Infinity Natural Resources (INR) 424B4 Prospectus supplement with pricing info

Filed pursuant to Rule 424(b)(4)
Registration No. 333-282502

13,250,000 Shares

Infinity Natural Resources, Inc.

Class A Common Stock

This is the initial public offering of the Class A common stock of Infinity Natural Resources, Inc., a Delaware corporation (the “initial public offering”). We are offering 13,250,000 shares of our Class A common stock. Prior to this offering, there has been no public market for our Class A common stock.

We have been approved to list our Class A common stock on the New York Stock Exchange under the symbol “INR.”

The initial public offering price per share of the Class A common stock is $20.00.

Holders of shares of our Class A common stock and Class B common stock are entitled to one vote for each share of Class A common stock and Class B common stock, respectively, held of record on all matters on which stockholders are entitled to vote generally. See “Description of Capital Stock.”

Investing in our Class A common stock involves risks, including those described under “Risk Factors” beginning on page 31 of this prospectus.

	Per share		Total
Price to the public	$	20.00	$	265,000,000
Underwriting discounts and commissions(1)	$	1.20	$	15,900,000
Proceeds to us (before expenses)	$	18.80	$	249,100,000

⁽¹⁾  We refer you to “Underwriting (Conflicts of Interest)” beginning on page 173 of this prospectus for additional information regarding underwriting compensation.

At our request, the underwriters have reserved up to 5% of the shares of common stock offered by this prospectus for sale, at the initial public offering price, to certain individuals associated with us. See “Underwriting (Conflicts of Interest)—Directed Share Program.”

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. “Risk Factors” and “Prospectus Summary—Emerging Growth Company Status” contain additional information about our status as an emerging growth company.

We have granted the underwriters the option to purchase up to 1,987,500 additional shares of Class A common stock on the same terms and conditions set forth above within 30 days from the date of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares on or about February 3, 2025.

Joint Book-Running Managers

CITIGROUP RAYMOND JAMES RBC CAPITAL MARKETS

BOFA SECURITIES CAPITAL ONE SECURITIES TRUIST SECURITIES

Senior Co-Managers

KEYBANC CAPITAL MARKETS STEPHENS INC.

Co-Managers

COMERICA SECURITIES FIFTH THIRD SECURITIES FIRST CITIZENS CAPITAL SECURITIES BTIG

Junior Co-Managers

BOK FINANCIAL SECURITIES, INC. ZIONS CAPITAL MARKETS

Prospectus dated January 30, 2025

TABLE OF CONTENTS

	Page
Commonly Used Defined Terms		ii
Glossary of Oil and Natural Gas Terms		iv
Presentation of Financial and Operating Data		vii
Industry and Market Data		vii
Trademarks and Trade Names		vii
Prospectus Summary		1
Risk Factors		31
Cautionary Statement Regarding Forward-Looking Statements		70
Use of Proceeds		72
Dividend Policy		73
Capitalization		74
Dilution		75
Management’s Discussion and Analysis of Financial Condition and Results of Operations		77
Business		104
Management		133
Executive Compensation		139
Security Ownership of Certain Beneficial Owners and Management		146
Corporate Reorganization		148
Certain Relationships and Related Party Transactions		154
Description of Capital Stock		157
Shares Eligible for Future Sale		164
Material U.S. Federal Income Tax Considerations for Non-U.S. Holders		166
Underwriting (Conflicts of Interest)		171
Legal Matters		177
Experts		178
Where You Can Find More Information		179
Index to Financial Statements		F-1

Neither we nor the underwriters have authorized anyone to provide you with any information or to make any representations other than those contained in this prospectus, any amendment or supplement to this prospectus or in any free writing prospectus prepared by us or on our behalf. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any information other than the information in this prospectus and any free writing prospectus prepared by us or on our behalf. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since such dates. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

Through and including February 24, 2025 (the 25th day after the date of this prospectus), all dealers effecting transactions in our shares, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” contain additional information regarding these risks.

i

COMMONLY USED DEFINED TERMS

As used in this prospectus, unless the context indicates or otherwise requires, the terms listed below have the following meanings:

• “Appalachia-Focused Public Peers” refers to the public companies operating in 2023 with the following ticker symbols: AR, CHK, CNX, EQT, GPOR, RRC, and SWN. For the avoidance of doubt, this does not reflect the merger of CHK and SWN, effective October 1, 2024;

• “Block Island” refers to Block Island Minerals LLC, a subsidiary of INR Holdings;

• “Carroll County Acquisition” refers to INR’s acquisition of the Warrior North field from PennEnergy Resources, Inc. in April 2021 for $32 million;

• “Cheat Mountain” refers to Cheat Mountain Resources, LLC, a subsidiary of INR Holdings;

• “Credit Agreement” refers to that certain Credit Agreement, dated September 25, 2024, by and among INR Holdings, the lenders from time to time party thereto and Citibank, N.A., as the administrative agent and an issuing bank;

• “Credit Facility” refers to the revolving credit facility provided under our Credit Agreement;

• “DROI” refers to Discounted Return on Investment, which we define as the present value at a 10% discount rate of future net cashflows excluding capital expenditures divided by the net capital expenditures associated with the development of a horizontal well;

• “Enverus” means Enverus, Inc., a database with which we have a fee-based subscription agreement for access to real-time information related to global oil and gas data, analytics and forecasting. Data on the Enverus system covers worldwide exploration, production and general midstream energy company information which we retrieve and then synthesize to generate charts and tables based on such data, such as the charts on pages 4, 5, 6, 107 and 108 of this registration statement;

• “Existing Owners” refers, collectively, to Pearl, NGP, certain other co-investors and the management members that directly and indirectly own equity interests in INR Holdings or its wholly owned subsidiaries prior to, as of and following the completion of our corporate reorganization;

• “INR Holdings” refers to Infinity Natural Resources, LLC, a Delaware limited liability company, and the entity that holds the Company’s operating entities;

• “INR Holdings LLC Agreement” refers to the second amended and restated limited liability company agreement of INR Holdings;

• “Infinity Natural Resources,” “Infinity,” “INR,” the “Company,” “we,” “our,” “us” or like terms refer collectively to Infinity Natural Resources, Inc. and its consolidated subsidiaries;

• “INR Ohio” refers to INR Ohio, LLC, a subsidiary of INR Holdings that, after its merger with Wolf Run, holds the assets acquired in the Utica Resource Acquisition;

• “INR Midstream” refers to INR Midstream, LLC, a subsidiary of INR Holdings;

• “INR Operating” refers to INR Operating, LLC, a subsidiary of INR Holdings;

• “INR Unit Holder” refers to a holder of INR Units (other than INR) and a corresponding number of shares of Class B common stock of INR;

• “INR Units” refers to units representing limited liability company interests in INR Holdings issued pursuant to the INR Holdings LLC Agreement, which shall only be held along with a corresponding number of shares of Class B common stock of INR;

• “IRR” refers to “Internal Rate of Return,” which we define as the discount rate that makes the net present value of all future cash flow equal to zero;

• “Liquids-Focused Public Peers” refers to the public companies with the following ticker symbols: FANG, DVN, CTRA, OVV, PR, CIVI, MTDR, SM, VTLE, REI, CHRD, MGY, MUR, CRC, NOG, and BRY;

ii

• “LLC Interests” refers to the limited liability company interests of INR Holdings;

• “NGP” refers to a family of private equity funds managed by NGP Energy Capital Management, L.L.C., including NGP XI US Holdings, L.P.;

• “Pearl” refers to Pearl Energy Investments, L.P., PEI INR Holdings, L.P., Pearl Energy Investments III, L.P., PEI Infinity-S, LP, PEI INR Co-Invest-B Corp and their affiliates;

• “PEO Ohio” refers to PEO Ohio, LLC;

• “PEO Ohio Acquisition” refers to Infinity’s acquisition of assets from PEO Ohio in October 2023;

• “Prior Credit Facility” refers to the amended and restated credit agreement of INR Holdings;

• “Utica Resource Acquisition” refers to Infinity’s acquisition of the assets of Utica Resource Ventures in October 2023;

• “Utica Resource Ventures” refers to Utica Resource Ventures, LLC; and

• “Wolf Run” refers to Wolf Run Operating, LLC, a subsidiary of INR Holdings that holds the assets acquired in the Utica Resource Acquisition.

iii

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:

• “Appalachian Basin” means the area of the United States composed of those portions of West Virginia, Pennsylvania, Ohio, Maryland, Kentucky, New York, Tennessee and Virginia that lie in amongst Appalachian Mountains;

• “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;

• “Capital Efficiency Ratio” means Adjusted EBITDAX per unit of production divided by finding and development costs (“F&D”) per Boe. F&D is calculated by dividing total costs incurred (which includes the total acquisition, exploration and development costs incurred during the period related to the specified property or group of properties) by the sum of the extensions, discoveries, additions, revisions, and purchases during that period;

• “CO₂” means carbon dioxide;

• “CO₂e” means carbon dioxide equivalent;

• “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;

• “D&C” means drilling and completion;

• “dragalong right” means a contractual arrangement that provides (i) if multiple parties own interests in the same or related properties, and (ii) if one owner elects to sell its interest to a third party, then the selling owner has the right to force the other owners to sell all or a pro rata portion of the other owners’ interests in the applicable properties to the third party purchaser on the same terms and conditions as the selling owner’s transaction;

• “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 “Business—Our Operations—Reserve Data and Presentation”;

• “estimated ultimate recovery” or “EUR” means the sum of the economic life of reserves remaining as of a given date and cumulative production as of that date. As used in this prospectus, EUR includes only proved reserves and is based on Wright’s reserve estimates;

• “FERC” means the Federal Energy Regulatory Commission;

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• “field” means an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations;

• “formation” means a layer of rock which has distinct characteristics that differs from nearby rock;

• “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;

• “HBP” means held-by-production;

• “hedging” means the use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility;

• “held-by-storage” means leasehold held through a declared storage field, injection well, or simply held by storage rights;

• “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;

• “IP 30” means the cumulative production generated by a well over the first thirty producing days divided by thirty;

• “IP 90” means the cumulative production generated by a well over the first ninety producing days divided by ninety; for the month in which the 90^th producing day occurs, an average daily production is used for any remaining days in that month to get to ninety producing days;

• “LNG” means liquified natural gas;

• “lower 48” means the continental United States, excluding Alaska and Hawaii;

• “MBoe” means one thousand barrels of oil equivalent;

• “MBoe/d” means one thousand barrels of oil equivalent per day;

• “Mcf” means one standard thousand cubic feet of natural gas;

• “Mcfe” means one standard thousand cubic feet of natural gas equivalent;

• “MMBoe” means one million barrels of oil equivalent;

• “MMBbl” means one million barrels of crude oil, condensate or NGLs;

• “MMBtu” means one million British thermal units;

• “MMBtu/d” means one MMBtu per day;

• “MMcf” means one million standard cubic feet of natural gas;

• “MMcf/d” means one million standard cubic feet of natural gas 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;

• “netbacks” means the total revenues generated from a well less the cash operating expenses incurred by the well;

• “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;

v

• “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” reserves that can be expected to be recovered through existing wells with existing equipment and operating methods but are not yet producing;

• “proved developed producing reserves” or “PDP” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, according to the Securities and Exchange Commission or Society of Petroleum Engineers definitions of proved reserves;

• “proved reserves” means the summation of reserves within the PDP, PDNP and PUD reservoir categories;

• “proved undeveloped reserves” or “PUDs” means proved reserves that are expected to be recovered from undrilled well locations on existing acreage or from existing wells where a relatively major expenditure is required for recompletion within the five-year development window, according to the Securities and Exchange Commission or Society of Petroleum Engineers definition of PUD;

• “recompletion” means the process of re-entering an existing wellbore and mechanically reinvigorating the wellbore to establish or increase existing production and reserves;

• “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;

• “spacing” means the footage between wellbores;

• “statutory unitization” means the process prescribed by Ohio Revised Code Section 1509.28, by which an applicant (typically an operator) may seek to combine mineral rights from individual tracts of land to form a drilling unit to efficiently and effectively develop the oil and gas resources beneath those tracts. Statutory unitization is available when the owners of sixty-five percent of the land overlying a pool (or part of a pool) of oil and gas apply to the Ohio Department of Natural Resources Division of Oil and Gas Resources Management to operate the pool (or part of a pool) as a drilling unit;

• “undeveloped acreage” means acreage under lease on which wells have not been drilled or completed;

• “unit” means the joining of all or substantially all interests in a specific reservoir or field, rather than a single tract, to provide for development and operation without regard to separate mineral interests. Also, the area covered by a unitization agreement;

• “wellbore” or “well” means a drilled hole that is equipped for the production of hydrocarbons;

• “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;

• “working interest” means the right granted to the lessee of a property to explore for and to produce and own 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.

vi

PRESENTATION OF FINANCIAL AND OPERATING DATA

The summary historical consolidated financial information presented in this prospectus is that of our accounting predecessor, Infinity Natural Resources, LLC. The summary unaudited pro forma data presented gives pro forma effect to the Utica Resource Acquisition and the PEO Ohio Acquisition, as indicated herein. Unless otherwise indicated, the financial and operational data in this prospectus is presented on a pro forma basis to reflect our results, the results of the acquired Utica Resource Ventures and PEO Ohio assets on a combined basis. Please see “Corporate Reorganization” and the unaudited pro forma condensed consolidated financial statements and the related notes to those financial statements included elsewhere in this prospectus.

INDUSTRY AND MARKET DATA

The market data and certain other statistical information included in this prospectus are based on a variety of sources, including independent industry publications, government publications and other published independent sources. Some data is also based on our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that these third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involves risks and uncertainties and is subject to change based on various factors, including those discussed under the headings “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” in this prospectus.

TRADEMARKS AND TRADE NAMES

This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensor to these trademarks, service marks and trade names.

vii

PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read this entire prospectus and other referenced documents before making an investment decision, including the sections titled “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements and the related notes to those financial statements contained elsewhere in this prospectus.

Unless otherwise indicated, the information presented in this prospectus assumes that the underwriters’ option to purchase additional shares of our common stock is not exercised. Unless otherwise indicated, the estimated reserve information presented in this prospectus was prepared by our independent reserve engineer as of December 31, 2023 based on the U.S. Securities and Exchange Commission’s (the “SEC”) reserve pricing rule as more fully described in “—Reserve and Operating Data,” and is presented as of the dates and for the periods indicated. References in this prospectus to “INR,” the “Company,” “we,” “us,” “our” and like terms are to Infinity Natural Resources, Inc., a Delaware corporation, and its wholly owned subsidiaries, unless the context otherwise requires or we otherwise state. Certain operational terms used in this prospectus are defined in the “Commonly Used Defined Terms” and “Glossary of Oil and Natural Gas Terms.”

