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Table of Con t ents

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, 2026
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 8, 2026 was 18,751,607 and 44,780,230, respectively.

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Table of Contents

| 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 | 29
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 40
Item 4. Controls and Procedures | 41
Part II - Other Information | 42
Item 1. Legal Proceedings | 42
Item 1A. Risk Factors | 42
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 42
Item 3. Defaults Upon Senior Securities | 42
Item 4. Mine Safety Disclosures | 42
Item 5. Other Information | 42
Item 6. Exhibits | 43
Signatures | 45

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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, our ability to make share repurchases, 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,” “target,” “outlook,” “guidance,” “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, 2025 (the “2025 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;
•our ability to integrate operations or realize any anticipated operational or corporate synergies and other benefits of our acquisitions, including the Antero Acquisition;
•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 armed conflict and instability in the Middle East, Venezuela, Mexico 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;
•risks and restrictions related to our debt agreements and the level of our indebtedness;
•risks and restrictions related to our Series A Preferred Stock;
•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;
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•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;
•our costs of developing our properties;
•general global political and economic conditions, including changes in interest rates and associated Federal Reserve policies and the impact of inflation on our business;
•changes in tariffs, trade policy, trade barriers, price and exchange controls and other regulatory requirements;
•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 2025 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 2025 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.
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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;
•“Bcf” means one billion standard cubic feet of natural gas;
•“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 2025 Form 10-K;
•“dth/d” means one decatherm per day;
•“gas” means natural gas;
•“gross” means “gross” natural gas and oil wells or “gross” acres equal to the total number of wells or acres in which we have a working interest, without regard to our proportionate ownership interest;
•“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;
•“MBbl” means one thousand barrels of oil, condensate or NGLs;
•“Mcf” means one thousand standard cubic feet of natural gas;
•“Mcfe” means one thousand cubic feet of natural gas equivalent with one barrel of oil, condensate or NGLs converted to six Mcf of natural gas;
•“Mcfe/d” means Mcfe per day;
•“MMBtu” means one million British thermal units;
•“MMcf” means one million standard cubic feet of natural gas;
•“MMcf/d” means one million standard cubic feet of natural gas per day;
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•“MMcfe” means one million cubic feet of natural gas equivalent with one barrel of oil, condensate or NGLs converted to six Mcf of natural gas;
•“MMcfe/d” means MMcfe per day;
•“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;
•“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 currently 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, 2026 |  | December 31, 2025 |
Assets |  |  |  |
Current assets: |  |  |  |
Cash and cash equivalents | $ | 72,983 |  | $ | 2,849 |
Accounts receivable: |  |  |  |
Oil and natural gas sales, net | 72,380 |  | 54,836 |
Joint interest and other, net | 13,042 |  | 12,912 |
Short-term deposit on acquisitions | — |  | 61,200 |
Prepaid expenses and other current assets | 8,474 |  | 4,002 |
Commodity derivative assets | 10,814 |  | 24,838 |
Total current assets | $ | 177,693 |  | $ | 160,637 |
Oil and natural gas properties, full cost method (including $126.4 million and $88.7 million as of March 31, 2026 and December 31, 2025, respectively excluded from amortization) | 1,842,791 |  | 1,264,212 |
Midstream and other property and equipment | 343,066 |  | 57,116 |
Less: Accumulated depreciation, depletion, and amortization | (292,235) |  | (256,712) |
Property and equipment, net | $ | 1,893,622 |  | $ | 1,064,616 |
Operating lease right-of-use assets, net | 1,684 |  | 1,147 |
Deferred tax asset, net | 5,211 |  | 4,858 |
Other assets | 18,585 |  | 6,709 |
Commodity derivative assets | 2,692 |  | 2,885 |
Total assets | $ | 2,099,487 |  | $ | 1,240,852 |
Total Liabilities, Stockholders’ Equity, Redeemable Interest and Series A Preferred Stock |  |  |  |
Current liabilities: |  |  |  |
Accounts payable | $ | 47,586 |  | $ | 38,572 |
Royalties payable | 59,205 |  | 39,686 |
Accrued liabilities and other | 65,277 |  | 23,021 |
Operating lease liabilities | 535 |  | 181 |
Commodity derivative liabilities, short-term | 30,931 |  | 1,106 |
Total current liabilities | $ | 203,534 |  | $ | 102,566 |
Long-term debt | 537,648 |  | 150,862 |
Operating lease liabilities, non-current | 1,149 |  | 966 |
Asset retirement obligations | 7,424 |  | 3,636 |
Commodity derivative liabilities | 6,461 |  | 3,361 |
Tax receivable agreement | 3,585 |  | 1,537 |
Total liabilities | $ | 759,801 |  | $ | 262,928 |
Series A Preferred Stock ($0.01 par value, 350,000 and 0 shares issued and outstanding as of March 31, 2026 and December 31, 2025, respectively) | 337,080 |  | — |
Redeemable non-controlling interest | 822,165 |  | 670,785 |
Stockholders’ equity / members’ equity |  |  |  |
Class A common stock—$0.01 par value; 400,000,000 shares authorized, 18,751,177 and 15,542,521 shares issued and outstanding as of March 31, 2026 and December 31, 2025, respectively | 187 |  | 155 |
Class B common stock—$0.01 par value; 150,000,000 shares authorized, 44,780,230 and 45,247,974 shares issued and outstanding as of March 31, 2026 and December 31, 2025, respectively | 447 |  | 452 |
Additional paid-in capital | 189,222 |  | 310,972 |
Accumulated deficit | (9,415) |  | (4,440) |
Total stockholders’ equity | 180,441 |  | 307,139 |
Total liabilities, stockholders’ equity, redeemable interest and Series A preferred stock | $ | 2,099,487 |  | $ | 1,240,852 |

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, |
|  |  |  |  | 2026 |  | 2025 |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |
Oil, natural gas, and natural gas liquids sales |  |  |  |  | $ | 150,704 |  | $ | 84,184 |  |  |
Midstream activities |  |  |  |  | 4,168 |  | 981 |  |  |
Total revenues |  |  |  |  | $ | 154,872 |  | $ | 85,165 |  |  |
Operating expenses: |  |  |  |  |  |  |  |  |  |
Gathering, processing, and transportation |  |  |  |  | 19,723 |  | 12,070 |  |  |
Lease operating |  |  |  |  | 8,916 |  | 6,772 |  |  |
Production and ad valorem taxes |  |  |  |  | 2,349 |  | 632 |  |  |
Midstream operations and maintenance expense |  |  |  |  | 1,478 |  | 662 |  |  |
Depreciation, depletion, and amortization |  |  |  |  | 35,660 |  | 21,258 |  |  |
General and administrative (1) |  |  |  |  | 21,413 |  | 131,750 |  |  |
Total operating expenses |  |  |  |  | $ | 89,539 |  | $ | 173,144 |  |  |
Operating income (loss) |  |  |  |  | 65,333 |  | (87,979) |  |  |
Other income (expense): |  |  |  |  |  |  |  |  |  |
Interest, net |  |  |  |  | (5,789) |  | (3,067) |  |  |
Loss on derivative instruments |  |  |  |  | (65,134) |  | (37,218) |  |  |
Other expense |  |  |  |  | (1,101) |  | (63) |  |  |
Net loss before income tax expense (benefit) |  |  |  |  | (6,691) |  | (128,327) |  |  |
Income tax expense (benefit) |  |  |  |  | (348) |  | 35 |  |  |
Net loss |  |  |  |  | $ | (6,343) |  | $ | (128,362) |  |  |
Net income attributable to Infinity Natural Resources, LLC prior to the reorganization |  |  |  |  | — |  | 9,914 |  |  |
Net loss attributable to redeemable non-controlling interests |  |  |  |  | (4,472) |  | (103,707) |  |  |
Net loss attributable to Infinity Natural Resources, Inc. |  |  |  |  | $ | (1,871) |  | $ | (34,569) |  |  |
Net income attributable to Infinity Natural Resources, Inc. per share of Class A common stock |  |  |  |  |  |  |  |  |  |
Basic: |  |  |  |  |  |  |  |  |  |
Weighted-average common stock outstanding |  |  |  |  | 17,662,870 |  | 15,237,500 |  |  |
Net loss per share of Class A common stock |  |  |  |  | $ | (0.28) |  | (2.27) |  |  |
Diluted: |  |  |  |  |  |  |  |  |  |
Weighted-average common stock outstanding |  |  |  |  | 17,662,870 |  | 15,237,500 |  |  |
Net loss per share of Class A common stock |  |  |  |  | $ | (0.28) |  | (2.27) |  |  |

(1) General and administrative expense includes share-based compensation of $126.1 million for the three months ended March 31, 2025, incurred in connection with the Company's initial public offering (“IPO”).
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 Stockholders' Equity, Redeemable Non-controlling Interest and Series A Preferred Stock (Unaudited)
(amounts in thousands, except share amounts)

| Class A | Class B | Additional Paid in Capital | Accumulated Deficit | Total | Redeemable Non-controlling Interest | Series A Preferred Stock |
Three Months Ended March 31, 2026 | Shares | Amount | Shares | Amount |
Balance as of December 31, 2025 | 15,542,521 | $ | 155 | 45,247,974 | $ | 452 | $ | 310,972 | $ | (4,440) | $ | 307,139 | $ | 670,785 | $ | — |
Share-based compensation expense |  | — | — | — | 2,262 | — | 2,262 | — | — |
RSU vested net of tax withholdings | 223,718 | 2 |  |  | (1,203) |  | (1,201) |  |  |
Net loss | — | — | — | — | — | (1,871) | (1,871) | (4,472) | — |
Issuance of Class A common stock for acquisition | 2,517,194 | 25 | — | — | 35,090 | — | 35,115 | — | — |
Issuance of Series A Preferred net of issuance costs | — | — | — | — | — | — | — | — | 333,976 |
Accretion of dividends on Series A Preferred | — | — | — | — | — | (3,104) | (3,104) | — | 3,104 |
Conversion of Class B Units to Class A Units | 467,744 | 5 | (467,744) | (5) | 6,888 |  | 6,888 | (6,888) |  |
Increase in Tax Receivable Agreement Liability / Establishment of liabilities under the Tax Receivable Agreement |  |  |  |  | $ | (2,047) |  | $ | (2,047) |  |  |
Adjustment of redeemable non-controlling interest to redemption value | — | — | $ | — | — | $ | (162,740) | $ | — | $ | (162,740) | $ | 162,740 | $ | — |
Balance as of March 31, 2026 | 18,751,177 | $ | 187 | 44,780,230 | $ | 447 | $ | 189,222 | $ | (9,415) | $ | 180,441 | $ | 822,165 | $ | 337,080 |

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| 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 |

