed in Note 14 – Commitments and Contingencies to our unaudited condensed consolidated financial statements in this Quarterly Report.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.
Oil, Natural Gas and NGL Revenues
Our revenues and cash flows from operations are subject to many variables, the most significant of which is the volatility of commodity prices. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by global economic factors, pipeline capacity constraints, inventory levels, basis differentials, weather conditions and other factors. Commodity prices have long been volatile and unpredictable, and we expect this volatility to continue in the future.
There can be no assurance that commodity prices will not be subject to continued wide fluctuations in the future. A substantial or extended decline in such prices could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil and gas reserves that may be economically produced, which could result in impairments of our oil and gas properties.
Commodity Price Risk and Hedges
Our primary market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue for the foreseeable future. Our revenues, profitability and future growth are highly dependent on the prices we receive for our oil, natural gas and NGL sales, and the levels of our production, and depend on numerous factors beyond our control, some of which are described in “Item 1A. Risk Factors” in the 2024 Form 10-K.
Based on our production for the three months ended March 31, 2024, our oil, natural gas and NGL sales for the three months ended March 31, 2024 would have moved up or down $2.7 million for each 10% change in oil prices per Bbl, $1.3 million for each 10% change in gas prices per Mcf, and $0.9 million for each 10% change in NGL prices per Bbl. Based on our production for the three months ended March 31, 2025, our oil, natural gas and NGL sales for the three months ended March 31, 2025 would have moved up or down $4.7 million for each 10% change in oil prices per Bbl, $2.3 million for each 10% change in gas prices per Mcf, and $1.4 million for each 10% change in NGL prices per Bbl.
Due to this volatility, we have historically used, and we may elect to continue to selectively use, commodity derivative instruments (such as collars, swaps, puts and basis swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flows that can emanate from fluctuations in oil and natural gas prices, and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, but alternatively they partially limit our potential gains from future increases in prices. Our Credit Agreement limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated, projected production from proved properties. “Item 1A. Risk Factors” in the 2024 Form 10-K contains additional information regarding the volumes of our production covered by derivatives and the associated risks.
Counterparty and Customer Credit Risk
Our derivatives expose us to credit risk in the event of nonperformance by counterparties. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. We minimize the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; and (ii) only entering into hedging arrangements with counterparties that are also participants in the Credit Agreement, all of which have investment-grade credit ratings.
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Our principal exposures to credit risk are through receivables resulting from the sales of our oil, natural gas, and NGLs. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our customers is high.
We sell our production to a relatively small number of customers, as is customary in our business. We extend and monitor credit based on an evaluation of their financial conditions and publicly available credit ratings. The future availability of a ready market for oil, natural gas and NGLs depends on numerous factors outside of our control, none of which can be predicted with certainty. For the three months ended March 31, 2025, we had four customers that exceeded 10% of total revenues. We do not believe the loss of any single purchaser would materially impact our operating results as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
Interest Rate Risk
As of March 31, 2025, our reserves supported a $350.0 million credit facility of which $11.3 million in borrowings was outstanding, leaving $338.7 million of unused capacity. Our largest exposure with respect to variable-rate debt comes from changes in the relevant benchmark rate underlying such debt financings, principally SOFR. We currently do not have an interest rate hedge program to hedge our exposure to floating interest rates on our variable-rate debt obligations. If annual interest rates increase 50 basis points, based on our March 31, 2024 and 2025, variable-rate debt, annual interest expense on variable-rate debt would increase by approximately $0.4 million and $0.1 million, respectively.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, evaluated, as of the end of the period covered by this Quarterly Report, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were not effective because of certain material weaknesses in our internal control over financial reporting, as described in “Item 9A. Controls and Procedures” in the 2024 Form 10-K.
Changes in Internal Control Over Financial Reporting
There was no change in the Company’s internal control over financial reporting during the period ended March 31, 2025 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
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Part II - Other Information
Item 1. Legal Proceedings
From time to time, we are subject to mediation, arbitration, litigation, or claims arising in the ordinary course of business. The results of any current or future claims or proceedings cannot be predicted with certainty, and regardless of the outcome, litigation can have an adverse impact on us because of defense and litigation costs, diversion of management resources, reputational harm, and other factors. We do not believe that any existing claims or proceedings will have a material effect on our business, consolidated financial condition or results of operations.
Item 1A. Risk Factors
We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in the 2024 Form 10-K. There have been no material changes to the risks described in such report. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On January 30, 2025, in connection with the recapitalization of INR Holdings, we issued an aggregate of 45,638,889 shares of Class B common stock to the Legacy Owners in exchange for the cancellation of their existing equity interests. No underwriters were involved in the foregoing issuances of securities. Such issuance was undertaken in reliance on an exemption from the registration requirements of the Securities Act pursuant to Section 4(a)(2) thereof as sales by an issuer not involving any public offering. The Company’s reliance upon Section 4(a)(2) of the Securities Act was based upon the following factors: (a) the issuance of the shares was an isolated private transaction by us which did not involve a public offering and (b) there was a limited number of recipients.
Item 3. Defaults upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
Disclosure in lieu of reporting on a Current Report on Form 8-K.
None.
Rule 10b5-1 Trading Arrangements
From time to time, our officers (as defined in Rule 16a–1(f)of the Exchange Act) and directors may enter into Rule 10b5-1 or non-Rule 10b5-1 trading arrangements (as each such term is defined in Item 408 of Regulation S-K). During the three months ended March 31, 2025, none of our officers or directors adopted or terminated any such trading arrangements.
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Item 6. Exhibits