Our Company

We are a growth oriented, free cash flow generating, independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible balance sheet. Additionally, we have proven our ability to grow our acreage position through organic leasing efforts and accretive acquisitions. We are an early mover into the core of the Utica Shale’s volatile oil window in eastern Ohio as well as the emerging dry gas Utica Shale in southwestern Pennsylvania. Our Marcellus Shale development overlays our deep dry gas Utica assets in Pennsylvania, providing highly economic stacked development inventory that leverages the same company-owned midstream infrastructure. We have amassed approximately 93,000 net surface acres with exposure to the core of these plays providing us a unique and balanced portfolio of high-return oil and natural gas drilling locations. This balance allows us to optimize our development plan across our portfolio to capitalize on changes in commodity pricing over time.

We believe our technical and managerial expertise allow us to execute our strategies and deliver industry leading results. Our expertise is bolstered by the continuity of our core team, which has worked together for a decade. Since our initial acquisition in southwestern Pennsylvania in March 2018, we have drilled 47 wells and increased our operated horizontal well count from 2 to 131 with an additional two PDNP wells and seven DUCs, as of December 31, 2024. In total, we have increased our net daily production from virtually zero at the beginning of 2021 to 25 Mboe/d (29% oil and 49% liquids) for the quarter ended September 30, 2024. Since quarter end, we have placed an additional seven operated Ohio Utica wells into sales representing approximately 96,000 lateral feet.

1

The following chart shows our average net daily production by area for each quarter since bringing our first horizontal wells online in January 2021:

As of December 31, 2023, our total estimated proved reserves were 141,587 MBoe with 48% proved developed and 22% oil, 18% NGLs and 60% natural gas. As of December 31, 2024, our total drilling inventory consisted of 333 gross horizontal drilling locations (73 proved locations and 260 unproved locations), two PDNP wells and seven DUCs. Our drilling inventory represents 4.6 million lateral feet, implying 19 years of inventory at our current drilling pace of approximately 18 wells per year. Approximately 85% of our acreage is HBP, held by operations or held-by-storage, meaning we maintain development flexibility and have limited obligations to access our current inventory.

The following table provides a summary of our approximate net acreage, gross drilling locations, net producing wells and lateral footage as of December 31, 2024 separated by shale (including acreage prospective for dual-zone development):

	As of December 31, 2024
	Net Horizon Acres(1)		Operated Producing Wells (#)		Operated Lateral Footage (in thousands)		Development Drilling Locations (#)			Development Lateral Footage (in thousands)		Development Average Well Lateral Length
Utica Shale Oil (OH)		62,702		118		954		158	(3)		2,109		13,349	'
Marcellus Shale Dry Gas (PA)(2)		30,305		13		126		118	(4)		1,715		14,532	'
Utica Shale Deep Dry Gas (PA)(2)		30,029		—		—		66			594		9,000	'(5)

(1) Does not include 12,605 net acres located in the Marcellus Shale in Ohio that is not part of our development plan.

(2) The acreage in this table reflects net horizon acres. Substantially all of our surface acreage in Pennsylvania is prospective for both the Utica and Marcellus Shales for dual-zone development. As a result, most of our net surface acres represent one horizon acre for the Utica Shale and one horizon acre for the Marcellus Shale. Our total net surface acreage irrespective of dual-zone development was 93,127 net acres and our total horizon acres were 123,036. See “Business—Our Operations—Acreage as of December 31, 2023” for information regarding our undeveloped and developed surface acreage.

(3) Includes two PDNP wells and two DUCs.

(4) Includes five DUCs.

(5) Utica Shale Deep Dry Gas (PA) land picture supports 14,000+ foot laterals.

Our oil volumes provide us with a unique advantage compared with many of our Appalachian Basin peers. Since our initial entry into the Utica Shale’s volatile oil window in April 2021, we have increased our oil production from less than approximately 300 Bbls/d to approximately 7,110 Bbls/d for the quarter ended September 30, 2024. The increase in our oil volumes is due to a combination of strategic acquisitions and organic development of our assets by placing into sales 22 wells during that period. We have also placed an additional seven operated

2

Ohio Utica wells into sales (approximately 96,000 lateral feet) since quarter end. We believe that the oil component of our production provides greater revenue per Boe resulting in higher operating margins compared to our natural gas focused public peers in the Appalachian Basin.

The following chart shows our average net daily oil production for each quarter by county in Ohio since April 2021:

Our Properties

Utica Shale Oil – Ohio

Given recent strength in the price of oil, our current activities are focused on developing our Ohio properties which are centered in the volatile oil window of the Utica Shale. Early commercial development of the Ohio Utica began principally in 2011 and has delineated bands of black oil, volatile oil, rich gas, and dry gas. Since 2019 through December 19, 2024, 322 wells have been drilled in the play, delineating the core of the play located in Carroll, Tuscarawas, Harrison, Guernsey, Noble, Muskingum and Morgan counties. Since January 2021 through September 2024, there have been 208 wells drilled that have been producing for over 90 days with an average IP 90 of 930 barrels of oil per day normalized to a 15,000’ lateral making the volatile oil window one of the leading oil resource plays in the lower 48 (compared to an average IP 90 of 1,098 barrels of oil per day per well normalized to 15,000’ lateral for our drilled Ohio Utica wells). When combined with the play’s low operating costs, low water production and low drilling costs, the Utica’s volatile oil window maintains one of the lowest breakeven costs amongst all oil resource plays in the United States.

We first acquired our properties in the volatile oil window of the Utica Shale in Ohio in April 2021 through our Carroll County Acquisition. Since that time, we have acquired 3,715 additional acres in Carroll County in close proximity to our existing assets through our organic leasing efforts that have added or extended 25 operated locations. In October 2023, we acquired assets from Utica Resource Ventures and PEO Ohio, including approximately 39,185 net acres, further expanding our operations in the core of the play. Since our acquisition, we have drilled 14 wells on the acquired acreage, 11 of which have been turned into sales and another one of which is PDNP. In February 2024, we were awarded the nomination for approximately 5,705 net acres within Salt Fork State Park in Guernsey County Ohio, adding over 23 locations averaging over 15,500 lateral feet per well to our inventory. On October 4, 2024, we entered into a lease with Muskingum Watershed Conservancy

3

District for approximately 1,900 acres in Guernsey and Noble Counties, Ohio, representing 19 new or enhanced (which includes increased working interest or longer lateral length) drilling locations. Our understanding of geology, technical expertise and local presence gave us early insight into the quality of the play which led us to amass approximately 62,000 net surface acres with 154 identified horizontal drilling locations, two PDNP wells and two DUCs representing over 2 million lateral feet and nine years of drilling inventory based on our current one-rig program. We intend to operate 100% of our future drilling locations. As of December 31, 2024, we have 118 operated producing wells, two PDNP wells and two DUCs. Approximately 40,000 of our net surface acres in the Utica Shale in Ohio are located in Guernsey and Carroll counties of eastern Ohio, which, according to Enverus, have demonstrated among the highest oil production in the volatile oil window and are competitive with some of the best oil producing counties in the lower 48.

The following chart shows the average first 12-months production in MBbls for wells drilled in the volatile oil window of Ohio compared to the top oil producing counties in the lower 48:

Source: Enverus.

Our management team has developed efficiencies and adopted procedures to enhance well performance and economics for the volatile oil window. Initial entrants did not have the benefit of current directional drilling technology or modern rig specifications to increase lateral lengths and ensure lateral placement in a progressively refined window. Early completions designs were sub-optimal and many operators used linear and cross linked gel that damaged the formation and reduced permeability which adversely impacted production rates. Our designs utilize enhanced completion fluids that allow for the placement of large proppant loads without reducing fracture permeability, which has resulted in some of the most productive development in the history of the play.

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To date, we have drilled the top eight, and 15 of the top 25, wells drilled in Carroll County since 2021 based on IP 90 of barrels of oil per day normalized to a 15,000’ lateral as shown in the following chart.

Source: Enverus.

The characteristics that have contributed to our well performance include:

• improved wellbore targeting and placement accuracy in a tighter window in the lower zone of the Utica / Point Pleasant play;

• increasing average lateral lengths;

• optimized size and intensity of proppant and fluid pumped per lateral foot;

• optimized completion fluid chemistry and composition;

• optimized fracture stage lengths and cluster spacing;

• improved management of production rates to preserve downhole pressure; and

• improved adjustment of well spacing and development patterns.

5

Successful implementation of these measures has resulted in leading well performance relative to that of other major operators⁽¹⁾ in Carroll County since 2021 through October 2024 as seen in the chart below.

(1) Represents all INR drilled Carroll County wells.

(2) Peers include EOG Resources, Inc. (“EOG”) and Encino Energy LLC (“Encino”).

(3) Represents the average cumulative production of the wells drilled on each respective pad.

Source: Enverus.

Marcellus Shale Dry Gas and Utica Deep Dry Gas – Pennsylvania

Our Pennsylvania properties, which we initially acquired in March 2018, are predominately located to the northeast of Pittsburgh in Westmoreland, Armstrong and Indiana counties. We have expanded our leasehold position through a series of subsequent acquisitions and today have approximately 31,000 net surface acres with exposure to both Marcellus and Utica Shales and operate 13 producing horizontal wells and five DUCs. We maintain an inventory of 113 and 66 undeveloped Marcellus and Utica locations in Pennsylvania, respectively, representing approximately a decade of drilling inventory based on a one-rig drilling program. We intend to operate 100% of our future drilling locations and over 98% of our acreage is HBP or held-by-storage.

Marcellus Shale Dry Gas

Development of the Marcellus Shale initially began in the historic core in Washington and Greene counties in Pennsylvania. Outside that area, the acreage ownership remained fragmented, which resulted in slower upstream and midstream development despite attractive geology. Today, we have the opportunity to apply

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modern technology to this area of historic underdevelopment and generate not only attractive return potential, but also operational flexibility. We have drilled and completed 18 and 13 horizontal wells, respectively, in our Pennsylvania acreage with a 100% success rate. We have approximately 113 identified highly economic locations and five DUCs, which our independent reserve engineer has estimated have an EUR of 1.7 Bcf per 1,000 feet, and our returns are bolstered by our wholly owned midstream system. We currently own a gathering system and therefore are not subject to onerous takeaway contracts that burden the results of some of our Marcellus peers.

Utica Deep Dry Gas

Our Pennsylvania acreage overlays the dry gas Utica Shale providing 66 highly prospective locations, which our independent reserve engineer has estimated has an EUR of 3.0 Bcf per 1,000 feet. Development of the southwestern Pennsylvania deep dry gas Utica continues to emerge and show attractive commercial characteristics. Utica development in our vicinity began in 2015 when CNX Resources Corp. (“CNX”) turned into sales the Gaut 4HU well, which had a 24-hr IP rate of 61.4 MMcf/d and has produced 14.4 Bcf since July 2015. Since 2015, the industry has drilled twelve deep dry gas Utica wells in Westmoreland and Armstrong counties with another twelve wells currently in various stages of development all near our leasehold position. CNX recently drilled two wells (Bell Point 6NHSU and 6OHSU) with an average of 14,600 lateral feet per well approximately seven miles from our acreage position. We have 66 identified drilling locations in this area, and our land picture supports lateral lengths of 12,500 to 14,000+ feet. Moreover, the industry has shown an ability to develop offset locations to initial development by repeatedly returning to pad locations to drill. Industry advancement has led to a broader understanding of the technical drilling, targeted depths, completion designs, and production profiles associated with the Utica. These wells are characterized by maintaining a high level of initial gas production ranging between 20 MMcf/d to 30 MMcf/d of natural gas for an extended period of 15 to 20 months prior to initial decline. While early in its development, operators’ recent return to pad drilling further underscores the industry’s transition away from exploration to managed development highlighting the deliverability of results. The well performance makes the deep dry gas Utica in southwestern Pennsylvania an exciting emerging natural gas resource opportunity.

Since 2015, cumulative dry gas production from Utica development has shown relatively flat production declines during the initial period of production as seen in the chart below.⁽¹⁾

(1) Gray lines represent recent Utica Dry Gas wells normalized to 9,000’ lateral: Aikens 5 S5JHSUT, Aikens 5 5MHSUT, Bell Point 6PHSU, Gaut 4IHSU, Poseidon 4U, Shaw 1DHSU, Shaw 1HHSU, Bell Point BP6NHSU, Bell Point BP6OHSU, Athena 4U and Athena 6U.

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Business Strategy

Our strategy is to create value for our stockholders through the identification and disciplined development of attractive oil and natural gas assets to achieve sustainable growth in our production and reserves and enhance our value. Our strategy has the following principal elements:

• Disciplined growth through development of our high-return drilling inventory. Our technical acumen and in-basin experience enable us to optimize our assets and produce some of the highest performing wells in the region. We have achieved this performance through relentless focus on costs, consistent lengthening of our laterals, careful lateral placement in the target zone and thoughtful completion design. Our assets include over 19 years of operated drilling locations. In Ohio, our Utica oil productivity per lateral foot compares favorably with premier oil basins across the lower 48 such as the Permian, Eagle Ford and Bakken. In Pennsylvania, our contiguous HBP acreage and company-owned midstream infrastructure allow us to maximize the economics of the stacked Marcellus and Utica plays. We intend to continue our disciplined operating approach and to develop our inventory in order to achieve the highest available rates of return.

• Optimize return-on-capital through focus on profitably increasing well recoveries while minimizing costs and leveraging midstream infrastructure. We take pride in carefully evaluating every step of the operational process to optimize production while minimizing costs. This includes potentially changing completion designs at the stage level from well to well to enhance recoveries. We continuously review and examine our AFEs to drive our drilling and completion costs lower. Further, we promote cross-discipline communication to ensure that decisions are made on an integrated basis across our enterprise. Our owned midstream infrastructure in Pennsylvania significantly enhances returns by reducing upstream costs and generating third party revenue, while enabling us to control development timing, capital deployment and future strategic takeaway. We have improved netbacks on our Ohio assets through facility optimization and successful contract renegotiation. In addition to a relentless focus on new well planning and execution, we also review operations of acquired assets to determine whether upgrading or replacing equipment will be profitable. We have successfully enhanced production on a large number of wells that we have acquired.