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, |
| 2026 |  | 2025 |  |  |
Cash flows from operating activities: |  |  |  |  |  |
Net loss | $ | (6,343) |  |  | $ | (128,362) |  |  |  |
Adjustments to reconcile net loss to net cash provided by operating activities: |  |  |  |  |  |
Depreciation, depletion, and amortization | 35,660 |  |  | 21,258 |  |  |  |
Amortization of debt issuance costs | 1,511 |  |  | 527 |  |  |  |
Loss on extinguishment of debt | 316 |  |  | — |  |  |  |
Share-based compensation expense | 2,262 |  |  | 126,895 |  |  |  |
Loss on derivative instruments | 65,134 |  |  | 37,218 |  |  |  |
Cash paid on settlement of derivative instruments | (17,992) |  |  | (3,585) |  |  |  |
Non-cash lease expense | 72 |  |  | 80 |  |  |  |
Deferred income taxes | (353) |  |  | 35 |  |  |  |
Changes in operating assets and liabilities: |  |  |  |  |  |
Accounts receivable | (17,674) |  |  | 22,013 |  |  |  |
Prepaid expenses and other assets | (4,635) |  |  | (1,151) |  |  |  |
Accounts payable | (13,697) |  |  | (978) |  |  |  |
Royalties payable | 6,463 |  |  | 3,319 |  |  |  |
Accrued and other expenses | 7,812 |  |  | (4,707) |  |  |  |
Other assets and liabilities | (109) |  |  | 1,667 |  |  |  |
Net cash provided by operating activities | $ | 58,427 |  |  | $ | 74,229 |  |  |  |
Cash flows from investing activities: |  |  |  |  |  |
Additions to oil and gas properties | (75,570) |  |  | (105,665) |  |  |  |
Acquisitions of oil and gas properties and midstream assets | (622,534) |  |  | — |  |  |  |
Additions to midstream and other property and equipment | (808) |  |  | (2,766) |  |  |  |
Net cash used in investing activities | $ | (698,912) |  |  | $ | (108,431) |  |  |  |
Cash flows from financing activities: |  |  |  |  |  |
Borrowings under revolving credit facility | 430,530 |  |  | 56,000 |  |  |  |
Payments on revolving credit facility | (581,376) |  |  | (304,000) |  |  |  |
Proceeds from issuance of Notes | 550,000 |  |  | — |  |  |  |
Proceeds from issuance of Class A common stock in initial public offering, net of underwriting discounts and commissions | — |  |  | 286,465 |  |  |  |
Proceeds from issuance of Series A preferred stock | 350,000 |  |  | — |  |  |  |
Payments of credit facility debt issuance costs | (13,257) |  |  | (645) |  |  |  |
Payments of Notes debt issuance costs | (9,626) |  |  | — |  |  |  |
Cancelled shares withheld for taxes from vesting of RSUs | (1,201) |  |  | — |  |  |  |
Payments of Series A preferred stock issuance costs | (14,396) |  |  | — |  |  |  |
Payments on notes payable | (55) |  |  | (37) |  |  |  |
Payments of initial public offering costs | — |  |  | (925) |  |  |  |
Net cash provided by financing activities | $ | 710,619 |  |  | $ | 36,858 |  |  |  |
Net increase in cash and cash equivalents | 70,134 |  |  | 2,656 |  |  |  |
Cash and cash equivalents at beginning of period | 2,849 |  |  | 2,203 |  |  |  |
Cash and cash equivalents at end of period | $ | 72,983 |  |  | $ | 4,859 |  |  |  |

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), is an independent oil and natural gas exploration, production and midstream 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, as well as the gathering of natural gas. Our operations are located in the Appalachian Basin, primarily in Pennsylvania and Ohio, targeting the Utica and Marcellus formations.
Principles of Consolidation and Basis of 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 Securities and Exchange Commission (“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, 2025 and the related notes included in the Company’s 2025 Form 10-K. The December 31, 2025, 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. The consolidated financial statements include the accounts of the Company, its subsidiary, Infinity Natural Resources, LLC (“INR Holdings”), and INR Holdings' wholly-owned subsidiaries. Noncontrolling interests represent third-party ownership in INR Holdings and are presented as a component of equity. Refer to Note 12 – Stockholders' Equity and Noncontrolling Interest for a discussion of noncontrolling interest.
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.
Reclassification. Certain previously reported amounts have been reclassified to conform with the current financial statement presentation. These reclassifications have no impact on previously reported total assets, total liabilities, net income or total operating cash flows.
Note 2 – Summary of Significant Accounting Policies
Refer to Note 2 – Summary of Significant Accounting Policies of our 2025 Form 10-K for the full list of our significant accounting policies.
Business Combinations. We account for business combinations under the Business Combinations Topic of the Financial Accounting Standards Board's (FASB) Accounting Standards Codification ("ASC 805"), which requires identifiable assets acquired and liabilities assumed to be recognized at their acquisition date fair values. See Note 4 for further discussion of the Antero acquisition.
Midstream operations and maintenance expense. Midstream operations and maintenance expense consists primarily of costs incurred to operate and maintain the Company’s owned gathering, compression, and related midstream infrastructure, including labor, power, repairs and maintenance, and insurance. These costs exclude third‑party gathering, processing, and transportation fees, which are presented separately within gathering, processing, and transportation expense.
Series A Preferred Stock. The Company accounts for its Series A Preferred Stock (as defined herein) in accordance with the applicable guidance in ASC 480 and SEC guidance for redeemable equity instruments. The Series A Preferred Stock is classified as mezzanine equity because it is redeemable upon the occurrence of events that are not solely within the
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Notes to Condensed Consolidated Financial Statements
Company’s control. All financial instruments are evaluated for embedded derivative features by analyzing each feature against the nature of the host instrument (e.g., more equity-like or debt-like). Features identified as freestanding instruments or bifurcated embedded derivatives that are material are recognized separately as a derivative asset or liability. The Series A Preferred Stock is initially recorded at the net proceeds received, net of directly attributable issuance costs. The carrying amount of the Series A Preferred Stock is not adjusted to redemption value unless the instrument becomes redeemable or probable of becoming redeemable. If redemption becomes probable, the Company will accrete the carrying amount to redemption value using the interest method over the period to the earliest redemption date. Accretion to redemption value (when applicable) and cumulative dividends, including PIK dividends, are treated as deemed dividends and reduce income available to holders of the Company's Class A common stock in the calculation of earnings per share.
Accretion to redemption value (when applicable) and cumulative dividends, including PIK dividends, are treated as deemed dividends and reduce income available to holders of the Company's Class A common stock in the calculation of earnings per share.
In April 2026, the FASB issued Accounting Standards Update (“ASU”) 2026‑01, Initial Measurement of Paid‑in‑Kind Dividends on Equity‑Classified Preferred Stock. The ASU requires paid‑in‑kind (“PIK”) dividends on equity‑classified preferred stock to be measured using the stated PIK dividend rate applied to the liquidation preference of the preferred stock, thereby reducing diversity in practice related to the measurement of such dividends.
The Company early adopted ASU 2026‑01 during the three months ended March 31, 2026 using a prospective transition method. Upon adoption, the Company measures PIK dividends based on the stated dividend rate applied to the liquidation preference of its Series A Preferred Stock. The adoption of this guidance impacted the measurement of PIK dividends and the amount of income (loss) available to common stockholders used in the calculation of earnings (loss) per share. The adoption did not have a material impact on the Company’s consolidated financial statements.
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;
•estimates related to the TRA (as defined herein); and
•determining fair value and allocating purchase price in connection with business combinations and asset acquisitions.
Redeemable Non-controlling Interest. Redeemable non-controlling interests are presented within our unaudited condensed consolidated balance sheet as of March 31, 2026 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, 2026. The redemption amount is calculated based on the 5-day volume-weighted average closing price 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-
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Notes to Condensed Consolidated Financial Statements
controlling interests on our unaudited condensed consolidated statement of operations for the three months ended March 31, 2026.
Income Taxes. The Company is 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 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. The Company entered into a Tax Receivable Agreement (“TRA”) with the owners of INR Holdings prior to the IPO (“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 common units representing limited liability company interests in INR Holdings (“INR Units”) and the corresponding surrender of an equivalent number of shares of the Company's Class B common stock, par value $0.01 per share (“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 Second Amended and Restated Limited Liability Company Agreement of INR Holdings (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 10 – Income Taxes and Tax Receivable Agreement for further details.
Earnings per Share. Basic earnings (loss) per share is calculated by dividing net income (loss) available to Class A common stockholders by the weighted average number of shares of Class A common stock outstanding during the period. Net income attributable to Class A common stock is reduced by dividends on the Company’s Series A Preferred Stock, including dividends paid in kind, whether or not declared.
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 13 – Share-based Compensation), 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 and the assumed conversion of the Company's Series A Preferred 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
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Notes to Condensed Consolidated Financial Statements
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 (“RSUs”), fair value is determined based on the closing stock price of the Company’s Class A common stock on the grant date. RSUs represent awards that entitle the holder to receive shares of the Company’s Class A common stock upon vesting, subject to satisfaction of applicable service conditions. 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.
Recently Issued Accounting Standards
Accounting Standards Recently Adopted. In April 2026, the FASB issued Accounting Standards Update (“ASU”) 2026‑01, Initial Measurement of Paid‑in‑Kind Dividends on Equity‑Classified Preferred Stock. The ASU provides guidance on the initial measurement of paid‑in‑kind (“PIK”) dividends on equity‑classified preferred stock by requiring such dividends to be measured based on the stated dividend rate applied to the liquidation preference of the preferred stock. The guidance is intended to reduce diversity in practice related to the measurement of PIK dividends. The ASU is effective for fiscal years beginning after December 15, 2026, with early adoption permitted. The Company early adopted ASU 2026‑01 during the three months ended March 31, 2026 using a prospective transition method. The adoption did not have a material impact on the Company’s consolidated financial statements.
Accounting Standards Not Yet Adopted. In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270): Narrow-Scope Improvements, to clarify the scope and presentation requirements for interim GAAP financial statements and to consolidate interim disclosure requirements. Under this ASU, entities must disclose material events or changes occurring after year end that affect interim periods. The amendments in this ASU are effective for interim reporting periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either prospectively or retrospectively to any or all prior periods presented in the financial statements. The Company is evaluating the impact ASU 2025-11 will have on its financial statements and related disclosures.
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.
Note 3 – Revenues
Crude oil, natural gas, and NGL sales are recognized at the point in time when control of the product is transferred to the customer. Virtually all of our contract pricing provisions are based on market indices, with adjustments for transportation costs, quality differentials, and other contractual factors.
The table below provides disaggregated information on the Company’s oil, natural gas, and NGL revenues included in the consolidated statements of operations:

|  |  | Three Months Ended March 31,
|  |  |  |  | 2026 |  | 2025 |  |
(in thousands) |  |  |  |  |  |  |  |  |
Oil revenues |  |  |  |  | $ | 56,822 |  | $ | 47,046 |  |
Natural gas revenues |  |  |  |  | 74,080 |  | 22,849 |  |
NGL revenues |  |  |  |  | 19,802 |  | 14,289 |  |
Oil, natural gas, and natural gas liquids sales |  |  |  |  | $ | 150,704 |  | $ | 84,184 |  |