|  |  |  | Incorporated by Reference
Exhibit Number |  | Description |  | Form |  | Exhibit Number |  | Filing Date
3.1 |  | Amended and Restated Certificate of Incorporation of Infinity Natural Resources, Inc. |  | 8-K |  | 3.1 |  | February 3, 2025
3.2 |  | Amended and Restated Bylaws of Infinity Natural Resources, Inc. |  | 8-K |  | 3.2 |  | February 3, 2025
4.1 |  | Registration Rights Agreement, dated February 3, 2025, by and among the Company and each of the other signatories from time to time party thereto. |  | 8-K |  | 4.1 |  | February 3, 2025
10.1†+ |  | Second Amended and Restated Limited Liability Company Agreement of Infinity Natural Resources, LLC, dated as of January 30, 2025, by and among the Company and the other signatories parties thereto. |  | 8-K |  | 10.1 |  | February 3, 2025
10.2 |  | Tax Receivable Agreement, dated as of January 30, 2025, by and among the Company and the TRA Parties (as defined in the Tax Receivable Agreement). |  | 8-K |  | 10.2 |  | February 3, 2025
10.3 |  | Form of Indemnification Agreement. |  | S-1 |  | 10.2 |  | October 4, 2024
10.4†† |  | Infinity Natural Resources, Inc. Omnibus Incentive Plan. |  | 8-K |  | 10.3 |  | February 3, 2025
10.5†† |  | Infinity Natural Resources, Inc. Executive Change in Control and Severance Plan. |  | 8-K |  | 10.4 |  | February 3, 2025
10.6†† |  | Form of Participation Agreement pursuant to Infinity Natural Resources, Inc. Executive Change in Control and Severance Plan. |  | 8-K |  | 10.5 |  | February 3, 2025
10.7†† |  | Form of RSU Grant Notice and Award Agreement (Employee) pursuant to Infinity Natural Resources, Inc. Omnibus Incentive Plan. |  | S-8 |  | 99.2 |  | February 3, 2025
10.8 |  | First Amendment to Credit Agreement, dated as of March 31, 2025, by and among, Infinity Natural Resources, LLC, the lenders party thereto and Citibank, N.A., as the administrative agent, collateral agent and an issuing bank. |  | 8-K |  | 10.1 |  | April 1, 2025
10.9*†† |  | Form of PSU Grant Notice and Award Agreement pursuant to Infinity Natural Resources, Inc. Omnibus Incentive Plan. |  |  |  |  |  |
10.10*†† |  | Form of RSU Grant Notice and Award Agreement pursuant to Infinity Natural Resources, Inc. Omnibus Incentive Plan. |  |  |  |  |  |
10.11*†† |  | Form of RSU Grant Notice and Award Agreement (Non-Employee Director) pursuant to Infinity Natural Resources, Inc. Omnibus Incentive Plan. |  |  |  |  |  |
31.1* |  | Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. |  |  |  |  |  |
31.2* |  | Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. |  |  |  |  |  |
32.1** |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350. |  |  |  |  |  |
32.2** |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350. |  |  |  |  |  |
101* |  | The following financial information from this Quarterly Report on Form 10-Q of Infinity Natural Resources, Inc. for the quarter ended March 31, 2025 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Redeemable Non-controlling Interest and Stockholders’ Deficit / Members’ Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements. |  |  |  |  |  |
104 |  | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |  |  |  |  |  |

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* | Filed herewith.
** | Furnished herewith.
+ | Certain portions of this document that constitute confidential information have been redacted in accordance with Regulation S-K, Item 601(b)(10). The Company hereby agrees to furnish a copy of any omitted portion to the SEC upon request.
† | Certain of the schedules and exhibits to the agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished to the SEC upon request.
†† | Management contract of compensatory plan or agreement.

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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

| INFINITY NATURAL RESOURCES, INC.
Date: May 13, 2025 | By: | /s/ Zack Arnold
|  | Zack Arnold
|  | President, Chief Executive Officer and Director
| By: | /s/ David Sproule
|  | David Sproule
|  | Executive Vice President, Chief Financial Officer and Director

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