• Ensure financial flexibility with balanced commodity exposure, and conservative financing. In building our company, we sought to preserve flexibility to maintain our focus on achieving the highest possible returns on investment. We have exposure to a range of assets that allow us to optimize our drilling economics across volatile commodity price environments. Additionally, we are not subject to any material midstream commitments or acreage expirations, which provides us the flexibility to match an optimal development pace to prevailing commodity prices and the hedging environment at any given time. Further, at the completion of this offering, we expect to have low net leverage positioning us to be immediately acquisitive. However, we intend to maintain a conservative capital structure with a target net leverage of less than 1.0x Adjusted EBITDAX.

• Leverage extensive industry and local experience to capture value through strategic acquisitions and asset base optimization. We have significant experience in sourcing, evaluating, executing and integrating acquisitions, including 14 privately sourced transactions. We believe our in-basin experience and local presence provides us with a competitive advantage in identifying opportunities and creating value through superior execution. We regularly initiate and review acquisition opportunities and intend to pursue future acquisitions that meet our strategic and financial objectives. We believe there are substantial opportunities to grow our acreage footprint across the Appalachian Basin through both acquisition and leasing. Additionally, our growth has been driven by increased operational efficiency, including reduced drilling days, well design modifications, facility optimization and continued focus on strategic, local procurement throughout our operations. Furthermore, we believe our contiguous acreage position and our ability to drill long-lateral wells will enhance our returns by increasing our EUR per well, reducing unit

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drilling and completion costs and providing economies of scale to allow us to better leverage our infrastructure. Further, given that we will be implementing an “Up-C” structure in connection with this offering, we will have the option in the future to offer acquisition targets equity in INR Holdings that can be exchanged for our Class A common stock (or cash of equivalent value) and offer a tax deferral mechanism, increasing the financial attractiveness of our platform to potential targets.

• Steward the health and safety of our employees and the environment, while taking an active role in our local community. We are dedicated to responsible energy development guided by our core values of environmental stewardship, safety and community engagement. While maintaining our commitment to our values, we actively seek business partners who share that commitment and will amplify our ability to achieve our goals. We use a top-down approach to provide resources and ensure our employees and partners are equipped to work in a safe environment. In 2023, our internal total recordable incident rate remained at 0.0 and our contractor blended rate was 1.6 with over 450,000 logged man-hours. We take pride in selectively choosing business partners with similar core values to help us achieve our goals. In addition to prioritizing high environmental standards and safe operations, we are committed to enriching the areas where we operate. We work diligently to make a strong economic impact in our communities and routinely volunteer both our time and resources to make a difference. Since our inception in 2017, we have partnered with 20 organizations in the region and have formed a community advisory panel to help actively expand our engagement within the area. Focusing on unconventional plays, we prioritize sustainable economic growth by producing natural resources responsibly. We invest considerable time and capital into accurately measuring and reducing production-related emissions like CO₂ and methane. Through innovative facility design and state of the art technology, we achieved a 51.9% reduction in CO₂e per MMBoe from 16,217.3 mT CO₂e/MMBoe in 2022 to 7,804 mT CO₂e/MMBoe in 2023, while methane intensity dropped from 0.14% to 0.076% of production between 2022 and 2023. Along with our environmental initiatives, we have established a culture which prioritizes safety.

Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our business strategy, including:

• Disciplined operator with industry-leading costs and well performance. We profitably develop our drilling inventory by optimizing our well performance while also minimizing costs. Our leading well performance is driven by our high reservoir quality, technical expertise and unique acreage positions that allow for extended laterals. We have drilled 48 horizontal wells and participated in 19 non-operated wells since 2020 across our properties. Our proven approach is rooted in our ability to target well placement within the most productive layer of the reservoir for miles, routinely staying “in-zone” for the duration of the lateral. Further, we thoughtfully engineer the completion design for each well to place the ideal amount and type of proppant throughout the wellbore. The combination of these two practices contributes to higher recoveries per well. Our per unit development costs are improved by the economies of scale generated when consistently drilling long laterals, routinely exceeding 14,500 lateral feet, drilling these wells in multi-well deployments and building pads that allow for multiple drilling projects. Our Ohio Utica wells have an average IP 90 of 1,098 barrels of oil per day per well normalized to 15,000’ lateral. Further, we maintain low operating expenses and successfully navigate various commodity cycles by minimizing term acreage and long-term midstream and services commitments. We own and operate our gathering system in our Pennsylvania assets, which reduces our total midstream costs. These factors underpin our preference for operated positions in which we can control development techniques and capital allocation decisions. As a result, our Capital Efficiency Ratio was 3.0x for 2023, versus 1.0x for our Appalachia-Focused Public Peers and 2.0x for our Liquids-Focused Public Peers.

• Expansive portfolio of low-risk and high-return oil and natural gas inventory across multiple acreage positions. Our operations target an expansive portfolio of low-risk, high-return development

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opportunities with exposure to oil, natural gas and NGLs. Our oil-weighted activities are focused on the development of the Utica Shale’s volatile oil window in eastern Ohio. We operate 118 producing wells, two PDNP wells and two DUCs and have identified 154 additional drilling locations (greater than 2 million lateral feet) in the Ohio Utica Shale representing approximately nine years of repeatable development potential utilizing a one-rig development cadence as of December 31, 2024. Our natural gas activities are focused on the development of the dry gas Marcellus and dry gas Utica Shales in southwestern Pennsylvania. We currently operate 13 producing wells and five DUCs and maintain an inventory of approximately 179 drilling locations. We evaluate the risk-adjusted performance of our drilling results through two primary metrics: DROI and IRR. Applying both metrics in development decisions ensures that we are adequately balancing both the timing and amount of return of capital. Since 2021, we have drilled 32 wells and turned 28 wells into sales in the Utica volatile oil window, with an average IP 90 of 1,098 barrels of oil per day per well normalized to 15,000’ lateral. When combined with our leading cost structure, oil and natural gas development opportunities both generate significant cash flow and attractive rates of return.

• Balanced portfolio of oil and natural gas enables us to capitalize on commodity price volatility. The attractive rates of return possible in both our oil and natural gas properties provide us with a competitive advantage versus our peers, enabling us to selectively develop areas with the highest expected rate of return based on the prevailing commodity price environment. Our drilling inventory is approximately 46% oil weighted and 54% natural gas weighted measured by gross operated locations with attractive DROIs across both our oil and natural gas assets allowing us to pivot drilling activity quickly to take advantage of commodity prices. Our exposure to high return, oil-weighted inventory is unique within the Appalachian Basin enhancing our operating margins and cash flows relative to our regional peers. Our high quality natural gas position offers dual zone co-development of the Marcellus and deep dry gas Utica allowing us to leverage our infrastructure lowering our operating costs relative to our peers. Our optionality to oscillate between high quality natural gas and oil opportunities allows us to high-grade our portfolio and maximize resultant cash flow for our investors.

• Superior capital efficiency to support production growth with attractive free cash flow. We believe our full-cycle ratio compares favorably versus other industry players, illustrating our superior capital efficiency. Our superior capital efficiency enabled us to reduce acquisition borrowings over time and improve leverage while growing production from 5 MBoe/d to 25 MBoe/d over the course of April 2021 to September 2024. Looking forward, maintaining this level of capital efficiency will allow us to continue to prudently grow our assets while preserving optionality to return value to stockholders, manage liquidity and pursue strategic opportunities in our focus areas. Historically, we have used this free cash flow to develop our assets, grow production and repay debt.

• Conservatively capitalized balance sheet with strong liquidity profile. Maintaining a strong balance sheet is a principal focus of ours and a differentiator that creates a competitive advantage relative to our peers. Since our founding in 2017, we have regularly maintained leverage of less than 1.0x while prioritizing repaying amounts borrowed in connection with acquisitions. We expect to have minimal debt outstanding upon the completion of this offering and intend to maintain modest debt loads in the near term for working capital purposes. We believe our conservative leverage and substantial liquidity provide us the financial flexibility to fund our planned capital expenditures, return value to stakeholders and pursue strategic acquisitions. To date, we have maintained a disciplined hedging program that aims to hedge at least 70% of anticipated production for the next 24 months. We have and will continue to hedge into near term development programs to lock in project returns. In addition to benchmark pricing, we also hedge basis due to the historic volatility of basis differentials within our operating areas as well as individual commodities across oil, natural gas and NGLs. As of December 19, 2024, we have entered into hedging contracts covering approximately 1.58 MMBbls (approximately 4,350 Bbls/d) of our oil production for 2025 at a weighted average swap price of $71.51 per Bbl, approximately 1.0 MMBbls (approximately 2,790 Bbls/d) of our NGL production for 2025 at a weighted average swap price of $28.95 per Bbl, and

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approximately 33,321,000 MMBtu (approximately 91,000 MMBtu/d) of our gas production for 2025 at a weighted average swap price of $3.49 per MMBtu.

• Long track record of leveraging expertise and local presence to capture value through drill bit and mergers and acquisitions. We believe our management team’s experience in the Appalachian Basin and the continuity of our core team, which has worked together for over a decade, offers a distinguishing competitive advantage. Because of our local presence, we have extensive knowledge and deep relationships that enhance our ability to be a low-cost and highly productive operator and acquire assets at attractive valuations. We believe our local expertise has been a key contributor to our acquisition and leasing success, and we have earned a reputation as a partner of choice in the local community, which enhances our ability to compete for acreage. Our ability to quickly begin drilling on leased acreage has helped us manage our land costs and is a benefit to mineral owners. Additionally, we routinely increase our working interests in front of the drill bit to lengthen our wells and add incremental locations within and adjacent to our existing drilling units to leverage our existing infrastructure. Since our founding in 2017, we have completed 14 transactions across four distinct operated fields. Within each area, we have both improved performance of new wells by leveraging our drilling and completion techniques and optimized the legacy assets. Our local presence also helps to reduce service costs and improve availability. We believe that leveraging our strong and lasting relationships throughout the basin provides us with a unique and compelling competitive advantage that will yield positive returns for our stockholders.

Development Plan and Capital Budget

We are currently running a one-rig drilling program focused on the development of the Utica Shale’s volatile oil window in eastern Ohio and the dry gas Marcellus Shale in southwestern Pennsylvania. We believe our portfolio consists of low-risk, high-return development opportunities that have been well delineated over the past decade and represent repeatable development potential. Our asset exposure to both oil and dry gas presents us with the flexibility to shift our drilling efforts between oil and natural gas opportunistically when commodity prices change.

We invested approximately $141.2 million in 2023 on development costs and estimate that we invested approximately $175 to $185 million (of which $108.9 million had been incurred as of September 30, 2024) on our operated development activities in 2024. We funded our 2024 capital development program from cash flow from operations. As of the date hereof, we are in the process of finalizing our operating results for the three months and year ended December 31, 2024, and they are preliminary and subject to change.

Our development plan and capital budget are based on management’s current expectations and assumptions about future events. While we consider these expectations and assumptions to be reasonable, they are subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties. The amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated commodity prices, the availability of necessary equipment, infrastructure, drilling rigs, labor and capital and related costs.

Highlights and Recent Developments

Recent Well Results

Since September 30, 2024, we have placed into sales seven additional operated Utica Ohio wells totaling approximately 96,000 lateral feet in Guernsey County. Four of those wells were on our Stillion-Beros pad that had an average IP 30 of 2,270 Boe/d (57% oil, 68% liquids), and two of those wells were on our Beros pad that had an estimated average IP 30 of 1,879 Boe/d (61% oil, 70% liquids) (in each case normalized to 15,000’). On January 13, 2025 we placed into sales one well from our Rubel pad. This information regarding recent well results is preliminary and subject to change.

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Fourth Quarter Production

For the fourth quarter of 2024, our average daily production was estimated to be between 23 and 24 MBoe/d (approximately 29% oil, 49% liquids). As of the date hereof, we are in the process of finalizing our operating results for the three months ended December 31, 2024, and they are preliminary and subject to change.

Ohio Utica Acquisitions

On August 7, 2023, Wolf Run, our wholly-owned subsidiary, entered into a definitive purchase and sale agreement to acquire working interests in certain oil and gas assets from Utica Resource Ventures and PEO Ohio for $306 million, subject to customary purchase price adjustments. The transaction closed on October 4, 2023, for $279.0 million and was financed through a combination of $222.3 million that was raised from the issuance of equity to certain of our Existing Owners as well as borrowings of $56.7 million under our Prior Credit Facility.

As part of the transaction, we assumed control of approximately 39,185 net acres across Washington, Morgan, Noble and Guernsey counties in Ohio along with 54 producing horizontal wells, related surface equipment located on various pad locations and a deep inventory of premium drilling locations located within the volatile oil window of the Utica and Point Pleasant play in eastern Ohio.

Since these acquisitions, we have drilled 14 wells (totaling approximately 251,000 lateral feet) on the acquired acreage, 10 of which have been turned into sales and another two of which are PDNP.

Salt Fork State Park

On February 26, 2024, we were awarded approximately 5,705 net acres within Salt Fork State Park by the Ohio Oil and Gas Management Commission for $58.5 million or approximately $10,250 per acre. We closed on the acquisition of the parcels in July 2024.

Muskingum Watershed Lease

On October 4, 2024, we entered into a lease with Muskingum Watershed Conservancy District for approximately 1,900 acres in Guernsey and Noble Counties, Ohio. The acreage is contiguous with our existing acreage and represents 19 new or enhanced (which includes increased working interest or longer lateral length) drilling locations.

Credit Facility

On September 25, 2024, we entered into a new credit facility led by Citibank, N.A. The Credit Facility has a maximum facility size of $1.5 billion, an initial borrowing base of $325.0 million and available capacity of approximately $100.3 million as of September 30, 2024. The Credit Facility replaced our previously outstanding credit facility, which was terminated in connection with the refinancing. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing Agreements—Credit Facility.”

Corporate Reorganization

Infinity Natural Resources is a Delaware corporation that was formed for the purpose of making this offering. Following this offering and the transactions related thereto, Infinity Natural Resources will be a holding company whose sole material asset will consist of membership interests in INR Holdings. INR Holdings will continue to own all of our operating subsidiaries. After the consummation of the transactions contemplated by this prospectus, Infinity Natural Resources will be the managing member of INR Holdings and will control and be responsible for all operational, management and administrative decisions relating to INR Holdings’ business and will consolidate the financial results of INR Holdings and its subsidiaries.