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Notes to Condensed Consolidated Financial Statements
Oil Sales
Our crude oil sales contracts are generally structured such that oil is delivered to the customer at a contractually agreed-upon delivery point, typically at the wellhead. Revenue is recognized when control and legal title transfers to the customer at the delivery point based on the net price received. Downstream transportation or marketing costs incurred by purchasers are reflected in the price received and are presented as a net reduction to oil sales revenues.
The sales of crude oil, natural gas, and NGLs presented in the Condensed Consolidated Statements of Operations represent the Company’s share of the revenues net of royalties and exclude revenue interests by others. When marketing production on behalf of royalty or working interest owners, the Company acts as an agent and, therefore, reports the revenue on a net basis.
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. The Company evaluates when control of the residue gas and NGLs transfers to determine whether revenues should be recognized on a gross or net basis. Fees incurred after transfer of control are recorded as gathering, processing and transportation expense, while fees incurred prior to transfer of control are reflected as a net reduction to natural gas and NGL revenues.
Performance Obligations
The Company has certain commodity sales contracts that contemplate the delivery of products over time. Under the Company’s revenue agreements, each individual delivery generally represents a separate performance obligation that is satisfied upon delivery. As a result, future volumes to be delivered under these contracts represent wholly unsatisfied performance obligations, and disclosure of the transaction price allocated to remaining performance obligations is not required.
For all commodity products, the Company recognizes revenue in the month production is delivered to the purchaser. Settlement statements for crude oil sales are generally received within 30 days following delivery, while settlement statements for natural gas and NGL sales may be received approximately 30 to 60 days after delivery. Payment is unconditional once the performance obligations have been satisfied. At that time, the delivered volumes and applicable 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, 2026 and December 31, 2025, such receivable balances were $72.4 million and $54.8 million, respectively.
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Notes to Condensed Consolidated Financial Statements
Note 4 - Acquisitions
2026 Antero Acquisition
On February 23, 2026, the Company completed the acquisition of certain upstream oil and gas properties and related midstream assets in Ohio from affiliates of Antero Resources Corporation and Antero Midstream LLC (the “Antero Acquisition”), pursuant to purchase and sale agreements dated December 5, 2025, each as amended on February 22, 2026. The Antero Acquisition significantly increased the Company’s production volumes, proved reserves, gathering and transportation capacity, and overall asset base. The total gross purchase price was approximately $1.2 billion in cash, consisting of $800 million for the upstream assets and $400 million for the midstream assets. The Company acquired a 60% undivided interest in the assets, with Northern Oil and Gas Inc. acquiring the remaining 40%.
The Company’s aggregate consideration for its 60% interest in the Antero Acquisition was approximately $683.9 million, which reflects preliminary purchase price adjustments and remains subject to finalization. The acquisition was financed with borrowings under the Company’s Credit Facility and net proceeds from the issuance of Series A Preferred Stock. The Antero Acquisition was accounted for as an asset acquisition in accordance with ASC 805.
Transaction costs of $13.5 million and $0 related to the Antero Acquisition are included in the statements of operations for the three months ended March 31, 2026 and 2025, respectively.
Nonrecurring Fair Value Measurements
The fair values of assets acquired and liabilities assumed in an acquisition are measured on a non-recurring basis on the acquisition date. If the assets acquired and liabilities assumed are current and short-term in nature, the Company typically uses their approximate carrying values as it believes that it approximates their fair values. If the assets acquired are not short-term in nature, then the fair value is determined using the estimated future cash flows or other appropriate methods, and as such, are considered Level 3 inputs in the fair value hierarchy.
The Antero Acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805, and the Company estimated the fair value of assets acquired and liabilities assumed as of February 23, 2026.
The fair values of the proved developed producing, proved undeveloped, probable and possible oil and natural gas reserves acquired in the Antero Acquisition were measured using an income approach based on discounted cash flow valuation techniques. The valuations utilize inputs that are not observable in the market and as such are Level 3 fair value measurements. Significant inputs used in the valuation of proved and unproved reserves included commodity prices based on NYMEX strip pricing as of February 23, 2026, projected reserve quantities based on a third-party reserve report, estimated future rates of production and production decline curves, projected reserve recovery factors, development plans including timing and amount of development, future development costs, operating costs and a weighted average cost of capital of 9.5%. The fair value of unevaluated acreage with no associated reserve development plans acquired in the Antero Acquisition was measured using a market approach based on guideline transactions involving comparable Appalachian Basin acreage. This measurement is classified as a Level 3 fair value measurement as the acreage pricing inputs are derived from market transactions that require significant judgment and adjustment.
The fair value of midstream and other property and equipment (gathering systems, compression facilities and water systems) acquired in the Antero Acquisition was measured using a cost approach based on estimated replacement cost new less physical depreciation, functional obsolescence and economic obsolescence. These measurements are classified as Level 3 fair value measurements as the replacement cost estimates and depreciation assumptions are not observable in the market.
Purchase Price Allocation
The following table presents the preliminary allocation of the Company’s consideration to the identifiable assets acquired and liabilities assumed based on their estimated fair values as of the acquisition date. The allocation is preliminary and subject to change as the Company completes its valuation analysis and obtains additional information related to the fair values of the acquired assets and assumed liabilities.
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Notes to Condensed Consolidated Financial Statements

(in thousands) |  | Preliminary Consideration
Cash (1) |  | $ | 683,897 |
Total estimated consideration |  | $ | 683,897 |
|  | Preliminary Purchase Price Allocation
Assets acquired: |  |
Oil and natural gas properties, full cost method |  | $ | 416,527 |
Midstream and other property and equipment |  | 283,927 |
Total assets acquired |  | $ | 700,454 |
Liabilities assumed: |  |
Royalties payable |  | 13,056 |
Asset retirement obligations |  | 3,501 |
Total liabilities assumed |  | 16,557 |
Net assets acquired |  | $ | 683,897 |

(1) Inclusive of approximately $61.4 million of cash deposit held in escrow as of December 31, 2025.
Pro Forma Financial Information
The following unaudited pro forma financial information represents a summary of the condensed combined results of operations of the Company for the three months ended March 31, 2026 and 2025, assuming the Antero Acquisition and related transactions, including the issuance of the Series A Preferred Stock, occurred on January 1, 2025. The pro forma financial information is provided for illustrative purposes and is not necessarily indicative of results that would have been achieved had the Antero Acquisition occurred on that date, nor is it indicative of future operating results.
The pro forma results include adjustments to depreciation, depletion and amortization based on the purchase price allocated to Oil and natural gas properties, full cost method and Midstream and other property and equipment and the estimated useful lives as well as adjustments to accretion expense and interest expense for the financing of the transactions.
The pro forma adjustments are based on estimates and assumptions that management believes are reasonable under the circumstances. The results of operations from the date of the Antero Acquisition through March 31, 2026 represented approximately $13.9 million of revenue and $8.6 million of income from operations. The pro forma results do not include anticipated synergies or integration-related costs.

|  | Three Months Ended March 31,
(in thousands) |  | 2026 |  | 2025
Revenues |  | $ | 175,726 |  |  | $ | 115,070 |
Net loss |  | $ | (3,074) |  |  | $ | (126,177) |
Net loss attributable to Infinity Natural Resources, Inc. |  | $ | (907) |  |  | $ | (34,023) |
Less |  |  |  |
Accretion of Series A Preferred Stock cumulative undeclared dividends |  | $ | (35,484) |  |  | $ | (6,813) |
Net loss attributable to Infinity Natural Resources, Inc. - Basic and diluted |  | $ | (36,391) |  |  | $ | (40,836) |
Net loss attributable to Infinity Natural Resources, Inc.- basic and diluted |  | $ | (2.06) |  |  | $ | (2.68) |

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Notes to Condensed Consolidated Financial Statements
Note 5 – 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, 2026 and December 31, 2025 are as follows:

| March 31, 2026 |  | December 31, 2025 |
(in thousands) |  |  |  |
Oil and natural gas properties: |  |  |  |
Proved properties | $ | 1,716,425 |  | $ | 1,175,523 |
Unproved properties | 126,366 |  | 88,689 |
Gross oil and natural gas properties | 1,842,791 |  | 1,264,212 |
Less: accumulated depreciation, depletion, and amortization | (283,221) |  | (249,296) |
Oil and natural gas properties, net | $ | 1,559,570 |  | $ | 1,014,916 |

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. When the book value is in excess of the ceiling value, an impairment is recognized. No impairment expense was recorded for the three months ended March 31, 2026 based on the results of the quarterly ceiling test.
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 will 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, if any. Historically, the Company has 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, 2026 and 2025 related to oil and gas properties:

|  |  | For the Three Months Ended March 31,
(in thousands, except per Boe amounts) |  |  |  |  | 2026 |  | 2025
Depletion of Proved Oil and Natural Gas Properties |  |  |  |  | 33,925 |  | 20,577
Average Depletion Rate per Boe |  |  |  |  | $ | 7.50 |  | $ | 8.68

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
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Notes to Condensed Consolidated Financial Statements
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, 2026 |  | December 31, 2025 |
Midstream assets | $ | 338,327 |  | $ | 53,077 |
Other property and equipment | 4,739 |  | 4,039 |
Gross midstream and other property and equipment | 343,066 |  | 57,116 |
Less: accumulated depreciation | (9,014) |  | (7,416) |
Total midstream and other property and equipment, net | $ | 334,052 |  | $ | 49,700 |

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, 2026 and 2025. Total depreciation expense for the three months ended March 31, 2026 and 2025 totaled approximately $1.6 million and $0.6 million, respectively.
Note 6 – Accrued Liabilities and Other
The Company’s accrued liabilities as of March 31, 2026 and December 31, 2025 consisted of the following amounts:

| March 31, 2026 |  | December 31, 2025 |
Accrued capital expenditures | 35,706 |  | 7,270 |
Accrued general and administrative expenses | 15,896 |  | 7,706 |
JIB advance deposits | 2,357 |  | 1,296 |
Other accrued liabilities | 11,318 |  | 6,749 |
Total accrued liabilities | $ | 65,277 |  | $ | 23,021 |

Note 7 – Long-Term Debt
Credit Facility
On September 25, 2024, INR Holdings entered into a credit facility led by Citibank, N.A. (the “Credit Facility” and the credit agreement governing the Credit Facility, as amended, the “Credit Agreement”) with a syndicate of financial institutions with an initial aggregate elected commitment amount and initial borrowing base of $325.0 million. On March 31, 2025, the Company amended the Credit Agreement to, among other things, increase each of the aggregate elected commitment amount and borrowing base from $325.0 million to $350.0 million. On May 29, 2025, the Company amended the Credit Agreement to, among other things, amend certain provisions relating to hedging requirements and restrictions in the Credit Agreement. Effective October 1, 2025, the borrowing base under the Credit Facility increased from
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Notes to Condensed Consolidated Financial Statements
$350.0 million to $375.0 million and the aggregate elected commitment amount was also increased from $350.0 million to $375.0 million. On December 5, 2025, INR Holdings entered into that certain Third Amendment to Credit Agreement, which among other things amended certain provisions relating to hedging requirements and restrictions, debt incurrences and permitted acquisitions in the Credit Agreement. On February 23, 2026, INR Holdings entered into a fourth amendment to the Credit Agreement (the “Fourth Amendment”). The Fourth Amendment, among other things, increased the aggregate elected commitment and borrowing base under the Credit Agreement from $375.0 million to $875.0 million and removed the credit spread adjustment previously applicable to Secured Overnight Financing Rate (“SOFR”) borrowings. 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.
The Credit Facility bears interest at a rate equal to, at the Company’s election, either (a) SOFR benchmark plus an applicable margin that varies from 2.75% to 3.75% per annum or (b) a base rate plus an applicable margin that varies from 1.75% to 2.75% per annum, based on borrowing base utilization. The Company is also required to pay a commitment fee of 0.50% per annum on the average daily unused portion of the current aggregate commitments under the Credit Facility. The Company is also required to pay customary letter of credit and fronting fees. As of March 31, 2026, the Company had no borrowings outstanding under the Credit Facility with $19.2 million in letters of credit, leaving $855.8 million of unused capacity.
For the three months ended March 31, 2026 and 2025, total interest expense on the Credit Facility was $4.4 million and $2.6 million, respectively. We had $0.1 million and zero capitalized interest expense for the three months ended March 31, 2026 and 2025, respectively. For the three months ended March 31, 2026 and 2025, the Company’s weighted-average interest rate was 6.9% and 5.2%, 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.
We had $13.6 million of additional capitalized debt issuance costs related to the Credit Facility for the three months ended March 31, 2026. As of March 31, 2026 and December 31, 2025, capitalized debt issuance costs were approximately $18.5 million and $6.7 million, respectively.
Amortization of debt issuance costs, which is included within interest expense in the condensed consolidated statements of operations, was approximately $1.8 million and $0.5 million for the three months ended March 31, 2026 and 2025, respectively.
The Credit Facility also requires INR Holdings 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 Credit Facility described above through the date these unaudited condensed consolidated financial statements were available to be issued.
7.625% Senior Notes due 2031
On March 20, 2026, INR Holdings issued $550.0 million aggregate principal amount of 7.625% senior notes due 2031 (the “Notes”) at par. The Notes were issued pursuant to an indenture, dated March 20, 2026 (the “Indenture”), by and among INR Holdings, certain subsidiary guarantors (the “Guarantors”), and U.S. Bank Trust Company, National Association, as trustee. The Notes bear interest at a fixed rate of 7.625% per annum, payable semi-annually in arrears on April 1 and October 1 of each year, commencing on October 1, 2026. The Notes will mature on April 1, 2031, unless earlier redeemed or repurchased.
The Notes are the general, unsecured, senior obligations of INR Holdings. The Notes are guaranteed on a senior unsecured basis by the Guarantors and may be guaranteed by certain future subsidiaries of INR Holdings. The Notes and the related guarantees rank equally in right of payment with the borrowings under our Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our Credit
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Notes to Condensed Consolidated Financial Statements
Facility) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Notes.
INR Holdings may, at its option, redeem all or a portion of the Notes at any time on or after April 1, 2028 at certain redemption prices. At any time prior to April 1, 2028, INR Holdings may redeem up to 40% of the aggregate principal amount of the Notes, with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 107.625% of the aggregate principal amount of the Notes redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. In addition, at any time prior to April 1, 2028, INR Holdings may, on any one or more occasions, redeem all or a part of the Notes at a redemption price equal to 100.00% of the principal amount of the Notes redeemed, plus a “make whole” premium and accrued and unpaid interest, if any, to, but excluding, the date of redemption.
If INR Holdings experiences certain kinds of changes of control, each holder of the Notes may require INR Holdings to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such Notes, plus accrued and unpaid interest, if any, to the date of repurchase.
The Indenture contains covenants that, among other things and subject to certain exceptions and qualifications, limit the ability of INR Holdings and its restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from its restricted subsidiaries to INR Holdings or any of their restricted subsidiaries; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
Debt issuance costs associated with the Notes are offset against the corresponding liability on the unaudited condensed consolidated balance sheet. Debt issuance costs are amortized using the straight-line method over the term of the related agreement.
We had $12.4 million of debt issuance costs related to the Notes for the three months ended March 31, 2026. As of March 31, 2026, debt issuance costs netted against the corresponding liability was approximately $12.4 million.
Amortization of debt issuance costs associated with the Notes, which is included within interest expense in the condensed consolidated statements of operations, was approximately $0.1 million for the three months ended March 31, 2026.
Note 8 – Derivatives and Risk Management
The Company is exposed to volatility in market prices and basis differentials for oil, natural gas, and NGLs, which can impact 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. The Company’s oil option positions primarily consist of costless collars, which combine purchased put options and sold call options with offsetting volumes and differing strike prices. The tables below present these component instruments on a gross basis. As a result of our hedging activities, we may realize prices that are greater or less than the market prices that we would have otherwise received.
We typically enter into over-the-counter (OTC) derivative contracts with financial institutions and regularly monitor the creditworthiness of all counterparties. Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our Credit Facility. As of March 31, 2026 and December 31, 2025, 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
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Notes to Condensed Consolidated Financial Statements
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, 2026.

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2026 |
Oil | (in MBbls) |  | ($ per Bbl) |  | (in thousands) |
Fixed price swaps |  |  |  |  |  |
2026 | 1,851 |  | 63.58 |  | $ | (32,059) |
2027 | 1,597 |  | 63.22 |  | (10,515) |
2028 | 408 |  | 67.95 |  | 236 |
2029 | 24 |  | 68.37 |  | 51 |
Total | 3,880 |  |  |  | $ | (42,287) |

| Volume |  | Floor / Ceiling |  | Fair Value as of March 31, 2026 |
Oil | (in MBbls) |  | ($ per Bbl) |  | (in thousands) |
Options price |  |  |  |  |  |
2026 | 219 |  | 70.00 - 78.00 |  | (1,255) |  |
2027 | 35 |  | 70.00 - 78.00 |  | 56 |  |
Total | 254 |  |  |  | $ | (1,199) |  |

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2026 |
Natural gas | (in MMBtu) |  | ($ per MMBtu) |  | (in thousands) |
Fixed price swaps |  |  |  |  |  |
2026 | 44,756,000 |  | 3.64 |  | $ | 27,448 |
2027 | 56,419,000 |  | 3.76 |  | 7,039 |
2028 | 36,647,000 |  | 3.77 |  | (1,302) |
2029 | 30,320,000 |  | 3.62 |  | (981) |
2030 | 26,580,000 |  | 3.57 |  | (1,421) |
2031 | 2,120,000 |  | 4.08 |  | (372) |
Total | 196,842,000 |  |  |  | $ | 30,411 |

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Notes to Condensed Consolidated Financial Statements

| Volume |  | Basis Differential |  | Fair Value as of March 31, 2026 |
Natural gas | (in MMBtu) |  | ($ per MMBtu) |  | (in thousands) |
Basis swaps |  |  |  |  |  |
2026 | 40,690,000 |  | (0.93) |  | $ | (3,835) |
2027 | 31,629,000 |  | (0.64) |  | (1,291) |
2028 | 32,603,750 |  | (0.52) |  | 250 |
2029 | 2,607,500 |  | (0.30) |  | 234 |
Total | 107,530,250 |  |  |  | $ | (4,641) |

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2026 |
Ethane | (in gallons) |  | ($ per gallon) |  | (in thousands) |
Fixed price swaps |  |  |  |  |  |
2026 | 6,163,000 |  | 0.28 |  | $ | 213 |
2027 | 7,294,000 |  | 0.25 |  | 61 |
2028 | 530,000 |  | 0.24 |  | 2 |
Total | 13,987,000 |  |  |  | $ | 276 |

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2026 |
Propane | (in gallons) |  | ($ per gallon) |  | (in thousands) |
Fixed price swaps |  |  |  |  |  |
2026 | 28,043,000 |  | 0.74 |  | $ | (1,104) |
2027 | 37,516,000 |  | 0.73 |  | (97) |
2028 | 2,521,000 |  | 0.71 |  | 12 |
Total | 68,080,000 |  |  |  | $ | (1,189) |

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2026 |
Isobutane | (in gallons) |  | ($ per gallon) |  | (in thousands) |
Fixed price swaps |  |  |  |  |  |
2026 | 5,882,000 |  | 0.94 |  | $ | (747) |
2027 | 8,090,000 |  | 0.91 |  | (218) |
2028 | 539,000 |  | 0.88 |  | (2) |
Total | 14,511,000 |  |  |  | $ | (967) |

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2026 |
Normal butane | (in gallons) |  | ($ per gallon) |  | (in thousands) |
Fixed price swaps |  |  |  |  |  |
2026 | 7,841,000 |  | 0.89 |  | $ | (1,189) |
2027 | 10,261,000 |  | 0.87 |  | (420) |
2028 | 703,000 |  | 0.84 |  | (15) |
Total | 18,805,000 |  |  |  | $ | (1,624) |

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Notes to Condensed Consolidated Financial Statements

| Volume |  | Weighted Average Price |  | Fair Value as of March 31, 2026 |
Pentane | (in gallons) |  | ($ per gallon) |  | (in thousands) |
Fixed price swaps |  |  |  |  |  |
2026 | 6,980,000 |  | 1.51 |  | $ | (2,213) |
2027 | 9,477,000 |  | 1.40 |  | (440) |
2028 | 652,000 |  | 1.35 |  | (13) |
Total | 17,109,000 |  |  |  | $ | (2,666) |

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, 2026 and December 31, 2025:

| March 31, 2026
Balance Sheet Classification | Gross Amounts |  | Netting Adjustment |  | Net Amounts Presented on Balance Sheet
(in thousands) |  |  |  |  |
Assets |  |  |  |  |
Commodity derivative assets, short-term | $ | 33,273 |  | $ | (22,459) |  | $ | 10,814
Commodity derivative assets, long-term | 13,824 |  | (11,133) |  | 2,692
Total assets | $ | 47,097 |  | $ | (33,592) |  | $ | 13,506
Liabilities |  |  |  |  |
Commodity derivative liabilities, short-term | $ | (53,391) |  | $ | 22,459 |  | $ | (30,931)
Commodity derivative liabilities, long-term | (17,594) |  | 11,133 |  | (6,461)
Total liabilities | $ | (70,985) |  | $ | 33,592 |  | $ | (37,392)

| December 31, 2025
Balance Sheet Classification | Gross Amounts |  | Netting Adjustment |  | Net Amounts Presented on Balance Sheet
(in thousands) |  |  |  |  |
Assets |  |  |  |  |
Commodity derivative assets, short-term | $ | 32,718 |  |  | $ | (7,880) |  |  | $ | 24,838 |
Commodity derivative assets, long-term | 7,701 |  |  | (4,816) |  |  | 2,885 |
Total assets | $ | 40,419 |  |  | $ | (12,696) |  |  | $ | 27,723 |
Liabilities |  |  |  |  |
Commodity derivative liabilities, short-term | $ | (8,986) |  |  | $ | 7,880 |  |  | $ | (1,106) |
Commodity derivative liabilities, long-term | (8,177) |  |  | 4,816 |  |  | (3,361) |
Total liabilities | $ | (17,163) |  |  | $ | 12,696 |  |  | $ | (4,467) |

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Notes to Condensed Consolidated Financial Statements
Our total derivative gains and losses for the three months ended March 31, 2026 and 2025 were as follows:

|  |  | For the Three Months Ended March 31,
(in thousands) |  |  |  |  | 2026 |  | 2025 |  |
Realized gain (loss) on derivative instruments |  |  |  |  | $ | (17,992) |  | $ | (3,585) |  |
Unrealized loss on derivative instruments |  |  |  |  | (47,142) |  | (33,633) |  |
Total loss on derivative instruments |  |  |  |  | $ | (65,134) |  | $ | (37,218) |  |