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This offering is being conducted through what is commonly referred to as an “Up-C” structure, which is often used by partnerships and limited liability companies undertaking an initial public offering. The Up-C structure provides the Existing Owners of the Company with the tax advantage of continuing to own interests in a pass-through structure, which is tax efficient because their allocable shares of income from INR Holdings will not be subject to entity-level tax. The Up-C structure will also provide potential future tax benefits for both the public company and the Existing Owners when they ultimately exchange their pass-through interests for shares of Class A common stock, which is expected to result in tax basis adjustments in the assets of INR Holdings and produce favorable tax attributes for us. We are a holding company, and immediately after the consummation of the reorganization transactions as described herein and this offering, our principal asset will be our ownership interests in INR Holdings. See “Corporate Reorganization—Holding Company Structure” and “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

In connection with this offering: (a) the Existing Owners’ LLC Interests (both capital interests and management incentive units) in INR Holdings will be recapitalized into a single class of units, the newly issued INR Units, with the INR Units to be allocated among the Existing Owners in accordance with the terms of the INR Holdings LLC Agreement and calculated using an implied valuation for INR Holdings based on the initial public offering price of our Class A common stock and (b) INR will contribute the net proceeds of this offering to INR Holdings in exchange for newly issued INR Units and a managing member interest in INR Holdings. Pursuant to the terms of the INR Holdings LLC Agreement, the INR Units to be issued to the Existing Owners in connection with the corporate reorganization will be calculated using an implied equity value of INR Holdings immediately prior to this offering, and the current relative levels of ownership in INR Holdings with the allocation of such units among our existing equity holders to be determined based on the initial public offering price. After giving effect to these transactions and the offering contemplated by this prospectus, (a) INR will own an approximate 22.5% interest in INR Holdings (or 25.0% if the underwriters’ option to purchase additional shares is exercised in full) and (b) the Existing Owners will own an approximate 77.5% interest in INR Holdings (or 75.0% if the underwriters’ option to purchase additional shares is exercised in full).

Each share of Class B common stock of INR (“Class B common stock”) will entitle its holder to one vote on all matters to be voted on by stockholders. Holders of shares of Class A common stock of INR (“Class A common stock”) and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation. We do not intend to list our Class B common stock on any stock exchange.

We will enter into a Tax Receivable Agreement with the Existing Owners. This agreement generally provides for the payment by INR to the Existing Owners of 85% of the net cash savings, if any, in U.S. federal, state and local income tax that INR (a) actually realizes with respect to taxable periods ending after this offering or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the INR board of directors) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (a) the tax basis increases resulting from the exchange of INR Units and the corresponding surrender of an equivalent number of shares of Class B common stock by the Existing Owners for a number of shares of Class A common stock on 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 (b) 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 Tax Receivable Agreement. INR will retain the benefit of the remaining 15% of these cash savings, if any. If we experience a change of control or the Tax Receivable Agreement terminates early, we could be required to make a substantial, immediate lump-sum payment. “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” contains more information.

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The following diagrams indicate our simplified current ownership structure and our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised):

Simplified Current Ownership Structure

(1) Includes PEI INR Holdings, L.P., Pearl Energy Investments III, L.P., PEI Infinity-S, LP, Pearl Energy Investments, L.P., PEI INR Co-Invest-B Corp, NGP XI US Holdings, L.P. and certain members of management and the board of directors.

(2) Includes INR Ohio, INR Midstream, Block Island, INR Operating and Cheat Mountain.

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Simplified Ownership Structure After Giving Effect to this Offering

(1) Includes PEI INR Holdings, L.P., Pearl Energy Investments III, L.P., PEI Infinity-S, LP, Pearl Energy Investments, L.P., PEI INR Co-Invest-B Corp and NGP XI US Holdings, L.P., members of management and certain other individuals.

(2) Includes INR Ohio, INR Midstream, Block Island, INR Operating and Cheat Mountain.

Our Principal Stockholders

Following the completion of this offering, Pearl will in the aggregate own 28,894,732 shares of Class B common stock, representing 49.1% of our outstanding capital stock and approximately 49.1% of the voting power of the Company (47.5% if the underwriters’ option to purchase additional shares is exercised in full), and NGP will in the aggregate own 9,631,441 shares of Class B common stock, representing 16.4% of our outstanding capital stock and approximately 16.4% of the voting power of the Company (15.8% if the underwriters’ option to purchase additional shares is exercised in full).

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Pearl Energy Investments is a Dallas, Texas-based investment firm with $2.0 billion of cumulative capital commitments under management. Pearl focuses on partnering with proven management teams to invest in the North American energy sector.

NGP is a family of private equity funds managed by NGP Energy Capital Management, L.L.C., a premier investment franchise organized to make investments in natural resources and energy transition. In NGP’s 36-year history, NGP has managed investment funds with more than $24 billion of aggregate equity commitments.

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”). For as long as we are an emerging growth company, unlike other public companies that are not emerging growth companies under the JOBS Act, we are not required to:

• provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (“SOX”);

• provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations nor more than two years of selected financial data in a registration statement on Form S-1;

• comply with any new requirements adopted by the Public Company Accounting Oversight Board (the “PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; or

• provide certain disclosure regarding executive compensation required of larger public companies required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”).

We will cease to be an “emerging growth company” upon the earliest of:

• the last day of the fiscal year in which we have $1.235 billion or more in annual revenues (as such amount may be adjusted by the SEC for inflation);

• the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30 of such year);

• the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or

• the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. We have elected to avail ourselves of the provision of the JOBS Act that permits emerging growth companies to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. As a result, we will not be subject to new or revised accounting standards at the same time as other public companies that are not emerging growth companies. We intend to take advantage of the other exemptions discussed above, both in this prospectus and in future filings with the SEC. Accordingly, the information contained herein and that we provide to our stockholders from time to time may be different than the information you receive from other public companies. For additional information, see the section titled “Risk Factors—Risks Related to this Offering, Our Class A Common Stock and Capital Structure—For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards

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and disclosure about our executive compensation. Taking advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards applicable to emerging growth companies may make our Class A common stock less attractive to investors.”

Corporate Information

Our principal executive offices are located at 2605 Cranberry Square, Morgantown, WV 26508, and our telephone number at that address is (304) 212-2350. Our website is located at www.infinitynaturalresources.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

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The Offering

Class A common stock offered by us 13,250,000 shares (or 15,237,500 shares, if the underwriters exercise in full their option to purchase additional shares).

Class A common stock to be outstanding after the offering 13,250,000 shares (or 15,237,500 shares, if the underwriters exercise in full their option to purchase additional shares).

Option to purchase additional shares We have granted the underwriters a 30-day option to purchase up to an aggregate of 1,987,500 additional shares of our Class A common stock.

Class B common stock to be outstanding immediately after completion of this offering 45,638,889 shares, or one share for each INR Unit held by the INR Unit Holders immediately following this offering. Class B shares are non-economic. When an INR Unit is exchanged for a share of Class A common stock, a corresponding share of Class B common stock will be surrendered.

Use of proceeds We expect to receive approximately $238.6 million of net proceeds from the sale of the Class A common stock offered by us (or approximately $276.0 million, if the underwriters exercise in full their option to purchase additional shares), after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to contribute all of the net proceeds from this offering to INR Holdings in exchange for 13,250,000 INR Units. INR Holdings intends to use the net proceeds from this offering to repay borrowings outstanding under the Credit Facility and the excess, if any, for general corporate purposes. “Use of Proceeds” contains additional information regarding our intended use of proceeds from this offering.

Conflicts of Interest Because affiliates of Citigroup Global Markets Inc. (“Citigroup”), RBC Capital Markets, LLC (“RBC”), BofA Securities, Inc. (“BofA”), BOK Financial Securities, Inc. (“BOK”), Capital One Securities, Inc. (“Capital One”), Truist Securities, Inc. (“Truist”), Comerica Securities, Inc. (“Comerica”), First Citizens Capital Securities, LLC (“First Citizens”) and KeyBanc Capital Markets Inc. (“KeyBanc”) are lenders under our Credit Facility and will receive 5% or more of the net proceeds of this offering due to the repayment of borrowings under the Credit Facility, Citigroup, RBC, BofA, BOK, Capital One, Truist, Comerica, First Citizens and KeyBanc, underwriters in this offering, are deemed to have a “conflict of interest” under Rule 5121 (“Rule 5121”) of the Financial Industry Regulatory Authority, Inc. (“FINRA”). Accordingly, this offering will be conducted in compliance with the requirements of Rule 5121, which requires, among other things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus. Raymond James & Associates, Inc. (“Raymond James”) has agreed to act as a qualified independent underwriter for this

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offering and to undertake the legal responsibilities and liabilities of an underwriter under the Securities Act, specifically including those inherent in Section 11 thereof. Raymond James will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify Raymond James against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act. See “Use of Proceeds” and “Underwriting (Conflicts of Interest)” for additional information.

Voting Power of Class A common stock after giving effect to this offering 22.5% (or 100% if all outstanding INR Units held by the INR Unit Holders are exchanged, along with a corresponding number of shares of our Class B common stock, for newly issued shares of Class A common stock on a one-for-one basis).

Voting Power of Class B common stock after giving effect to this offering 77.5% (or 0% if all outstanding INR Units held by the INR Unit Holders are exchanged, along with a corresponding number of shares of our Class B common stock, for newly issued shares of Class A common stock on a one-for-one basis).

Voting rights The Existing Owners will hold all of the outstanding shares of our Class B common stock. Each share of Class B common stock will entitle its holder to one vote on all matters to be voted on by stockholders generally. After giving effect to the shares issued pursuant to this offering, the Existing Owners will hold in the aggregate 0% of the outstanding shares of our Class A common stock. The Class A common stock will be voting stock and entitle each holder to one vote per share of Class A common stock. “Description of Capital Stock” contains more information.

Dividend policy Following the completion of this offering, our board of directors may elect to declare cash dividends on our Class A common stock, subject to our compliance with applicable law, and depending on, among other things, economic conditions, our financial condition, results of operations, projections, liquidity, earnings, legal requirements, and restrictions in the agreements governing our indebtedness (as further discussed below). The payment of any future dividends will be at the discretion of our board of directors. We have not adopted, and do not currently expect to adopt, a written dividend policy. “Dividend Policy” contains more information.

Listing and trading symbol We have been approved to list our Class A common stock on the NYSE under the symbol “INR.”

Exchange rights of INR Unit Holders In connection with the completion of this offering, we will adopt the INR Holdings LLC Agreement so that the Existing Owners may (subject to the terms of the INR Holdings LLC Agreement) exchange their INR Units, along with surrendering a corresponding number of shares of our Class B common stock, for shares of Class A common stock of INR on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications, or, at our option, an equivalent amount of cash (the “Exchange Right”).

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Directed Share Program At our request, the underwriters have reserved up to 5% of the shares of Class A common stock offered by this prospectus for sale, at the initial public offering price to certain individuals through a directed share program, including our directors, officers, employees and other individuals we identify. The number of shares of our Class A common stock available for sale to the general public will be reduced to the extent these individuals purchase such reserved shares. Any reserved shares that are not so purchased will be offered by the underwriters to the general public on the same basis as the other shares offered by this prospectus. See “Underwriting (Conflicts of Interest)—Directed Share Program.”

Tax receivable agreement Future exchanges of INR Units for shares of Class A common stock are expected to result in increases in the tax basis of the tangible and intangible assets of INR Holdings. The anticipated basis adjustments are expected to increase (for tax purposes) our depreciation, depletion and amortization deductions and may also decrease our gains (or increase our losses) on future dispositions of certain capital assets to the extent tax basis is allocated to those capital assets. Such increased deductions and losses and reduced gains may reduce the amount of tax that we would otherwise be required to pay in the future. Prior to the completion of this offering, we will enter into a Tax Receivable Agreement with the Existing Owners. This agreement generally provides for the payment by INR to the Existing Owners, respectively, of 85% of the net cash savings, if any, in U.S. federal, state and local income tax that INR (a) actually realizes with respect to taxable periods ending after this Offering or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the INR board) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of INR Units and the corresponding surrender of an equivalent number of shares of Class B common stock by an Existing Owner, respectively, 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 Tax Receivable Agreement. INR will retain the benefit of the remaining 15% of these cash savings, if any. If we experience a change of control or the Tax Receivable Agreement terminates early, we could be required to make a substantial, immediate lump-sum payment. “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” contains more information.

Unless indicated otherwise, information regarding outstanding shares of our Class A common stock does not include 5,888,889 shares of Class A common stock reserved for issuance pursuant to our omnibus incentive plan

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that we intend to adopt in connection with the completion of this offering or the grants of equity awards to certain of our directors, officers and employees upon consummation of this offering. See “Executive Compensation” for more information.

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Summary of Risk Factors

An investment in our securities involves a high degree of risk. The occurrence of one or more of the events or circumstances described in the section titled “Risk Factors,” alone or in combination with other events or circumstances, may materially adversely affect our business, financial condition and operating results. In that event, the trading price of our securities could decline, and you could lose all or part of your investment. Such risks include, but are not limited to:

Risks Related to Commodity Prices

• Oil, natural gas and NGL prices are volatile. A sustained decline in prices could adversely affect our business, financial condition and results of operations, liquidity and our ability to meet our financial commitments or cause us to delay our planned capital expenditures.

• We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

• Certain factors could require us to write down the carrying values of our properties, including commodity prices decreasing to a level such that our future undiscounted cash flows from our properties are less than their carrying value.

Risks Related to Our Reserves, Leases and Drilling Locations

• Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

• Unless we replace our reserves with new reserves and develop those new reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

• Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

• Properties that we decide to drill may not yield oil, natural gas and NGLs in commercially viable quantities.

Risks Related to Our Operations

• Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

• Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

• Some of our properties are in areas that may have been partially depleted or drained by offset (i.e., neighboring) wells, and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own.

• Our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.

• The marketability of certain of our production is dependent upon transportation and other facilities, which we do not control. If these facilities are unavailable, or if there are any increases in the cost of using these services or facilities, our operations could be interrupted, our revenues could be reduced and our costs could increase.

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• We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

• Continuing or worsening inflationary pressures and associated changes in monetary policy may result in increases to the cost of our goods, services, and personnel, which in turn could cause our capital expenditures and operating costs to rise.

• We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

• We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

• Competition in our industry is intense, making it more difficult for us to acquire properties, market oil, natural gas and NGLs, secure trained personnel and raise additional capital.