Note 9 – 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 Company has categorized its assets and liabilities at fair value into a three-level fair value hierarchy based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities that use Level 2 inputs include the Company’s fixed price swaps, basis swaps, and collars.
The carrying values of cash and cash equivalents, 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 Credit Facility approximates fair value because the interest rates are variable and reflective of market rates. We consider the fair value of our Credit Facility to be a Level 2 measurement on the fair value hierarchy.
The Notes were issued in a private placement and are carried at amortized cost. The estimated fair value of the Notes is determined using observable market inputs, including prices and yields for similar debt instruments with comparable terms and maturities, and is categorized as a Level 2 fair value measurement within the fair value hierarchy. As of March 31, 2026, the carrying value of the Notes approximated their estimated fair value.
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, 2026 |
| Level 1 |  | Level 2 |  | Level 3 |  | Fair Value |
(in thousands) |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |
Fixed price swaps | $ | — |  | $ | 30,687 |  | $ | — |  | $ | 30,687 |
Basis swaps | — |  | 3,298 |  | — |  | 3,298 |
Options | — |  | 1,268 |  | — |  | 1,268 |
Liabilities |  |  |  |  |  |  |  |
Fixed price swaps | — |  | (48,734) |  | — |  | (48,734) |
Basis swaps | — |  | (7,937) |  | — |  | (7,937) |
Options | — |  | (2,467) |  | — |  | (2,467) |
Total | $ | — |  | $ | (23,886) |  | $ | — |  | $ | (23,886) |

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| December 31, 2025 |
| Level 1 |  | Level 2 |  | Level 3 |  | Fair Value |
(in thousands) |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |
Fixed price swaps | $ | — |  | $ | 33,079 |  | $ | — |  | $ | 33,079 |
Basis swaps | — |  | 349 |  | — |  | 349 |
Liabilities |  |  |  |  |  |  |  |
Fixed price swaps | — |  | — |  | — |  | — |
Basis swaps | — |  | (10,172) |  | — |  | (10,172) |
Total | $ | — |  | $ | 23,256 |  | $ | — |  | $ | 23,256 |

Derivative assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. We have classified our derivative instruments into levels depending upon the data utilized to determine their fair values. The Company uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. As such, we use Level 2 inputs to measure the fair value of commodity derivative contracts.
Note 10 – Income Taxes and Tax Receivable Agreement
The Company recorded income tax (benefit) of $(0.4) million for the three months ended March 31, 2026. No income tax expense (benefit) was recorded for the three months ended 2025.
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 4.97% and (0.03)% for the three months ended March 31, 2026 and 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, OpCo, 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 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 the periods prior to the Offering. OpCo 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 OpCo is reported in the respective tax returns of its members.
The Company had no activity or holdings prior to the Offering.
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
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Notes to Condensed Consolidated Financial Statements
exchange of INR Units and the corresponding surrender of an equivalent number of shares of Class B common stock by the Legacy Owners for a number of shares of Class A common stock on a one-for-one basis or, at our option, the receipt of an equivalent amount of cash pursuant to the INR Holdings LLC Agreement and (ii) deductions arising from imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the TRA. We will retain the benefit of the remaining 15% of these cash savings, if any.
On March 13, 2026, Legacy Owners redeemed 467,744 INR Units for shares of Class A common stock on a one-for-one basis. Concurrently with each redemption of the INR Units, an equal number of shares of Class B common stock were cancelled. The Company recognizes a liability for the estimated amounts payable under the TRA when it is probable that taxable income will be sufficient to realize the related tax benefits and the amounts can be reasonably estimated. The estimation of liability under the TRA is by its nature imprecise and subject to significant assumptions regarding the amount, character, and timing of the taxable income of the Company in the future. Changes in tax laws or rates could also materially impact the estimated liability. As of March 31, 2026, the Company recorded a TRA liability of $3.6 million, all of which has been classified as a non-current liability.
Note 11 – Series A Convertible Preferred Stock
On February 18, 2026, Infinity Natural Resources, Inc. (the "Company" or "INR") entered into a Securities Purchase Agreement with affiliates of Quantum Capital Group ("Quantum") and Carnelian Energy Capital Management ("Carnelian") pursuant to which the Company issued and sold an aggregate of 350,000 shares of Series A Convertible Preferred Stock (the "Series A Preferred Stock"), par value $0.01 per share, at an original purchase price of $1,000.00 per share, for total gross proceeds of $350.0 million on February 23, 2026 (the "Preferred Stock Transaction"). The Series A Preferred Stock carries an initial liquidation preference of $1,000 per share and ranks senior to the Company's Class A common stock with respect to dividend rights and rights upon liquidation.
Holders of the Series A Preferred Stock are entitled to receive cumulative quarterly dividends at a rate of 8.0% per annum through the fifth anniversary of the initial issuance date, increasing to 12.0% per annum thereafter. Dividends accrue quarterly and may be paid in cash when declared or added to the liquidation preference if unpaid through the second anniversary of the initial issuance date. The dividend rate is subject to an automatic increase of 2.0% per annum if the Company is unable to pay dividends in cash due to restrictions under its Credit Agreement after the second anniversary of the initial issuance date. Each holder of Series A Preferred Stock has the right to participate in any dividends declared on the Class A common stock on an as-converted basis.
The Series A Preferred Stock is convertible into shares of Class A common stock at the option of the holders at an initial conversion price of $21.39 per share, subject to customary anti-dilution adjustments for stock splits, stock dividends, tender offers, spin-offs, and rights distributions.
Beginning three years after issuance, the Company has the right to require mandatory conversion of all or any portion of the Series A Preferred Stock into shares of Class A common stock, provided that the closing price of the Company's Class A common stock exceeds 140% of the conversion price for 20 of 30 consecutive trading days and certain liquidity conditions are met.
The Company has the option to redeem the Series A Preferred Stock beginning on the fifth anniversary of the initial issuance date at a redemption price that will provide the holders with a 15.0% per annum internal rate of return ("IRR") based on the initial liquidation preference through the redemption date.
Holders of the Series A Preferred Stock have the right to require the Company to repurchase their shares upon the occurrence of a Change of Control (as defined in the Certificate of Designation of the Series A Preferred Stock). A Change of Control is defined to include, among other events, the acquisition by a third party of more than 50% of the Company's voting stock, a sale of all or substantially all of the Company's assets, or a delisting of the Class A common stock from a national securities exchange. Upon a Change of Control, each holder may elect to either (i) convert at the then-current conversion price or (ii) require the Company to repurchase such shares at the Change of Control Repurchase Price (as defined in the Certificate of Designation), which is the greater of (a) an amount (together with all prior distributions) necessary to achieve a 13.0% per annum IRR on the initial liquidation preference or (b) a 1.30x return on the initial liquidation preference.
The Series A Preferred Stock is classified as temporary (mezzanine) equity on the consolidated balance sheets because the instrument is redeemable for cash upon the occurrence of a Change of Control, an event that is not solely within the
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Company's control. The Company evaluated the Series A Preferred Stock for embedded derivative features, including certain dividend rate step-up provisions related to credit agreement restrictions and share issuance limitations. Based on this evaluation, the Company concluded that these features do not result in material derivative instruments requiring separate accounting as of the issuance date or as of March 31, 2026.
The Series A Preferred Stock was initially recorded at approximately $334.0 million, representing $350.0 million in aggregate gross proceeds less approximately $16.0 million of directly attributable issuance costs. Issuance costs consisted of registration fees, filing fees, listing fees, legal and accounting fees, and other directly attributable costs, and were recorded as a direct reduction of the carrying amount of the Series A Preferred Stock within mezzanine equity.
The Series A Preferred Stock had a carrying value of $337.1 million, including accrued dividends of $3.1 million, as of March 31, 2026.
Note 12 – Stockholders' Equity and Noncontrolling Interest
As of March 31, 2026, the Company’s equity structure consists of Class A common stock, Class B common stock and Series A Preferred 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. Legacy Owners own an approximate 70.5% interest in INR Holdings and we own an approximate 29.5% 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.
Holders of Series A Preferred Stock generally are entitled to vote with the holders of the shares of Class A common stock on all matters submitted for a vote of holders of shares of Class A common stock (voting together with the holders of shares of Class A common stock as one class) on an as-converted basis, subject to certain limitations.
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, 2026, 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.
Note 13 – Share-based Compensation
Omnibus Incentive Plan
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 has 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, with a corresponding credit to APIC in the consolidated balance sheet.
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
Restricted Stock Units
In March 2026, the Company granted an additional 531,623 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 one-year anniversary of the grant date.
In February and March 2026, 294,638 previously issued RSUs vested and settled in Class A common stock, of which 70,571 were withheld to cover employee tax obligations. The total fair value of shares vested was $5.2 million and the fair value of shares withheld $1.2 million which was remitted in cash to the tax authorities.
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, 2026:

| RSUs |  | Weighted-average grant date fair value
Unvested as of beginning of period | 433,482 |  | $ | 18.17
Granted | 531,623 |  | $ | 17.26
Vested and settled | (294,638) |  | $ | 18.65
Canceled/Forfeited | (1,625) |  | $ | 17.23
Unvested as of end of period | 668,842 |  | $ | 17.23

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 $1.1 million and $0.6 million for the three months ended March 31, 2026 and 2025, respectively.
As of March 31, 2026, unrecognized compensation expense related to unvested RSU awards was $11.2 million, which is expected to be recognized over a weighted-average remaining service period of 2.5 years.
Performance Stock Units
In March 2025, the Company granted Performance Stock Units ("PSUs") under the Plan to certain employees. The PSUs are subject to a performance period from the grant date to December 31, 2027.
In March 2026, the Company granted additional PSUs under the Plan to certain employees. The PSUs are subject to a performance period from January 1, 2026 to December 31, 2028.
For all PSUs, 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 applicable 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.
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements

| 2026 | 2025
Expected volatility | 45.00% | 40.00%
Risk-free rate | 3.50% | 4.04%
Expected dividend yield | —% | —%
Correlation with peer group range | 25.00% - 68.00% | 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, 2026:

| PSUs |  | Weighted-average grant date fair value
Unvested as of beginning of period | 426,582 |  | $ | 22.20
Granted | 428,363 |  | 32.04
Vested | — |  | —
Canceled/Forfeited | — |  | —
Unvested as of end of period | 854,945 |  | $ | 27.13