• As a private company, we have not been required to document and test our internal controls over financial reporting, nor has our management been required to certify the effectiveness of our internal controls, and our auditors have not been required to opine on the effectiveness of our internal control over financial reporting. We have identified material weaknesses in our internal control over financial reporting which, if not corrected, could affect the reliability of our consolidated financial statements and have other adverse consequences.

Risks Related to Our Derivative Transactions, Debt and Access to Capital

• Our derivative activities could result in financial losses or could reduce our earnings.

• Our ability to obtain financing on terms acceptable to us may be limited in the future by, among other things, increases in interest rates.

Risks Related to this Offering, Our Class A Common Stock and Capital Structure

• We are a holding company. Our sole material asset after completion of this offering will be our equity interest in INR Holdings and we are accordingly dependent upon distributions from INR Holdings to pay taxes, make payments under the Tax Receivable Agreement and cover our corporate and other overhead expenses.

• Pearl and NGP will collectively hold a substantial majority of our capital stock and voting power.

• Investors in this offering will experience immediate and substantial dilution of $7.02 per share.

• For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including disclosure about our executive compensation, that apply to other public companies.

• We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may claim, and the amounts of such payments could be significant.

• In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits we realize, if any, in respect of the tax attributes subject to the Tax Receivable Agreement.

Risks Related to Environmental and Regulatory Matters

• Our operations are subject to stringent environmental, health and safety laws and regulations that may expose us to significant costs and liabilities that could exceed current expectations.

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• Legislation or regulatory initiatives intended to address seismic activity, as well as government reviews of such activities, could restrict our drilling and production activities, as well as our ability to dispose of saltwater produced from such activities, which could limit our ability to produce oil, natural gas and NGLs economically and have a material adverse effect on our business.

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Summary Historical and Unaudited Pro Forma Financial Information

The following table shows summary historical financial information of the Company’s accounting predecessor, INR Holdings, and summary unaudited pro forma financial information as of the dates indicated and for the periods ended herein.

The summary historical financial information as of September 30, 2024, and for the nine months ended September 30, 2024 and 2023, and for the years ended December 31, 2023 and 2022, were derived from the unaudited and audited historical consolidated financial statements of INR Holdings included elsewhere in this prospectus.

The summary unaudited pro forma condensed consolidated balance sheet and statement of operations data as of and for the nine months ended September 30, 2024, respectively, and the summary unaudited pro forma condensed consolidated statement of operations data for the year ended December 31, 2023, has been prepared to give pro forma effect to (i) the reorganization transactions described elsewhere in this prospectus under “Corporate Reorganization,” and (ii) this offering and the application of the net proceeds from this offering as described elsewhere in this prospectus under “Use of Proceeds,” as if each had been completed on September 30, 2024, for purposes of the unaudited pro forma condensed consolidated balance sheet and January 1, 2023, for purposes of the unaudited pro forma condensed consolidated statements of operations.

The summary unaudited pro forma condensed consolidated statement of operations data for the year ended December 31, 2023, has been prepared to also give pro forma effect to the Utica Resource Acquisition and the PEO Ohio Acquisition, as if the Utica Resource Acquisition and the PEO Ohio Acquisition each had been completed on January 1, 2023. As the Utica Resource Acquisition and the PEO Ohio Acquisition each closed on October 4, 2023, the consolidated balance sheet of INR Holdings as of December 31, 2023, includes the assets acquired.

This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus. The summary unaudited pro forma financial information is presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the above mentioned transactions been consummated on the date indicated, and does not purport to be indicative of our financial position or results of operations as of any future date or for any future period.

“Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Corporate Reorganization,” the unaudited pro forma condensed consolidated financial statements, and the historical financial statements included elsewhere in this prospectus contain additional information to be read in conjunction with the following information.

	Predecessor Historical								Pro Forma
	As of and for the Nine Months Ended September 30,				As of and for the Years Ended December 31,				As of and for the Nine Months Ended September 30, 2024		For the Year Ended December 31, 2023
	2024		2023		2023		2022
	(in thousands, except share and per share data)
Statements of Operations Information:
Revenues:
Oil, natural gas, and natural gas liquids sales	$	188,877	$	88,301	$	159,532	$	142,600	$	188,877	$	260,355
Midstream activities		1,032		1,672		2,198		555		1,032		2,198
Total revenues		189,909		89,973		161,730		143,155		189,909		262,553

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	Predecessor Historical												Pro Forma
	As of and for the Nine Months Ended September 30,						As of and for the Years Ended December 31,						As of and for the Nine Months Ended September 30, 2024			For the Year Ended December 31, 2023
	2024			2023			2023			2022
	(in thousands, except share and per share data)
Operating Expenses:
Gathering, processing, and transportation		37,852			18,378			31,097			15,673			37,852			42,628
Lease operating		20,715			10,808			18,371			8,256			20,715			24,939
Production and ad valorem taxes		1,264			396			886			719			1,264			1,880
Depreciation, depletion, and amortization		56,344			29,289			53,796			18,336			56,344			89,899
General and administrative		8,268			3,472			4,885			4,712			8,268			137,439
Total operating expenses		124,443			62,343			109,035			47,696			124,443			296,785
Operating income		65,466			27,630			52,695			95,459			65,466			(34,232	)
Operating income (expense):
Interest, net		(16,263	)		(6,968	)		(11,910	)		(2,574	)		(222	)		(312	)
(Loss) gain on derivative instruments		6,397			5,220			45,322			(24,820	)		6,397			46,477
Other (loss) income		(797	)		562			565			64			(797	)		1,009
Income before income taxes		54,803			26,444			86,672			68,129			70,844			12,942
Income tax provision		—			—			—			—			3,558			650
Net income	$	54,803		$	26,444		$	86,672		$	68,129		$	67,286		$	12,292
Net income attributable to non-controlling interests														52,147			9,526
Net income attributable to Infinity Natural Resources													$	15,139		$	2,766
Pro forma net income per share of Class A common stock - basic and diluted													$	1.14		$	0.21
Weighted-average shares of Class A common stock outstanding - basic														13,250,000			13,250,000
Incremental shares of Class A common stock attributable to dilutive instruments														45,801,389			45,720,139
Weighted average of shares of Class A common stock outstanding - diluted														59,051,389			58,970,139
Balance Sheet Information:
Cash and cash equivalents	$	1,565					$	1,504		$	739		$	23,096
Oil and gas properties, net – full cost	$	709,320					$	575,560		$	207,595		$	709,320
Total assets	$	825,375					$	688,509		$	266,705			851,042
Total debt	$	224,930					$	171,241		$	58,148		$	184
Total members’ / stockholders’ equity(1)	$	513,759					$	458,456		$	149,506		$	171,939

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	Predecessor Historical												Pro Forma
	As of and for the Nine Months Ended September 30,						As of and for the Years Ended December 31,						As of and for the Nine Months Ended September 30, 2024		For the Year Ended December 31, 2023
	2024			2023			2023			2022
	(in thousands, except share and per share data)
Non-controlling interests	$	—					$	—		$	—		$	592,233
Total equity(2)	$	513,759					$	458,456		$	149,506		$	764,172
Statements of Cash Flows Information:
Net cash provided by operating activities	$	147,566		$	73,293		$	106,475		$	64,976
Net cash used in investing activities	$	(194,755	)	$	(142,755	)	$	(436,686	)	$	(95,661	)
Net cash provided by financing activities	$	47,250		$	92,615		$	330,976		$	28,997
Other Financial Information:
Adjusted EBITDAX(3)	$	149,539		$	70,958		$	126,494		$	75,971		$	149,539	$	205,504

(1) Total members’ equity as of September 30, 2024, December 31, 2023, and December 31, 2022 represents the historical members’ equity of INR Holdings, while the pro forma stockholders’ equity as of September 30, 2024 represents the pro forma stockholders’ equity of the Company subsequent to the corporate reorganization and offering transactions described herein.

(2) Pro forma total equity as of September 30, 2024, includes $592.2 million of non-controlling interests.

(3) Adjusted EBITDAX is not a financial measure calculated in accordance with U.S. GAAP. We believe this measure provides important perspective regarding our operating results and liquidity, as applicable. “—Non-GAAP Financial Measures” contains a description of this measure and a reconciliation to the most directly comparable U.S. GAAP measure.

Non-GAAP Financial Measures

Adjusted EBITDAX

We define Adjusted EBITDAX as net income plus interest expense, net, income tax expense, depreciation, depletion, and amortization, unrealized gain (loss) on derivative instruments, net cash settlements received (paid) on derivatives, non-cash interest expense (amortization) and non-cash G&A. We believe Adjusted EBITDAX is useful because it makes for an easier comparison of our operating performance, without regard to our financing methods, corporate form or capital structure. We determined our adjustments from net income to arrive at Adjusted EBITDAX to reflect the substantial variance in practice from company to company within our industry depending upon accounting methods and book values of assets, capital structures, and the method by which the assets were acquired. Adjusted EBITDAX should not be considered more meaningful than or as an alternative to net income determined in accordance with U.S. GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may differ from and may not be comparable to similarly titled measures of other companies.

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The following table provides a reconciliation of our net income, the most directly comparable financial measure presented in accordance with U.S. GAAP, to Adjusted EBITDAX for the periods presented herein:

	Predecessor						Predecessor Historical						Pro Forma
	For the Nine Months Ended September 30,						For the Year Ended December 31,						For the Nine Months Ended September 30, 2024			For the Year Ended December 31, 2023
	2024			2023			2023			2022
	(in thousands)
Net income	$	54,803		$	26,444		$	86,672		$	68,129		$	67,286		$	12,292
Interest expense, net		16,263			6,968			11,910			2,574			222			312
Income tax expense		—			—			—			—			3,558			650
Depreciation, depletion, and amortization		56,344			29,289			53,796			18,336			56,344			89,899
Net (gain) loss on derivative instruments		(6,397	)		(5,220	)		(45,322	)		24,820			(6,397	)		(46,477	)
Net cash settlements received (paid) on derivatives		27,755			13,477			19,438			(37,888	)		27,755			19,438
Non-cash G&A		771			—			—			—			771			129,390
Adjusted EBITDAX	$	149,539		$	70,958		$	126,494		$	75,971		$	149,539		$	205,504

PV-10

Certain of our oil and natural gas reserve disclosures included in this prospectus are presented on a PV-10 basis. PV-10 is a non-GAAP financial measure and represents the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV-10 of proved reserves generally differs from the standardized measure of discounted future net cash flows from production of proved oil and natural gas reserves (the “Standardized Measure”), the most directly comparable GAAP financial measure, because it does not include the effects of future income taxes, as is required under GAAP in computing the Standardized Measure. However, our PV-10 for proved reserves using SEC pricing and the Standardized Measure of proved reserves are equivalent because we were not subject to entity level taxation. Accordingly, no provision for federal or state income taxes has been provided in the Standardized Measure because taxable income is passed through to our unitholders.

We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and natural gas companies. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of PV-10 value provides greater comparability when evaluating oil and natural gas companies. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. However, the definition of PV-10 value as defined above may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value as defined may not be comparable to similar measures provided by other companies.

Investors should be cautioned that neither PV-10 nor Standardized Measure of proved reserves represents an estimate of the fair market value of our proved reserves. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.

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Summary Reserve, Production and Operating Data

The following tables summarize our estimated oil, natural gas and NGL reserves as of December 31, 2023 and our production and historical operating data for the years ended December 31, 2022 and 2023. The information included in the summary reserve table is based on a reserve report prepared by our independent consulting petroleum engineers, Wright & Company, Inc. (“Wright”). For more information, see “Business—Our Operations—Reserve Data and Presentation” and our summary reserve report filed as an exhibit to the registration statement of which this prospectus forms a part. Historical reserve information is not necessarily indicative of results that may be expected for any future period.

Summary Reserve Data

Summary of Reserves as of December 31, 2023 Based on SEC Pricing

The following table provides our estimated proved reserves as of December 31, 2023 based on SEC pricing.

	December 31, 2023(1)
Proved developed reserves:
Crude oil (MBbls)		13,172
Natural Gas (MMcf)		252,832
NGL (MBbls)		12,644
Total proved developed reserves (MBoe)(3)		67,954
Proved undeveloped reserves:
Crude oil (MBbls)		17,866
Natural Gas (MMcf)		255,893
NGL (MBbls)		13,118
Total proved undeveloped reserves (MBoe)(3)		73,633
Total proved reserves:
Crude oil (MBbls)		31,038
Natural Gas (MMcf)		508,725
NGL (MBbls)		25,762
Total proved reserves (MBoe)(2)(3)		141,587
Proved developed reserves (%)		48.0	%
Total undeveloped reserves (%) .		52.0	%
Reserve values (in thousands):
Standardized Measure of discounted future net cash flows	$	938,384
Discounted future income tax expense		N/A
Total proved pre-tax PV-10(4)	$	938,384

(1) Our estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC regulations. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $78.22 per barrel for oil and $2.637 per MMBtu for natural gas at December 31, 2023. These base prices were adjusted for differentials on a per property basis, including local basis differentials and fuel costs, resulting in $73.73 per barrel for oil, $1.739 per MMBtu for natural gas, and $26.87 per barrel for NGLs at December 31, 2023.

(2) All proved reserves as of December 31, 2023 were part of a development plan adopted by management indicating that such locations were scheduled to be drilled within five years of initial classification.

(3) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

(4) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves and less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. For more information on how we calculate PV-10 and a reconciliation of proved reserves PV-10 to its nearest GAAP measure, see “Prospectus Summary—Non-GAAP Financial Measures.” With respect to PV-10 calculated as of an interim date, it is not practicable to calculate the taxes for the related interim period because GAAP does not provide for disclosure of Standardized Measure on an interim basis.

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Select Production and Operating Statistics

The following table sets forth information regarding production, revenues and realized prices and production costs for the years ended December 31, 2023 and 2022. The information for the year ended December 31, 2023, includes the assets acquired in the Utica Resource Acquisition and the PEO Ohio Acquisition that closed on October 4, 2023. All of our production is derived from the Appalachian Basin. For additional information on price calculations, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	For the Year Ended December 31,
	2023		2022
Production data:
Oil (MBbls)		1,205		640
Natural gas (MMcf)		27,506		11,585
NGL (MBbls)		1,112		656
Total (MBoe)		6,901		3,227
Average daily production (MBoe/d)(1)		18.9		8.8
Average wellhead realized prices (before giving effect to realized derivatives):
Oil (/Bbl)	$	70.77	$	85.36
Natural gas (/Mcf)	$	1.80	$	5.70
NGL (/Bbl)	$	22.16	$	33.42
Average wellhead realized prices (after giving effect to realized derivatives):
Oil (/Bbl)	$	71.03	$	74.09
Natural gas (/Mcf)	$	2.42	$	3.48
NGL (/Bbl)	$	24.00	$	25.43
Operating costs and expenses (per Boe)(1):
Gathering, processing and transportation	$	4.51	$	4.86
Lease operating		2.66		2.56
Production and ad valorem taxes		0.13		0.22
Depreciation, depletion, and amortization		7.79		5.68
General and administrative		0.71		1.46
Total	$	15.80	$	14.78

(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

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RISK FACTORS

Investing in our Class A common stock involves risks. The information in this prospectus should be considered carefully, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks, before making an investment decision. The risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. The occurrence of any of the following risks or additional risks and uncertainties that are currently immaterial or unknown could materially and adversely affect our business, financial condition, liquidity, results of operations, cash flows or prospects. The trading price of our Class A common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Commodity Prices

Oil, natural gas and NGL prices are volatile. A sustained decline in prices could adversely affect our business, financial condition and results of operations, liquidity and our ability to meet our financial commitments or cause us to delay our planned capital expenditures.

Our revenues, operating results, profitability, liquidity and ability to grow depend primarily upon the prices we receive for the oil, natural gas and NGLs we sell. We require substantial expenditures to replace our oil, natural gas and NGL reserves, sustain production and fund our business plans, including our development and exploratory drilling efforts. Lower commodity prices negatively affect the amount of cash available for capital expenditures, could negatively affect our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows. In addition, low prices may reduce the quantities of oil, natural gas and NGL reserves that may be economically produced and result in an impairment of our natural gas and oil properties.

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in oil, natural gas and NGL prices may result from relatively minor changes in the supply of or demand for oil, natural gas and NGLs, market uncertainty and other factors that are beyond our control, including:

• worldwide and regional economic conditions impacting the supply and demand for oil, natural gas and NGLs, including inflationary pressures;

• changes in seasonal temperatures, including the number of heating degree days during winter months and cooling degree days during summer months;

• the level of oil, natural gas and NGL exploration, development and production;

• the level of U.S. LNG exports;

• prevailing prices on local price indexes in the areas in which we operate;

• the proximity, capacity, cost and availability of gathering and transportation facilities;

• localized and global supply and demand fundamentals and transportation availability;

• the cost of exploring for, developing, producing and transporting reserves;

• the spot price of LNG on world markets;

• weather conditions and natural disasters;

• technological advances affecting energy consumption;

• the price and availability of alternative fuels;

• speculative trading in natural gas derivative contracts;

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• armed conflict, political instability or civil unrest in oil and gas producing regions, including instability in the Middle East and the conflict between Russia and Ukraine, and the related potential effects on laws and regulations or the imposition of economic or trade sanctions;

• the occurrence or threat of epidemic or pandemic diseases, or any government response to such occurrence or threat;

• political and economic conditions in or affecting major LNG consumption regions or countries, particularly Asia and Europe;

• actions of the Organization of the Petroleum Exporting Countries (“OPEC”), including the ability and willingness of the members of OPEC and other exporting nations to agree to and maintain oil price and production controls, including the anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia;

• U.S. trade policies and their effect on U.S. oil, natural gas and NGL exports;

• expectations about future commodity prices; and

• U.S. federal, state and local and non-U.S. governmental regulation and taxes.

Lower commodity prices may reduce our operating margins, cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves or make acquisitions could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with natural gas prices at levels lower than current Henry Hub strip prices or oil prices lower than current WTI strip prices may adversely affect our drilling economics, cash flow and our ability to raise capital, which may require us to re-evaluate and postpone or substantially restrict our development program and result in the reduction of some of our proved undeveloped reserves and related PV-10. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to meet our financial commitments or cause us to delay our planned capital expenditures.

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices and drilling activity in our areas of operation and other major shale basins throughout the U.S. These cost increases result from a variety of factors beyond our control, such as increases in the cost of sand and other proppant used in hydraulic fracturing operations; steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities. Furthermore, 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. Higher levels of development activity in oil-focused shale basins have also historically resulted in higher levels of associated gas production that places downward pressure on natural gas prices. To the extent natural gas prices decline due to a period of increased associated gas production and we experience service cost inflation during such period, our cash flow and profitability may be materially adversely impacted.

Certain factors could require us to write down the carrying values of our properties, including commodity prices decreasing to a level such that our future undiscounted cash flows from our properties are less than their carrying value.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of

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prospective impairment reviews and the continuing evaluation of development plans, drilling and completion results, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash impairment charge to earnings. Lower commodity prices in the future could result in impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. For example, natural gas prices are a critical component to our fair value estimate of our natural gas properties. If these prices decline, we will record an impairment, which is a non-cash charge to earnings, if we determine that an asset’s carrying value exceeds its estimated fair value. Impairment expense may have a material adverse effect on our earnings. We could experience further material write-downs as a result of other factors, including low production results or high lease operating expenses, capital expenditures or transportation fees.

Risks Related to Our Reserves, Leases and Drilling Locations

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil, natural gas and NGL reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, production rates and timing of development expenditures must be projected and available geological, geophysical, production and engineering data must be analyzed. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as commodity prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, commodity prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves may vary materially from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected and production declines may be greater than we estimate and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates of proved reserves to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves. Furthermore, our development plan calls for completing horizontal wells using tighter frac spacing and substantially higher proppant volumes, which may increase the risk that these wells interfere with production from existing or future wells in the same spacing section and horizon, which in turn may result in lower recoverable reserves. There can be no assurance that our reserves will ultimately be produced.

You should not assume that the present values of future net cash flows from our reserves presented in this prospectus are the current market value of our estimated reserves. Actual future prices and costs may differ materially from those used in our present value estimates using SEC pricing. If spot prices or future actual prices are below the prices used in our current reserve estimates, using those prices in estimating proved reserves may result in a decrease in proved reserve volumes due to economic limits. You should not assume that the PV-10 values of our estimated reserves are accurate estimates of the current fair value of our estimated oil, natural gas and NGL reserves.

Unless we replace our reserves with new reserves and develop those new reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing development

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activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

The development of our estimated PDNPs and PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PDNPs and PUDs may not be ultimately developed or produced.

As of December 31, 2023, approximately 52% of our total estimated proved reserves were classified as proved undeveloped under SEC pricing. Development of these PUDs may take longer and require higher levels of capital expenditures than we currently anticipate. Estimated future development costs relating to the development of our PDNPs and PUDs at December 31, 2023 are approximately $530 million over the next five years. We plan to fund our capital development program primarily through cash flow from our operations. Our ability to fund these expenditures is subject to a number of risks. See “—Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.” Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the PV-10 value of our estimated PUDs and future net cash flows estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify some of our PUDs as unproved reserves. Furthermore, there is no certainty that we will be able to convert our PUDs to developed reserves or that our undeveloped reserves will be economically viable or technically feasible to produce.

Further, SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. As a result, we may be required to reclassify certain of our PUDs if we do not drill those wells within the required five-year timeframe.

Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Although approximately 85% of our acreage is HBP, held by operations or held-by-storage as of September 30, 2024, the remaining acreage is subject to expiration over future years. Of the remaining 15% of our acreage not HBP, approximately 4% will be subject to expiration in 2025, 2% in 2026 and approximately 93% thereafter, although a portion of our leases generally grant us the right to extend these leases for an additional three or five-year period. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. If we are unable to fund renewals of expiring leases, we could lose portions of our acreage and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.

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Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

We have specifically identified and scheduled certain drilling locations as an estimation of our future multiyear drilling activities on our existing acreage. Our ability to drill and develop these locations depends on a number of uncertainties, including commodity prices, statutory unitization, availability and cost of capital, drilling and production costs, availability of drilling services and equipment, availability and cost of sand and other proppant used in hydraulic fracturing operations, drilling results, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, access to and availability of saltwater disposal systems, regulatory approvals, the cooperation of other working interest owners and other factors. Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other drilling locations. Further, certain of the horizontal wells we intend to drill in the future may require pooling or unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to pool or unitize such leaseholds with ours, the total locations we can drill may be limited. As such, our actual drilling activities may materially differ from those presently identified.

Although we plan to fund our drilling program primarily with cash flow from operations, if our cash flows are less than we expect or we change our drilling activities, we may be required to borrow under our Credit Facility or issue debt or equity securities in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. See “—Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.” Any drilling activities we are able to conduct on these locations may not be successful, may not result in production or additions to our estimated proved reserves and could result in a downward revision of our estimated proved reserves, which could have a material adverse effect on the borrowing base under our Credit Facility or our future business and results of operations. Additionally, if we curtail our drilling program, we may be required to reduce our estimated proved reserves, which could reduce the borrowing base under our Credit Facility.

Properties that we decide to drill may not yield oil, natural gas and NGLs in commercially viable quantities.

Although we believe that the vast majority of our drilling locations are technically proved, any inability to develop commercially viable quantities will adversely affect our results of operations and financial condition. Properties that we decide to drill that do not yield natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil, natural gas or NGLs in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of geologic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil, natural gas or NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

Seismic data is subject to interpretation and may not accurately identify the presence of drilling hazards, which could adversely affect the results of our drilling operations.

Seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, even if we were to use and interpret seismic data in analyzing our drilling prospects, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.

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Risks Related to Our Operations

Our development projects and acquisitions require substantial capital expenditures. We may be unable to obtain any required capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

The oil and gas industry is capital-intensive. Although we expect to fund our capital budget primarily with cash flow from our operations, a number of factors could cause our cash flow to be less than we expect, including the results of our drilling and completion program. Moreover, our capital budgets are based on a number of assumptions, including drilling and completion costs, midstream service costs, commodity prices and drilling results, and are therefore subject to change. If our cash flows are less than we expect, we decide to pursue acquisitions or we change our capital budgets, we may be required to borrow under our Credit Facility or issue debt or equity securities to consummate such acquisitions or fund our drilling and completion program. The incurrence of additional indebtedness, either through borrowings under our Credit Facility, the issuance of debt securities or otherwise, would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund capital expenditures and acquisitions. The issuance of additional equity securities would be dilutive to our other stockholders. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things: commodity prices; actual drilling results; the availability and cost of drilling rigs and other services and equipment; the availability, cost and adequacy of midstream gathering, processing, compression and transportation infrastructure; and regulatory, technological and competitive developments.

Our cash flow from operations and access to capital are subject to a number of variables, including:

• the prices at which our production is sold;

• the amount of our proved reserves;

• the amount of hydrocarbons we are able to produce from existing wells;

• our ability to acquire, locate and produce new reserves;

• the amount of our operating expenses;

• cash settlements from our derivative activities;

• our ability to borrow under our Credit Facility; and

• our ability to access the capital markets or sell non-core assets.

If our revenues or the borrowing base under our Credit Facility decrease as a result of lower commodity prices, operational difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to make acquisitions or sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our Credit Facility are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which in turn could lead to a decline in our reserves and production and could materially and adversely affect our business, financial condition and results of operations.

Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our development, production and acquisition activities, which are subject to numerous risks beyond our control. For example, we cannot assure you that wells we drill will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil, natural gas and NGLs often involves unprofitable efforts from wells

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that do not produce sufficient oil, natural gas and NGLs to return a profit at then-realized prices after deducting drilling, operating and other costs. In addition, our cost of drilling, completing and operating wells is often uncertain.

Our decisions to develop or purchase prospects or properties will depend, in part, on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”

Further, many factors may increase the cost of, curtail, delay or cancel our scheduled drilling projects, including:

• declines in oil, natural gas and NGL prices;

• increases in the cost of, and shortages or delays in the availability of, proppant, equipment, services and qualified personnel or in obtaining water for hydraulic fracturing activities;

• equipment failures, accidents or other unexpected operational events;

• capacity or pressure limitations on gathering systems, processing and treating facilities or other related midstream infrastructure;

• coal and other mineral ownership permitting issues may impact our ability to develop on our current timeline;

• drilling in the vicinity of coal mining operations and certain other structures;

• any future lack of available capacity on interconnecting transmission pipelines;

• delays imposed by, or resulting from, compliance with regulatory requirements, including limitations on freshwater sourcing, wastewater disposal, emission of greenhouse gases (“GHGs”) and hydraulic fracturing;

• pressure or irregularities in geological formations;

• limited availability of financing on acceptable terms;

• issues related to compliance with or liability arising under environmental laws and regulations;

• environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the environment;

• compliance with contractual requirements;

• competition for surface locations from other operators that may own rights to drill at certain depths across portions of our leasehold;

• adverse weather conditions;

• title issues or legal disputes regarding leasehold rights; and

• other market limitations in our industry.

Some of our properties are in areas that may have been partially depleted or drained by offset (i.e., neighboring) wells, and certain of our wells may be adversely affected by actions other operators may take when drilling, completing or operating wells that they own.

Some of our properties are in areas that may have been partially depleted or drained by earlier drilled offset wells. We have no control over offsetting operators who could take actions such as drilling and completing

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nearby wells, which actions could adversely affect our operations. When a new offset well is completed and produced, reserves previously attributed to offset wells may be produced by the new well which could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. The possibility for these impacts may increase with respect to wells that are shut in as a response to lower commodity prices or the lack of pipeline and storage capacity. In addition, completion operations and other activities conducted on other nearby wells could cause us, in order to protect our existing wells, to shut in production for indefinite periods of time. Shutting in our wells and damage to our wells from offset completions could result in increased costs and could adversely affect the reserves and re-commenced production from such shut in wells as well as the timing of cash flows from impacted wells.

Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells and the unitization or pooling of oil and gas properties. Some states allow the forced pooling or unitization of tracts to facilitate exploration and development, while other states rely on voluntary pooling of lands and leases. Such rules often impact the ultimate timing of our exploration and development plans. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

Part of our business strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques, which include drilling longer laterals and completing wells with larger fluid volumes and higher proppant volumes. The difficulties we face drilling horizontal wells include:

• landing our wellbores in the desired drilling zone;

• staying in the desired drilling zone while drilling horizontally through the formation;

• running casing the entire length of the wellbore;

• potentials for casing failures; and

• being able to run and remove tools and other equipment consistently through the entire length of the wellbore.