The Company recognized compensation expense for PSUs of $1.1 million and $0.1 million for the three months ended March 31, 2026 and 2025, respectively.
As of March 31, 2026, unrecognized compensation expense related to unvested PSU awards was $19.5 million, which is expected to be recognized over a weighted-average remaining service period of 2.6 years.
Note 14 – Earnings Per Share
Income available to Class A common stockholders is reduced by accretion on the Series A Preferred Stock, which is treated as a deemed dividend. Although the Series A Preferred Stock is not currently redeemable and redemption is not considered probable, the Company elected, as an accounting policy, to accrete the carrying amount from inception to the maximum redemption value using the interest method. Basic earnings per share is calculated by dividing income available to Class A common stockholders 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 of INR Units (and the cancellation of an equal number of shares of Class B common stock) held by the Legacy Owners into shares of Class A common stock. The Series A Preferred Stock is not included in diluted earnings per share because conversion is not considered probable, and the effect would be anti‑dilutive for the periods presented.
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

| Three Months Ended March 31, 2026 |  | Three Months Ended March 31, 2025
(in thousands, except per share amounts) |  |  |
Net loss attributable to Infinity Natural Resources, Inc. | $ | (1,871) |  | $ | (34,569)
Less |  |  |
Accretion of Series A Preferred Stock cumulative undeclared dividends | $ | (3,104) |  | $ | —
Net loss available to Class A common stockholders | $ | (4,975) |  | $ | (34,569)
Weighted average number of common units outstanding: |  |  |
Basic | 17,662,870 |  | 15,237,500
Effect of dilutive securities: |  |  |
INR Units | — |  | —
RSUs | — |  | —
PSUs | — |  | —
Diluted | 17,662,870 |  | 15,237,500
Net loss available to Class A common stockholders per share |  |  |
Basic | $ | (0.28) |  | $ | (2.27)
Diluted | $ | (0.28) |  | $ | (2.27)

The calculation of diluted net loss per share for the three months ended March 31, 2026 and 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, (ii) and unvested RSUs and PSUs, respectively, and (iii) the assumed conversion of the Company’s Series A Preferred Stock, because their inclusion in the calculation would be anti-dilutive.
Note 15 – Supplemental Cash Flow Information
The following table provides additional information concerning non-cash activities and cash paid for interest, for the three months ended March 31, 2026 and 2025:

| For the Three Months Ended March 31, |  |
| 2026 |  | 2025 |  |  |  |
(in thousands) |  |  |  |  |  |  |
Supplemental disclosure of non-cash transactions: |  |  |  |  |  |  |
ROU asset/Lease liability (ASC 842) new additions/reductions | $ | 609 |  | $ | — |  |  |  |
ARO additions | 185 |  | 80 |  |  |  |
Acquisition of oil and gas property in exchange for Class A common stock | 35,115 |  | — |  |  |  |
RSUs capitalized | 1,549 |  | — |  |  |  |
Deferred offering costs included in accounts payable and accrued liabilities | — |  | (5,856) |  |  |  |
Additions to oil and gas properties in accounts payable and accrued liabilities | 69,069 |  | 34,753 |  |  |  |
Additions to other property and equipment included in accounts payable | 1,428 |  | 1,145 |  |  |  |
Additions to liabilities under the Tax Receivable Agreement | 2,047 |  | — |  |  |  |
Issuance costs in accrued liabilities | 4,798 |  | — |  |  |  |
Capitalized interest | 81 |  | — |  |  |  |
Interest paid | 4,645 |  | 2,800 |  |  |  |

Note 16 – Commitments and Contingencies
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
Drilling Rig Service Commitments. As of March 31, 2026, we have a minimum payment of $6.8 million related to our drilling rig services contracts.
Firm Transportation Commitment. In February 2026, we entered into a firm transportation agreement for an average daily commitment of 300,000 dth/d through January 2030, and thereafter 100,000 dth/d through January 2035.
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 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 17 – 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 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. See our Condensed Consolidated Statement of Operations.
The following table provides information about the Company’s one reportable segment and includes the reconciliation to consolidated net income:

|  |  | For the Three Months Ended March 31,
|  |  |  |  | 2026 |  | 2025 |  |
Total revenues |  |  |  |  | 154,872 |  | 85,165 |  |
Less: |  |  |  |  |  |  |  |  |
Gathering, processing, and transportation |  |  |  |  | 19,723 |  | 12,070 |  |
Lease operating |  |  |  |  | 8,916 |  | 6,772 |  |
Production and ad valorem taxes |  |  |  |  | 2,349 |  | 632 |  |
Midstream operations and maintenance expense |  |  |  |  | 1,478 |  | 662 |  |
Depreciation, depletion, and amortization |  |  |  |  | 35,660 |  | 21,258 |  |
General and administrative |  |  |  |  | 21,413 |  | 131,750 |  |
Other segment (income)/expenses(1) |  |  |  |  | 71,676 |  | 40,383 |  |
Segment income |  |  |  |  | $ | (6,343) |  | $ | (128,362) |  |

_____________
(1) Other segment (income) expenses are comprised of net interest expense of $5.8 million and $3.1 million for the three months ended March 31, 2026 and 2025, respectively, gain (loss) on derivative instruments of $(65.1) million and $(37.2) million for the three months ended March 31, 2026 and 2025, respectively, other income (loss) of $(1.1) million and $(0.1) million for the three months ended March 31, 2026 and 2025, respectively and income tax expense (benefit) of $(0.3) million for the three months ended March 31, 2026.
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INFINITY NATURAL RESOURCES, INC. AND SUBSIDIARIES
Notes to Condensed Consolidated Financial Statements
Note 18 –Subsequent Events
The Company has evaluated subsequent events that occurred subsequent to March 31, 2026 and determined that there were no events requiring recognition or disclosure in these 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 2025 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, production and gathering of hydrocarbons in the Appalachian Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible balance sheet. Our operations are focused on the Utica Shale in eastern Ohio as well as our dry gas assets in both the Marcellus and Utica Shales in southwestern Pennsylvania, providing highly economic stacked development inventory that leverages shared infrastructure and operational efficiencies. Our portfolio is balanced across oil and natural gas assets, allowing us to optimize our development plan to respond to changes in commodity prices over time.
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.
Commodity prices were volatile in the first quarter of 2026 and we expect commodity prices to continue to be volatile for the remainder of 2026 due to macroeconomic uncertainty, changes to the regulatory environment and geopolitical instability and tensions, including in the Middle East, Venezuela, Russia and Ukraine, and potential further imposition of domestic and foreign tariffs. For example, in late February and early March 2026, military conflict involving the United States, Israel and Iran escalated in the Middle East, increasing geopolitical uncertainty in global energy markets. Concerns over disruptions to oil, natural gas and LNG production and shipping routes in the region may contribute to market price volatility for an undeterminable period of time. Domestically, natural gas prices have been negatively impacted in recent months by a combination of mild weather and increased production. Our revenue, profitability, liquidity and financial position will continue to be impacted in the future by the market prices for oil, natural gas and NGLs.
The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2026 through March 31, 2026, monthly index prices for NYMEX WTI crude oil ranged from $60.04 per Bbl to $91.38 per Bbl, while the range for NYMEX Henry Hub natural gas monthly index prices were between $2.98 per MMBtu and $7.49 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 2025:

| 2025 |  | 2026
| Q1 |  | Q2 |  | Q3 |  | Q4 |  |  |  | Q1 |  |  |  |  |  |  |  |
Oil (per Bbl) | $ | 71.84 |  |  | $ | 64.63 |  |  | $ | 65.74 |  |  | $ | 59.64 |  |  |  |  | $ | 71.98 |  |  |  |  |  |  |  |  |
Gas (per MMBtu) | $ | 3.65 |  |  | $ | 3.44 |  |  | $ | 3.07 |  |  | $ | 3.55 |  |  |  |  | $ | 5.05 |  |  |  |  |  |  |  |  |

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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.
Recent Developments
Chase Acquisition
On January 20, 2026, the Company and INR Holdings entered into a purchase and sale agreement (the “Chase Purchase Agreement”) with Chase Oil Corporation, a New Mexico corporation, and certain other sellers (each a “Chase Seller” and, collectively, “Chase Sellers”) for the acquisition of certain non-operated rights, title and interests in oil and gas properties, rights and related assets located in the State of Pennsylvania from the Chase Sellers (the “Chase Acquisition”), for consideration of 2,517,194 shares of the Company’s Class A common stock. The Chase Acquisition closed on January 20, 2026, simultaneously with the execution of the Chase Purchase Agreement.
Preferred Stock Transaction
On February 23, 2026, we issued and sold an aggregate 350,000 shares of Series A Preferred Stock to affiliates of Quantum and Carnelian for consideration of $350 million. After deducting placement agent fees, Infinity received net proceeds of approximately $334.0 million. Quantum acquired 275,000 shares of Series A Preferred Stock, and Carnelian acquired 75,000 shares of Series A Preferred Stock. The Company used the proceeds of the Preferred Stock Transaction to fund a portion of the purchase price for the Antero Acquisition and used the remaining proceeds for general corporate purposes.
Antero Acquisition
On February 23, 2026 the Company completed the Antero Acquisition of certain upstream oil and gas properties and related midstream assets in Ohio for a purchase price of $720.0 million for cash consideration of $683.9 million. The Antero Acquisition was financed with the proceeds of the issuance of Series A Preferred Stock and borrowings under the Credit Facility.
Notes Offering
On March 20, 2026, the Company completed the offering of the Notes. The proceeds from the issuance of the Notes were used to repay outstanding borrowings under our Credit Facility and for other general corporate purposes.
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:
Antero Acquisition. On February 23, 2026, the Company completed the Antero Acquisition. As a result, the Company’s results of operations for the three months ended March 31, 2026 include only a partial period of contribution from the acquired assets, whereas future periods will reflect a full‑period contribution. The Antero Acquisition significantly increased the Company’s production volumes, proved reserves, gathering and transportation capacity, and overall asset base, which materially impacts the comparability of revenues, operating expenses (including gathering, processing and transportation, lease operating expenses, production and ad valorem taxes, and depreciation, depletion and amortization), and cash flows between periods.
Full‑Period Versus Partial‑Period Effects. The Company’s results for the three months ended March 31, 2026 reflect the impact of assets placed into service or acquired at different points in time, including wells placed on production throughout 2025 and early 2026 and the partial‑period contribution from the Antero Acquisition. As a result, production volumes, revenues, and certain operating costs for the current period are not directly comparable to the prior‑year period,
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which did not include the acquired properties or a full period of production from certain development activity. Additionally, certain operating costs include a higher proportion of fixed or semi‑fixed components that do not scale linearly with production; therefore, per‑unit cost metrics may fluctuate between periods as production volumes increase.
Non-Cash Compensation Expense. In connection with the closing of the IPO in 2025, all outstanding 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 for the three months ended March 31, 2025, in accordance with the guidance provided by ASC 710.
For the Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025
Summary Results of Operations
Total revenues for the three months ended March 31, 2026 increased $66.5 million, or 79%, compared to the three months ended March 31, 2025, primarily driven by higher production volumes resulting from development activity and the partial‑period contribution of assets acquired in the Antero Acquisition, as well as higher realized natural gas and oil prices. Net production increased 88% period over period, reflecting a partial period of production from assets acquired in the Antero Acquisition and production from wells placed on production throughout 2025 and early 2026.
Total operating expenses for the three months ended March 31, 2026 decreased $83.6 million, or 48%, compared to the prior‑year period, primarily due to the absence of $126.1 million of non‑recurring, non‑cash stock‑based compensation expense recognized in connection with the Company’s initial public offering in the prior‑year period. Excluding this item, operating expenses increased due to higher production volumes, the partial‑period contribution of assets acquired in the Antero Acquisition, and increased development and operating activity.
On a per‑unit basis, direct operating expenses for three months ended March 31, 2026 declined $0.20 per Mcfe to $1.20 per Mcfe, or 14%, compared to the prior-year period, reflecting improved cost absorption and scale benefits associated with higher production volumes.
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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:

| For the Three Months Ended March 31, |  | Increase / (Decrease)
| 2026 |  | 2025 |  | $ |  | %
Net revenues (in thousands): |  |  |  |  |  |  |
Oil sales | $56,822 |  | $47,046 |  | $9,776 |  | 21%
Natural gas sales | $74,080 |  | $22,849 |  | $51,231 |  | 224%
Natural gas liquids sales | $19,802 |  | $14,289 |  | $5,513 |  | 39%
Oil, natural gas, and natural gas liquids sales | $150,704 |  | $84,184 |  | $66,520 |  | 79%
Average sales prices: |  |  |  |  |  |  |
Oil price (per Bbl) | $65.77 |  | $63.40 |  | $2.37 |  | 4%
Effects of derivative settlements on average price (per Bbl) | ($7.37) |  | $1.30 |  | ($8.67) |  | (667)%
Oil price including the effects of derivatives (per Bbl) | $58.40 |  | $64.70 |  | ($6.30) |  | (10%)
Wtd. Average NYMEX WTI price for oil (per Bbl)(2)(3) | $72.76 |  | $71.97 |  | $0.79 |  | 1%
Oil differential to NYMEX | ($6.99) |  | ($8.57) |  | $1.58 |  | 18%
Natural gas price (per Mcf) | $4.23 |  | $3.51 |  | $0.72 |  | 20%
Effects of derivative settlements on average price (per Mcf) | ($0.69) |  | ($0.21) |  | ($0.48) |  | (229%)
Natural gas price including the effects of derivatives (per Mcf) | $3.54 |  | $3.30 |  | $0.24 |  | 7%
Wtd. Average NYMEX Henry Hub price for natural gas (per MMBtu)(2)(3) | $4.86 |  | $3.65 |  | $1.21 |  | 33%
Natural gas differential to NYMEX | ($0.63) |  | ($0.14) |  | ($0.49) |  | (350)%
NGL price excluding GP&T (per Bbl) | $28.17 |  | $25.49 |  | $2.68 |  | 11%
Effects of derivative settlements on average price (per Bbl) | $0.72 |  | ($0.22) |  | $0.94 |  | 427%
NGL price including the effects of derivatives (per Bbl) | $28.89 |  | $25.27 |  | $3.62 |  | 14%
Net production |  |  |  |  |  |  |
Oil (MBbls) | 864 |  | 742 |  | 122 |  | 16%
Natural gas (MMcf) | 17,531 |  | 6,519 |  | 11,012 |  | 169%
NGL (Bbls) | 703 |  | 561 |  | 142 |  | 25%
Net production (MMcfe)(1) | 26,933 |  | 14,337 |  | 12,596 |  | 88%
Average daily net production |  |  |  |  |  |  |
Oil (Bbls/d) | 9,600 |  | 8,244 |  | 1,356 |  | 16%
Natural gas (Mcf/d) | 194,789 |  | 72,429 |  | 122,360 |  | 169%
NGLs (Bbls/d) | 7,811 |  | 6,230 |  | 1,581 |  | 25%
Average daily net production (Mcfe/d)(1) | 299,256 |  | 159,300 |  | 139,956 |  | 88%

_____________
(1)Calculated by converting oil, condensate and NGLs to natural gas equivalent at a ratio of one barrel of oil or NGL to six Mcf.
(2)Based on Netherland, Sewell and Associates Inc. found at https://netherlandsewell.com/resources/pricing-data/ and EIA commodity pricing. Weighted average is based on INR’s production in a given month during the course of the calendar year.
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Revenues
Total oil, natural gas, and NGL revenues for the three months ended March 31, 2026 increased $66.5 million, or 79%, compared to the three months ended March 31, 2025. The increase was primarily driven by higher production volumes, partially offset by the effects of commodity price volatility and derivative settlements.
Net production volumes increased 88% period over period, reflecting increased development activity and a full month of production from the 241 producing wells acquired in the Antero Acquisition. Oil production increased 16%, natural gas production increased 169%, and NGL production increased 25%, driven by wells placed on production across the Company’s oil‑weighted assets in the Ohio Utica Shale and natural gas‑weighted assets in the Marcellus Shale in Pennsylvania during the second quarter of 2025 through the first quarter of 2026, as well as the contribution of assets acquired in the Antero Acquisition.
Average realized natural gas prices increased 20% compared to the prior‑year period, primarily due to higher NYMEX Henry Hub pricing and improved differentials. Average realized oil prices increased 4%, reflecting higher NYMEX WTI prices, partially offset by derivative settlements. Average realized NGL prices increased 11% due to changes in product mix and pricing dynamics. The combined impact of increased production volumes and higher realized commodity prices resulted in the significant increase in revenues compared to the prior‑year period.
Operating Expenses

| For the Three Months Ended March 31, |  | Change
| 2026 |  | 2025 |  | Amount |  | Percent
(in thousands) |  |  |  |  |  |  |
Gathering, processing, and transportation | $ | 19,723 |  | $ | 12,070 |  | $ | 7,653 |  | 63%
Lease operating | 8,916 |  | 6,772 |  | 2,144 |  | 32%
Production and ad valorem taxes | 2,349 |  | 632 |  | 1,717 |  | 272%
Midstream operations and maintenance expense | 1,478 |  | 662 |  | 816 |  | 123%
Direct operating costs | 32,466 |  | 20,136 |  | 12,330 |  | 61%
Depreciation, depletion and amortization | 35,660 |  | 21,258 |  | 14,402 |  | 68%
Total general and administrative | 21,413 |  | 131,750 |  | (110,337) |  | (84)%
Total operating expenses | $ | 89,539 |  | $ | 173,144 |  | (83,605) |  | (48)%
($ per Mcfe) |  |  |  |  |  |  |
Gathering, processing, and transportation | $ | 0.73 |  | $ | 0.84 |  | $ | (0.11) |  | (13%)
Lease operating | 0.33 |  | 0.47 |  | (0.14) |  | (30%)
Production and ad valorem taxes | 0.09 |  | 0.04 |  | 0.05 |  | 130%
Midstream operations and maintenance expense | 0.05 |  | 0.05 |  | — |  | —%
Direct operating costs | 1.20 |  | 1.40 |  | (0.20) |  | (14)%
Depreciation, depletion and amortization | 1.32 |  | 1.48 |  | (0.16) |  | (11)%
General and administrative | 0.80 |  | 9.19 |  | (8.39) |  | (91)%
Total operating expenses | $ | 3.32 |  | $ | 12.08 |  | $ | (8.75) |  | (72)%

Gathering, processing, and transportation. Gathering, processing, and transportation expense (“GP&T”) increased $7.7 million to $19.7 million for the three months ended March 31, 2026, primarily due to higher production volumes and the partial‑period contribution of acquired upstream assets from the Antero Acquisition. Although total GP&T expense increased on an absolute basis, GP&T expense per unit declined to $0.73 per Mcfe from $0.84 per Mcfe in the prior‑year period. The reduction in per‑unit GP&T expense was primarily attributable to higher production volumes and a shift in
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production mix toward the Company’s natural gas‑weighted assets in Pennsylvania, which benefit from lower gathering and processing costs and greater utilization of Company-owned gathering infrastructure compared to the Company’s wet‑gas‑weighted assets.
Lease operating. Lease operating expenses increased $2.1 million to $8.9 million for the three months ended March 31, 2026, driven primarily by higher production volumes, an increased well count from development activity, and the partial‑period contribution of wells acquired in the Antero Acquisition. On a per‑unit basis, lease operating expense declined to $0.33 per Mcfe from $0.47 per Mcfe in the prior‑year period, reflecting improved cost efficiency and dilution of fixed and semi‑variable costs across higher production volumes, particularly in the Company’s Marcellus assets.
Production and ad valorem taxes. Production and ad valorem taxes increased $1.7 million to $2.3 million for the three months ended March 31, 2026, primarily due to higher production volumes and the addition of acquired properties.
Midstream Operations and Maintenance Expense. Midstream operations and maintenance expense increased $0.8 million to $1.5 million for the three months ended March 31, 2026, primarily reflecting the addition of acquired midstream assets in connection with the Antero Acquisition and higher throughput volumes during the period. On a per‑unit basis, midstream operating expenses remained generally consistent with the prior‑year period, as increased operating activity and integration‑related costs were largely offset by higher volumes and improved utilization of the acquired midstream assets.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $14.4 million to $35.7 million for the three months ended March 31, 2026, primarily due to higher production volumes and the partial‑period contribution of acquired assets from the Antero Acquisition. On a per‑unit basis, DD&A declined to $1.32 per Mcfe from $1.48 per Mcfe in the prior‑year period, reflecting increased production volumes and the effect of spreading the depreciable base over a larger production base.
General and Administrative Expenses. General and administrative expense decreased $110.3 million to $21.4 million for the three months ended March 31, 2026, compared to the prior‑year period. The decrease was primarily attributable to the absence of $126.1 million of non‑recurring, non‑cash stock‑based compensation expense related to the Company’s IPO recognized in the prior‑year period, partially offset by transaction costs associated with the Antero Acquisition of $13.5 million.
Net Gain (Loss) on Derivative Instruments. The following table presents gains and losses on our derivative instruments for the periods indicated:

| Three Months Ended March 31,
| 2026 |  | 2025
(in thousands) |  |  |
Realized cash settlement gains (losses) | $ | (17,992) |  | $ | (3,585)
Non-cash mark-to-market derivative gain (losses) | (47,142) |  | (33,633)
Total | $ | (65,134) |  | $ | (37,218)

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 debt and 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, such as the Preferred Stock Transaction and the Notes offering, 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. During the three months ended March 31, 2026, we incurred $111.5 million of capital expenditures on development activities and $11.1 million related to land activities. Our development capital budget for 2026 is $450 million to $500 million, which includes drilling and completions and midstream capital expenditures. We funded our capital expenditures for the three months ended March 31,
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2026 from cash flows from operations, borrowings incurred under the Credit Facility and net proceeds from capital market activities. We expect to fund our 2026 capital expenditures budget through a combination of cash flows from operations and additional borrowings under the Credit Facility, as well as the proceeds of the Preferred Stock Transaction and the Notes offering. 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 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.
On March 20, 2026, the Company completed the offering of the Notes for total net proceeds of $537.6 million. The proceeds from the issuance of the Notes were used to repay outstanding borrowings under our Credit Facility and for other general corporate purposes.
On February 23, 2026, we closed the Antero Acquisition for consideration of approximately $683.9 million net to Infinity. We funded the transaction with cash on hand, the proceeds of the Preferred Stock Transaction and borrowings under our Credit Facility, the borrowing base and aggregate elected commitment amount of which increased from $375.0 million to $875.0 million in connection with closing.
In connection with the closing of the Antero Acquisition, we also completed the Preferred Stock Transaction, which generated gross proceeds of $350 million and net proceeds of $334.0 million after deducting placement agent fees and offering expenses. The Series A Preferred Stock provides long‑term capital with no stated maturity; however, it accrues cumulative dividends that may be paid in kind for a limited period, after which dividends must be paid in cash, subject to restrictions under our Credit Facility. Any dividends paid in kind increase the liquidation preference of the Series A Preferred Stock and may increase future cash requirements. We believe the Preferred Stock Transaction enhances our overall liquidity and financial flexibility while supporting the execution of our development and acquisition strategy.
Our liquidity requirements also include operating expenses, which have been impacted by elevated levels of inflation. High oil prices have historically led to more development activity in oil-focused shale basins and resulted in service cost inflation across all U.S. shale basins, including our areas of operation. Ongoing inflationary pressures may result in increases to the costs of our oilfield goods, services and personnel, which would, in turn, cause our capital expenditures and operating costs to rise. We closely monitor costs and are cost conscious in managing our operations. We may solicit bids from multiple vendors or contractors or source materials from multiple suppliers to take advantage of cost competition, and we may buy surplus materials if we can acquire them on attractive terms. Where we anticipate elevated costs may be more sustained, such as in the cost of services, we may enter into contracts with certain service providers to lock in rates. We are also strategic in the duration of our contracts to provide flexibility to take advantage of cost declines when they occur.
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
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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,
| 2026 |  | 2025 |  |
(in thousands) |  |  |  |  |
Net cash provided by operating activities | $ | 58,427 |  | $ | 74,229 |  |
Net cash used in investing activities | (698,912) |  | (108,431) |  |
Net cash provided by financing activities | 710,619 |  | 36,858 |  |
Net increase in cash and cash equivalents | $ | 70,134 |  | $ | 2,656 |  |

Analysis of Cash Flow Changes Between the Three Months Ended March 31, 2026 and 2025
Operating activities
For the three months ended March 31, 2026, we generated $58.4 million of cash from operating activities, a decrease of $15.8 million from the prior period. Cash provided by operating activities decreased modestly compared to the prior-year period primarily due to integration-related costs associated with the Antero Acquisition, partially offset by higher production volumes. 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
For the three months ended March 31, 2026, we spent $75.6 million on capital expenditures in connection with our development activities. We also spent $0.8 million on other property and equipment largely related to midstream activities. In connection with the Antero Acquisition, we spent $622.5 million on certain upstream oil and gas properties and related midstream assets.
For the three months ended March 31, 2025, we spent $105.6 million on capital expenditures in connection with our development activities. We also spent $2.8 million on other property and equipment.
Financing activities
For the three months ended March 31, 2026, the change in financing activity was primarily related to proceeds received from the issuance of the Notes and Series A Preferred Stock of $550.0 million and $350.0 million, respectively. We incurred issuance-related costs of $9.6 million and $14.4 million in connection with the issuance of the Notes and the Series A Preferred Stock, respectively. We also had debt issuance payments associated with the increase in the borrowing base and elected commitments of the Credit Facility of $13.3 million. We made borrowings under the Credit Facility of $430.5 million during the period. We used funds from the financing activities, along with cash from operating activities to pay down borrowings under the Credit Facility of $550.0 million since the beginning of the year.
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.
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,
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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 pay 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 8 – Derivatives and Risk Management for more information on our derivative activities.
Changes in the fair value of derivative contracts from December 31, 2025 to March 31, 2026, are presented below:

(in thousands) | Commodity Derivative Liability
Net fair value of oil and gas derivative contracts outstanding as of December 31, 2025 | $ | 23,256
Commodity hedge contract settlement payments, net of any receipts | 17,992
Cash and non-cash mark-to-market losses on commodity hedge contracts (1) | (65,134)
Net fair value of oil and gas derivative contracts outstanding as of March 31, 2026 | $ | (23,886)

_____________
(1)At inception, new derivative contracts entered into by us have no intrinsic value.
Financing Agreements
Senior Notes
On March 20, 2026, INR Holdings issued $550.0 million aggregate principal amount of the Notes at par. The Notes were issued pursuant to the Indenture and bear interest at a fixed rate of 7.625% per annum, payable semi-annually in arrears on April 1 and October 1 of each year, commencing on October 1, 2026. The Notes will mature on April 1, 2031, unless earlier redeemed or repurchased.
The Notes are the general unsecured, senior obligations of INR Holdings. The Notes are guaranteed on a senior unsecured basis by the Guarantors and may be guaranteed by certain future subsidiaries of INR Holdings. The Notes and the related guarantees rank equally in right of payment with the borrowings under our Credit Facility and any of our other future senior indebtedness and senior to any of our future subordinated indebtedness. The Notes and the guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our Credit Facility) to the extent of the value of the collateral securing such indebtedness and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the Notes.
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INR Holdings may, at its option, redeem all or a portion of the Notes at any time on or after April 1, 2028 at certain redemption prices. At any time prior to April 1, 2028, INR Holdings may redeem up to 40% of the aggregate principal amount of the Notes, with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 107.625% of the aggregate principal amount of the Notes redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. In addition, at any time prior to April 1, 2028, INR Holdings may, on any one or more occasions, redeem all or a part of the Notes at a redemption price equal to 100.00% of the principal amount of the Notes redeemed, plus a “make whole” premium and accrued and unpaid interest, if any, to, but excluding, the date of redemption.
If INR Holdings experiences certain kinds of changes of control, each holder of the Notes may require INR Holdings to repurchase all or a portion of its Notes for cash at a price equal to 101% of the aggregate principal amount of such Notes, plus accrued and unpaid interest, if any, to the date of repurchase.
The Indenture contains covenants that, among other things and subject to certain exceptions and qualifications, limit the ability of INR Holdings and its restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from its restricted subsidiaries to INR Holdings or any of their restricted subsidiaries; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
Credit Facility
On September 25, 2024, INR Holdings entered into a credit facility led by Citibank, N.A. (the “Credit Facility” and the credit agreement governing the Credit Facility, as amended, the “Credit Agreement”). The Credit Facility has a total facility size of $1.5 billion, subject to lender commitments and borrowing base limitations. On February 23, 2026, in connection with the closing of the Antero Acquisition, we amended our Credit Facility to, among other things, increase the aggregate elected commitment amount from $375.0 million to $875.0 million and increase the borrowing base from $375.0 million to $875.0 million. As of March 31, 2026, our elected commitments and borrowing base were $875.0 million of which zero was outstanding with $19.2 million in letters of credit.
The Credit Facility also requires INR Holdings 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 Credit Facility described above through the date these unaudited condensed consolidated financial statements were available to be issued.
For the three months ended March 31, 2026 and 2025, total interest expense on the Credit Facility was $4.4 million and $2.6 million, respectively. The Company capitalized $0.1 million of interest expense during the three months ended March 31, 2026 and did not capitalize any interest expense during the same period in 2025. For the three months ended March 31, 2026 and 2025, the Company’s weighted-average interest rate was 6.9% and 5.2%, 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 2025 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.
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Contractual Obligations and Commitments
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, 2025, there have not been any significant, non-routine changes in our contractual obligations other than drilling rig contracts and the firm transportation agreement entered into as discussed in Note 16 – 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 2025 Form 10-K.
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. Based on our production for the three months ended March 31, 2026, our oil, natural gas and NGL sales for the three months ended March 31, 2026 would have moved up or down $5.7 million for each 10% change in oil prices per Bbl, $7.4 million for each 10% change in gas prices per Mcf, and $2.0 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 90% of our reasonably anticipated, projected production from proved properties. “Item 1A. Risk Factors” in the 2025 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, 2026, we had three 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, 2026, our reserves supported a $875.0 million credit facility of which zero in borrowings was outstanding with $19.2 million in letters of credit, leaving $855.8 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, 2025 and 2026, variable-rate debt, annual interest expense on variable-rate debt would increase by approximately $0.1 million and zero, 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 2025 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, 2026 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 2025 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
Recent Sales of Unregistered Equity Securities
None.
Issuer Purchases of Equity Securities
We did not repurchase any equity securities registered under Section 12 of the Exchange Act during the first quarter of 2026.
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 quarter ended March 31, 2026, 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
2.1† |  | Purchase and Sale Agreement, dated as of December 5, 2025, by and among Antero Resources Corporation, Antero Minerals LLC and Monroe Pipeline LLC, as sellers, and Infinity Natural Resources, LLC and Northern Oil and Gas, Inc., as buyers. |  | 8-K |  | 2.1 |  | December 8, 2025
2.2† |  | Purchase and Sale Agreement, dated as of December 5, 2025, by and among Antero Midstream LLC, Antero Water LLC and Antero Treatment LLC, as sellers, and Infinity Natural Resources, LLC and Northern Oil and Gas, Inc., as buyers. |  | 8-K |  | 2.2 |  | December 8, 2025
2.3† |  | Amendment No. 1 to the Purchase and Sale Agreement, dated as of February 22, 2026, by and among Antero Resources Corporation, Antero Minerals LLC and Monroe Pipeline LLC, as sellers, and Infinity Natural Resources, LLC and Northern Oil and Gas, Inc., as buyers. |  | 8-K |  | 2.3 |  | February 23, 2026
2.4† |  | Amendment No. 1 to the Purchase and Sale Agreement, dated as of February 22, 2026, by and among Antero Midstream LLC, Antero Water LLC and Antero Treatment LLC, as sellers, and Infinity Natural Resources, LLC and Northern Oil and Gas, Inc., as buyers. |  | 8-K |  | 2.4 |  | February 23, 2026
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
3.3 |  | Certificate of Designation of Series A Convertible Preferred Stock of Infinity Natural Resources, Inc., as filed with the Secretary of State of the State of Delaware on February 23, 2026. |  | 8-K |  | 3.1 |  | February 23, 2026
4.1 |  | Registration Rights Agreement, dated February 23, 2026, by and among the Company and each of the other signatories from time to time party thereto. |  | 8-K |  | 4.1 |  | February 23, 2026
4.2†† |  | Indenture, dated as of March 20, 2026, by and among Infinity Natural Resources, LLC, the Guarantors named therein and U.S. Bank Trust Company, National Association, as trustee. |  | 8-K |  | 4.1 |  | March 23, 2026
4.3 |  | Form of 7.625% Senior Notes due 2031 (included as Exhibit A in Exhibit 4.2 hereto). |  | 8-K |  | 4.2 |  | March 23, 2026
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 |  | Amendment No. 1 to the Second Amended and Restated Limited Liability Company Agreement of Infinity Natural Resources, LLC, dated as of February 23, 2026. |  | 8-K |  | 10.2 |  | February 23, 2026
10.3 |  | Fourth Amendment to Credit Agreement, dated as of February 23, 2026, 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 |  | 10.3 |  | February 23, 2026
10.4 |  | Securities Purchase Agreement, by and among Infinity Natural Resources, Inc., INR (II) Investments, LLC and Etineles Holdings V, LLC, dated as of February 18, 2026. |  | 8-K |  | 10.1 |  | February 23, 2026
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. |  |  |  |  |  |

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101* |  | The following financial information from this Quarterly Report on Form 10-Q of Infinity Natural Resources, Inc. for the quarter ended March 31, 2026 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) Equity / 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). |  |  |  |  |  |

_____________

* | Filed herewith.
** | Furnished herewith.
† | 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.
†† | Certain personally identifiable information has been omitted from this exhibit pursuant to Item 601(a)(6) of Regulation S-K.
+ | 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.

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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 Quarterly Report to be signed on its behalf by the undersigned, thereunto duly authorized.

| INFINITY NATURAL RESOURCES, INC.
Date: May 12, 2026 | 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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