Difficulties that we face while completing our wells include:

• the ability to fracture stimulate the planned number of stages with the planned amount of fluid and proppant;

• the ability to run tools through the entire length of the wellbore during completion operations; and

• the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, our development plan calls for completing horizontal wells using greater fluid volumes and substantially higher proppant volumes in addition to drilling additional and longer laterals off of existing well pads, which may increase the risk that these wells interfere with production from existing or future wells in the same spacing section and horizon. This may cause such wells to produce at lower rates than we anticipate and produce lower recoverable reserves. These latest drilling and completion techniques require substantially more capital on a per well basis (when compared to vertical wells), which may result in us drilling and completing fewer wells per year. If our development and production results are less than anticipated, the return on our investment for a particular well or region may not be as attractive as we anticipated, and we could incur material write-downs of our undeveloped acreage, and its value could decline in the future.

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Our ability to produce oil, natural gas and NGLs economically and in commercial quantities is dependent on the availability of adequate supplies of water for drilling and completion operations and access to water and waste disposal or recycling facilities and services at a reasonable cost. Restrictions on our ability to obtain water or dispose of produced water and other waste may have an adverse effect on our financial condition, results of operations and cash flows.

The hydraulic fracturing stimulation process on which we depend to produce commercial quantities of oil, natural gas and NGLs requires the use and disposal of significant quantities of water. The availability of water recycling facilities and other disposal alternatives to receive all of the water produced from our wells may affect our production. Our inability to secure sufficient amounts of water, to dispose of or recycle the water used in our operations or to timely obtain water sourcing permits or other rights could adversely impact our operations. The availability of water may change over time in ways that we cannot control, including as a result of climate change-related effects such as shifting weather patterns. Additionally, the imposition of new environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste and adversely affect our business and operating results.

Our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.

Our producing properties are geographically concentrated in the Appalachian Basin in eastern Ohio and southwestern Pennsylvania. As of December 31, 2023, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by, and costs associated with, governmental regulation, state and local political activities, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

The marketability of certain of our production is dependent upon transportation and other facilities, which we do not control. If these facilities are unavailable, or if there are any increases in the cost of using these services or facilities, our operations could be interrupted, our revenues could be reduced and our costs could increase.

The marketability of certain of our oil, natural gas and NGLs production depends in part upon the availability, proximity and capacity of transportation pipelines, plants and other midstream facilities, which are owned by third parties. Certain of our natural gas production is collected from the wellhead by third-party gathering lines and transported to gas processing or treating facilities and/or transmission pipelines. Our oil and NGLs production in some cases are also dependent on certain midstream infrastructure. We do not control these third-party facilities and our access to them may be limited, curtailed or denied. Economic, regulatory or other issues may affect the construction and availability of needed third-party facilities. These pipelines, plants, and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements, and curtailments of receipts or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. These third-party facilities may experience unplanned downtime or maintenance for a variety of reasons outside our control, and our production could be materially negatively impacted as a result of such outages. Insufficient production from our wells to support the construction of pipeline facilities by third parties or a significant disruption in the availability of third-party midstream facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil, natural gas and NGLs and thereby cause a significant interruption in our operations.

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If, in the future, we are unable, for any sustained period, to implement gathering, treating, processing, fractionation or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations. Additionally, certain of our gas gathering arrangements are subject to cost-of-service fee arrangements. The variable nature of these fee arrangements may result in per unit cost increases over time. If such increases occur, our costs could rise, which would negatively impact our financial results.

The unavailability or high cost of drilling rigs, completion crews, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

The demand for drilling rigs, completion crews, pipe and other equipment and supplies, including sand and other proppant used in hydraulic fracturing operations, as well as for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in our industry, can fluctuate significantly, often in correlation with inflationary pressures, commodity prices or drilling activity in our areas of operation and in other shale basins in the U.S., causing periodic shortages of supplies and needed personnel and rapid increases in costs. Increased drilling activity could materially increase the demand for and prices of these goods and services, and we could encounter rising costs and delays in or an inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to conduct our drilling and development activities, which could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs could have a material adverse effect on our cash flow and profitability.

The loss of one or more of the purchasers of our production could adversely affect our business, results of operations, financial condition and cash flows.

The largest purchaser of our oil and natural gas during the year ended December 31, 2023, accounted for approximately 49% of our total oil, natural gas and NGL revenues. As is typical in our industry, this purchaser’s contract is short-term in nature and is renewed in six-month increments. While we are not substantially dependent on this purchaser’s contract and we believe that we could find replacement purchasers of our oil and natural gas on acceptable terms if any one or more of the significant purchasers were unable to satisfy their contractual obligations, there can be no assurance that we will be able to do so on terms that we consider acceptable or at all. To the extent we are unable to replace such purchasers, it would adversely affect our business, financial condition, results of operations and cash flows. Further, the inability of one or more of our customers to pay amounts owed to us could adversely affect our business, financial condition, results of operations and cash flows.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.

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The success of completed acquisitions will depend on our ability to effectively integrate the acquired businesses into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our Credit Facility imposes certain limitations on our ability to enter into mergers or combination transactions and to incur certain indebtedness, which could indirectly limit our ability to acquire assets and businesses. For additional information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing Agreements—Credit Facility.”

Future legislation or changes in tax laws and regulations may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction, transportation and sales.

We are subject to taxation by various governmental authorities at the federal, state and local levels in the jurisdictions in which we operate. New legislation could be enacted by these governmental authorities, which could increase our tax burden and increase the cost to produce oil, natural gas or NGLs. Members of Congress periodically introduce legislation to revise U.S. federal income tax laws which could have a material impact on us. In the past, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal and state income tax laws, including to certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. Future adverse changes could include, but are not limited to, (a) the repeal of the percentage depletion allowance for oil and natural gas properties, (b) the elimination of current deductions for intangible drilling and development costs, and (c) an extension of the amortization period for certain geological and geophysical expenditures. In addition, federal or state legislation increasing the amount of tax imposed on oil and natural gas extraction, transportation or sales could also be enacted. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or other similar changes to federal or state income tax laws could eliminate or postpone certain tax deductions or credits that are currently available with respect to oil and natural gas exploration and development, which could result in increased operating costs and negatively affect our financial condition, results of operations and cash flows. Additionally, state and local taxing authorities in jurisdictions in which we operate or own assets may enact new taxes, such as the imposition of a severance tax on the extraction of natural resources in states in which we produce natural gas, NGLs and oil or change the rates of existing taxes, which could adversely impact our earnings, cash flows and financial position.

Changes in effective tax rates, or adverse outcomes resulting from other tax increases or an examination of our income or other tax returns, could adversely affect our results of operations and financial condition.

Any changes in our effective tax rates or tax liabilities could adversely affect our results of operations and financial condition. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

• changes in the valuation of our deferred tax assets and liabilities;

• expected timing and amount of the release of any tax valuation allowances;

• expansion into or future activities in new jurisdictions;

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• the availability of tax deductions, credits, exemptions, refunds and other benefits to reduce tax liabilities;

• tax effects of share-based compensation; and

• changes in tax laws, tax regulations, accounting principles, or interpretations or applications thereof.

In addition, we are also subject to the examination of our tax returns by the U.S. Internal Revenue Service (the “IRS”) and other tax authorities. An adverse outcome arising from an examination of our income or other tax returns could result in higher tax exposure, penalties, interest or other liabilities that could have an adverse effect on our operating results and financial condition. We regularly assess the likelihood of an adverse outcome resulting from these examinations to determine the adequacy of our provision for income taxes. Although we believe our tax provisions are adequate, the final determination of tax audits and any related disputes could be materially different from our historical income tax provisions and accruals. The results of audits or related disputes could have an adverse effect on our financial statements for the period or periods for which the applicable final determinations are made.

Continuing or worsening inflationary pressures and associated changes in monetary policy may result in increases to the cost of our goods, services, and personnel, which in turn could cause our capital expenditures and operating costs to rise.

Inflation has been an ongoing concern in the U.S. since 2021. 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. Sustained levels of high inflation could cause the U.S. Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which, or the combination thereof, could hurt the financial and operating results of our business and impact our ability to raise capital.

Our actual operating results and activities could differ materially from the guidance we have disclosed herein.

We have presented herein certain forecasted operating results, costs and activities, including, without limitation, our future expected drilling activity and production. Any such forward-looking guidance represents our management’s estimates as of the date hereof, is based upon a number of assumptions that are inherently uncertain and is subject to numerous business, political, economic, competitive, financial and regulatory risks, including the risks described in this “Risk Factors” section and under “Cautionary Statement Regarding Forward-Looking Statements.” Many of these risks and uncertainties are beyond our control, such as declines in commodity prices and the speculative nature of estimating natural gas and NGL reserves and in projecting future rates of production. If any of these risks and uncertainties actually occur or the assumptions underlying our guidance are incorrect, our actual operating results, costs and activities may be materially and adversely different from our guidance. In addition, investors should also recognize that the reliability of any guidance diminishes the farther in the future that the data is forecast. In light of the foregoing, investors are urged to put our guidance in context and not to place undue reliance upon it.

We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

We are not the operator of all of the properties in which we have an interest. Thus, we have limited ability to exercise influence over the operations of such non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploration activities on properties operated by others will depend upon a number of factors that will be largely outside of our control, including:

• the timing and amount of capital expenditures;

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• the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

• the operator’s expertise and financial resources;

• approval of other participants in drilling wells;

• selection of technology; and

• the rate of production of the reserves.

In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring natural gas or oil properties requires us to assess recoverable reserves; future oil, natural gas and NGL prices and their applicable differentials; development and operating costs and potential liabilities, including environmental liabilities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as expected or may not be accretive to free cash flow. In connection with the assessments, we perform a review of the subject properties, but such a review may not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental concerns, such as any groundwater contamination or pipe corrosion, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are subject to risk and uncertainties, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition.

Our future growth prospects are dependent upon our ability to identify optimal strategies for investing our capital resources to produce superior rates of return. In developing our business plan, we consider allocating capital and other resources to various aspects of our businesses, including well development, reserve acquisitions, exploratory activity, corporate items (including share and debt repurchases) and other alternatives, including investments into new proprietary technologies and strategies surrounding the generation and monetization of environmental attributes from our operations, including but not limited to carbon credit offsets. We also consider likely sources of capital, including cash generated from operations and borrowings under our Credit Facility. Notwithstanding the determinations made in the development of our core business plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions and opportunities to monetize technological improvements to our operations.

If we fail to identify optimal business strategies, optimize our capital investment and capital raising opportunities, use our other resources in furtherance of our business strategies, make appropriate capital investment decisions or anticipate regulatory, policy and market changes associated with any of our strategic determinations, our financial condition and future growth may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our business plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

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We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We maintain insurance against some, but not all, operating risks and losses. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

Our development activities are subject to all of the operating risks associated with drilling for and producing oil, natural gas and NGLs, including, but not limited to, the possibility of:

• environmental hazards, such as unplanned releases of pollution into the environment, including soil, groundwater and air contamination;

• abnormally pressured formations;

• mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

• fires, explosions and ruptures of pipelines;

• personal injuries and death;

• natural disasters; and

• terrorist attacks targeting natural gas and oil related facilities and infrastructure.

Any of these events could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

• injury or loss of life;

• damage to and destruction of property, natural resources and equipment;

• pollution and other environmental damage;

• regulatory investigations and penalties; and

• repair and remediation costs.

We may elect not to obtain insurance for certain of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, risks related to pollution and the environment are generally not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition or results of operations.

Competition in our industry is intense, making it more difficult for us to acquire properties, market oil, natural gas and NGLs, secure trained personnel and raise additional capital.

Our ability to acquire additional oil and gas properties and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil, natural gas and NGLs and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and gas industry. Many of our competitors possess and employ greater financial, technical and personnel resources than we do. Those companies may be able to pay more for natural gas and oil properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. We may not be able to compete successfully in the future in acquiring natural gas and oil properties, developing reserves, marketing our production, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

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The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer-based programs, including our well operations information, geologic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches or attacks, possible consequences include our loss of communication links, inability to find, produce, process and sell oil, natural gas and NGLs, costs associated with incident response or lost employee time and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

Cyberattacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. Our technologies, systems, networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A cyberattack involving our information systems and related infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s, supplier’s or royalty owners’ data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.

In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cybersecurity risks may not be sufficient. As cyberattacks continue to evolve, including those leveraging artificial intelligence, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In addition, new laws and regulations governing data privacy, cybersecurity, and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.

Terrorist activities could materially adversely affect our business and results of operations.

Terrorist attacks, including eco-terrorism, the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response to these acts, could affect the energy industry, the environment and

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industry related economic conditions, including our operations, the operations of our customers, as well as general economic conditions, consumer confidence, spending and market liquidity. Strategic targets, including energy-related assets, may be at greater risk of future attacks than other targets in the United States. The occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially adversely affect our business and results of operations.

A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity, financial condition, results of operations, cash flows and ability to pay dividends on our Class A common stock.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the European, Asian and the U.S. financial markets have contributed to economic volatility and diminished expectations for the global economy. Historically, concerns about global economic growth have had a significant impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and materially adversely impact our results of operations, liquidity, financial condition, results of operations, cash flows and ability to pay dividends on our Class A common stock.

As a private company, we have not been required to document and test our internal controls over financial reporting, nor has our management been required to certify the effectiveness of our internal controls, and our auditors have not been required to opine on the effectiveness of our internal control over financial reporting. We have identified material weaknesses in our internal control over financial reporting which, if not corrected, could affect the reliability of our consolidated financial statements and have other adverse consequences.

A material weakness is a deficiency or combination of deficiencies in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the financial statements would not be prevented or detected on a timely basis.

We have identified material weaknesses in our internal control over financial reporting which relate to: (a) our general segregation of duties, including the review and approval of journal entries; (b) the lack of a formalized risk assessment process; (c) identification and implementation of control activities, including over information technology; (d) identification and application of a sufficient level of formal accounting policies and procedures; and (e) maintaining a sufficient complement of accounting and financial reporting resources commensurate with our financial reporting requirements.

Our management has concluded that these material weaknesses in our internal control over financial reporting are due to the fact that we have operated as a private company with limited resources and have not had the necessary business processes and related internal controls formally designed and implemented coupled with the appropriate resources with the appropriate level of experience and technical expertise to oversee our business processes and controls.

Our management is in the process of developing a remediation plan. The material weaknesses will be considered remediated when our management designs and implements effective controls that operate for a sufficient period of time and management has concluded, through testing, that these controls are effective. Our management will monitor the effectiveness of its remediation plans and will make changes management determines to be appropriate.

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If not remediated, these material weaknesses could result in material misstatements to our annual or interim consolidated financial statements that might not be prevented or detected on a timely basis, or in delayed filing of required periodic reports. If we are unable to assert that our internal control over financial reporting is effective, or when required in the future after the consummation of a business combination, if our independent registered public accounting firm is unable to express an unqualified opinion as to the effectiveness of the internal control over financial reporting, investors may lose confidence in the accuracy and completeness of our financial reports, the market price of the our common stock could be adversely affected and we could become subject to litigation or investigations by the NYSE, the SEC, or other regulatory authorities, which could require additional financial and management resources.

If we fail to develop or maintain an effective system of internal controls over financial reporting, we may not be able to report our financial results accurately and timely or prevent fraud, which may result in material misstatements in our financial statements or failure to meet our periodic reporting obligations. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.

Prior to the completion of this offering, we were a private entity. We have not completed an assessment of the effectiveness of our internal controls over financial reporting, and our independent registered public accounting firm was not required to, and did not, conduct an audit of our internal controls over financial reporting as of December 31, 2023 or 2022. Our internal controls over financial reporting do not currently meet all the standards contemplated by Section 404 of SOX (“Section 404”). Accordingly, we cannot assure you that we have identified all, or that we will not in the future have additional, material weaknesses. If we are not able to implement the requirements of Section 404 in a timely manner or with adequate compliance at the time required, this may cause us to be unable to report on a timely basis and thereby subject us to adverse regulatory consequences, including sanctions by the SEC or violations of applicable stock exchange listing rules.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results may be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock. Additional material weaknesses may be identified in the future. If we identify such issues or if we are unable to produce accurate and timely financial statements, the trading price of our Class A common stock may decline and we may be unable to maintain compliance with the NYSE listing standards.

Risks Related to Our Derivative Transactions, Debt and Access to Capital

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, natural gas and NGLs, we enter into derivative contracts for a significant portion of our projected oil, natural gas

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and NGL production, primarily consisting of swaps. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Derivative Activities.” Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

• production is less than the volume covered by the derivative instruments;

• the counterparty to the derivative instrument defaults on its contractual obligations;

• there is an increase in the differential between the underlying price in the derivative instrument and actual prices received for the sale of our production; or

• there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties and oil, natural gas and NGL prices.

The cost to drill and complete our wells often increases in times of rising commodity prices. To the extent our drilling and completion costs increase but our derivative arrangements limit the benefit we receive from increases in commodity prices, our margins could be limited, which could have a material adverse effect on our financial condition. In addition, the amount we pay in production taxes is calculated without taking our derivative arrangements into account, and if our derivative arrangements limit the benefit we receive from increases in commodity prices, the effective tax rate we pay in production taxes could increase.

Our derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices, our derivative contract receivable positions would generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our derivative contracts.

The failure of our hedge counterparties, significant customers or working interest holders to meet their obligations to us may adversely affect our financial results.

Our hedging transactions expose us to the risk that a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make such party unable to perform under the terms of the derivative contract, and we may not be able to realize the benefit of the derivative contract. Any default by a counterparty to these derivative contracts when they become due could have a material adverse effect on our financial condition and results of operations.

Our ability to collect payments from the sale of oil, natural gas and NGLs to our customers depends on the payment ability of our customer base, which includes several significant customers. If any one or more of our significant customers fail to pay us for any reason, we could experience a material loss. We generally do not require our customers to post collateral, but we are managing our credit risk as a result of the current commodity

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price environment through the attainment of financial assurances from certain customers. In addition, if any of our significant customers cease to purchase our oil, natural gas and NGLs or reduce the volume of the oil, natural gas and NGLs that they purchase from us, the loss or reduction could have a detrimental effect on our revenues and may cause a temporary interruption in sales of, or a lower price for, our oil, natural gas and NGLs.

We also face credit risk through joint interest receivables. Joint interest receivables arise from billing entities who own partial working interests in the wells we operate. Though we often have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings, the inability or failure of working interest holders to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our ability to obtain financing on terms acceptable to us may be limited in the future by, among other things, increases in interest rates.

We require continued access to capital and our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. We may use our Credit Facility to finance a portion of our future growth, and these factors could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Volatility in the global financial markets, significant losses in financial institutions’ U.S. energy loan portfolios, or environmental and social concerns may lead to a contraction in credit availability impacting our ability to finance our operations or our ability to refinance our Credit Facility or other outstanding indebtedness. An increase in interest rates could increase our interest expense and materially adversely affect our financial condition. A significant reduction in cash flow from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

The borrowing base under our Credit Facility may be reduced if commodity prices decline, which could hinder or prevent us from meeting our future capital needs.

Our Credit Facility limits the amounts that we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually in the spring and fall. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Credit Facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments.

In the future, we may not be able to access adequate funding under our Credit Facility (or a replacement facility) as a result of a decrease in the borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has issued final regulations in certain areas, in other

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areas, final regulations and the scope of relevant definitions and/or exemptions still remain to be finalized. On January 24, 2020, U.S. banking regulators published a new approach for calculating the quantum of exposure of derivative contracts under their regulatory capital rules. This approach to measuring exposure is referred to as the standardized approach for counterparty credit risk or SA-CCR. It requires certain financial institutions to comply with significantly increased capital requirements for over-the-counter commodity derivatives beginning on January 1, 2022. In addition, on September 15, 2020, the CFTC issued a final rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, which has a compliance date of October 6, 2021. These two sets of regulations and the increased capital requirements they place on certain financial institutions may reduce the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to end-users like us. The full impact of the Dodd-Frank Act’s swap regulatory provisions and the related rules of the CFTC on our business will not be known until all of the rules to be adopted under the Dodd-Frank Act have been adopted and fully implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

In addition, the European Union and other non-U.S. jurisdictions have implemented and continue to implement regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, which could have adverse effects on our operations similar to the possible effects on our operations of the Dodd-Frank Act’s swap regulatory provisions and the rules of the CFTC.

Risks Related to this Offering, Our Class A Common Stock and Capital Structure

We are a holding company. Our sole material asset after completion of this offering will be our equity interest in INR Holdings and we are accordingly dependent upon distributions from INR Holdings to pay taxes, make payments under the Tax Receivable Agreement and cover our corporate and other overhead expenses.

We are a holding company and will have no material assets other than our equity interest in INR Holdings. “Corporate Reorganization” contains more information. We have no independent means of generating revenue or cash flow, and our ability to pay our taxes and operating expenses (including payments due under the Tax Receivable Agreement) or declare and pay dividends in the future, if any, will be dependent upon the financial results and cash flows of INR Holdings and distributions we receive from INR Holdings. INR Holdings will continue to be treated as a partnership for U.S. federal income tax purposes and, as such, generally will not be subject to any entity-level U.S. federal income tax. Instead, any taxable income of INR Holdings will be allocated to holders of LLC Interests, including us. Accordingly, we will incur income taxes on our allocable share of any net taxable income of INR Holdings. Under the terms of the INR Holdings LLC Agreement, INR Holdings will be obligated, subject to various limitations and restrictions, including with respect to our debt agreements, to make tax distributions to holders of LLC Interests, including us. To the extent INR Holdings has available cash, we intend to cause INR Holdings (a) to generally make pro rata distributions to its unitholders, including us, in an amount at least sufficient to allow us to pay our taxes and make payments under the Tax Receivable Agreement and (b) to reimburse us for our corporate and other overhead expenses through non-pro rata payments that are not treated as distributions under the INR Holdings LLC Agreement. To the extent that we are unable to make payments under the Tax Receivable Agreement for any reason, such payments will be deferred and will accrue interest until paid. We are limited, however, in our ability to cause INR Holdings and its subsidiaries to make these and other distributions to us due to the restrictions under our Credit Facility. To the extent that we need funds and INR Holdings or its subsidiaries are restricted from making such distributions

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under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of SOX, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of SOX, related regulations of the SEC and the requirements of the NYSE, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of our time and will significantly increase our costs and expenses. We will need to:

• institute a more comprehensive compliance function to test and conclude on the sufficiency of our internal controls over financial reporting;

• comply with rules promulgated by the NYSE;

• prepare and distribute periodic public reports;

• establish new internal policies, such as those relating to insider trading; and

• involve and retain to a greater degree outside professionals in the above activities.

Furthermore, while we generally must comply with Section 404, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company.” We may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the year ending December 31, 2030. At any time, we may conclude that our internal controls, once tested, are not operating as designed or that the system of internal controls does not address all relevant financial statement risks. Once required to attest to control effectiveness, our independent registered public accounting firm may issue a report that concludes it does not believe our internal controls over financial reporting are effective. Compliance with SOX requirements may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

There is no existing market for our Class A common stock, and we do not know if one will develop.

Prior to this offering, there has not been a public market for our Class A common stock. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on the stock exchange on which we list our Class A common stock or otherwise or how liquid that market might become. If an active trading market does not develop, anyone purchasing our Class A common stock may have difficulty selling it. The initial public offering price for the Class A common stock was determined by negotiations between us and the representatives of the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, purchasers of our Class A common stock may be unable to sell it at prices equal to or greater than the price paid.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

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Pearl and NGP will collectively hold a substantial majority of our capital stock and voting power.

Upon completion of this offering (assuming no exercise of the underwriters’ option to purchase additional shares), Pearl will own INR Units and corresponding Class B common stock representing approximately 49.3% of our voting power and NGP will own INR Units and corresponding Class B common stock representing approximately 16.4% of our voting power (together representing 65.7% of our combined voting power).

Subject to NGP’s right to nominate one director, Pearl is entitled to elect all of the members of our board of directors based on their voting interest in us, and thereby to control our management and affairs. Further, although Pearl and NGP are entitled to act separately and have no obligation to act together in their own respective interests with respect to their stock in us, they will together have an even greater voting interest in us and ability to control our management and affairs. In addition, they will be able to determine the outcome of all matters requiring shareholder approval, including mergers and other material transactions, and will be able to cause or prevent a change in the composition of our board of directors or a change of control of our company that could deprive our shareholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our company. The existence of significant shareholders may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other shareholders to approve transactions that they may deem to be in the best interests of our company.

So long as Pearl individually or Pearl and NGP, collectively, continue to control a significant amount of our voting power, they will be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of Pearl and NGP may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling stockholder.

Conflicts of interest could arise in the future between us and Pearl, NGP and their respective affiliates, including their portfolio companies concerning conflicts over our operations or business opportunities.

Pearl and NGP are both investment firms and have investments in other companies in the energy industry. As a result, Pearl and NGP may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are our customers or suppliers. As such, Pearl, NGP or their respective portfolio companies may acquire or seek to acquire the same assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our Class A common stock. For additional discussion of potential conflicts of interest of which our stockholders should be aware and a discussion of our related party transactions policy, see “Certain Relationships and Related Party Transactions.”

Certain of our directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Certain of our directors, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities (including Pearl or NGP-affiliated entities) that are in the business of identifying and acquiring oil and natural gas properties. The existing positions held by these directors may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more

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appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see “Certain Relationships and Related Party Transactions.”

Our amended and restated certificate of incorporation (“Amended Charter”) and amended and restated bylaws (“Amended Bylaws”), as well as Delaware law, will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Our Amended Charter will authorize our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our Amended Charter and Amended Bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

• authorizing “blank check” preferred stock that our board of directors could issue to increase the number of outstanding shares to discourage a takeover attempt;

• prohibiting stockholders from acting by written consent at any time when Pearl beneficially owns, in the aggregate, less than 35% in voting power of our common stock;

• limitations on the ability of our stockholders to call special meetings;

• the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock (or a majority of the voting power of all outstanding shares of capital stock if Pearl beneficially owns at least 35% of the voting power of all such outstanding shares) be obtained to amend our Amended Bylaws, to remove directors or to amend our certificate of incorporation;

• providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws; and

• establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

In addition, certain change of control events have the effect of accelerating the payment due under our Tax Receivable Agreement, which could be substantial and accordingly serve as a disincentive to a potential acquirer of our company. “—In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement” contains more information.

Any provision of our Amended Charter, Amended Bylaws or Delaware law that has the effect of delaying, preventing or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their shares of our Class A common stock and could also affect the price that some investors are willing to pay for our Class A common stock. See “Description of Capital Stock—Anti-Takeover Effects of Our Amended Charter, Amended Bylaws and Certain Provisions of Delaware Law.”

Investors in this offering will experience immediate and substantial dilution of $7.02 per share.

Purchasers of our Class A common stock in this offering will experience an immediate and substantial dilution of $7.02 per share in the as adjusted net tangible book value per share of Class A common stock from the initial public offering price, and our as adjusted net tangible book value as of September 30, 2024, on a pro forma basis would be $12.98 per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. “Dilution” contains additional information.

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We cannot assure you that we will be able to pay dividends on our Class A common stock.

Following the completion of this offering, our board of directors may elect to declare cash dividends on our Class A common stock, subject to our compliance with applicable law, and depending on, among other things, economic conditions, our financial condition, results of operations, projections, liquidity, earnings, legal requirements, and restrictions in the agreements governing our indebtedness (as further discussed below). The payment of any future dividends will be at the discretion of our board of directors. The declaration and amount of any future dividends is subject to the discretion of our board of directors, and we have no obligation to pay any dividends at any time. We have not adopted, and do not currently expect to adopt, a written dividend policy. Our ability to pay dividends depends on our receipt of cash dividends from our operating subsidiaries, which may further restrict our ability to pay dividends as a result of the laws of their jurisdiction of organization, agreements of our subsidiaries or covenants under any existing and future outstanding indebtedness we or our subsidiaries incur.

Our Credit Facility contains restrictions on the payment of dividends. Such restrictions allow us to pay dividends after the completion of this offering only when certain conditions are met, including certain required leverage ratio and financial metrics. For additional information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing Agreements—Credit Facility.” Due to the foregoing, we cannot assure you that we will be able to pay a dividend in the future or continue to pay a dividend after we commence paying dividends.

Future sales of our Class A common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may issue additional shares of Class A common stock or convertible securities in subsequent public offerings. After the completion of this offering, assuming the underwriters’ option to purchase additional shares is fully exercised, we will have 15,237,500 shares of Class A common stock outstanding and 45,638,889 shares of Class B common stock outstanding. This number includes 13,250,000 shares of Class A common stock that we are selling in this offering and the 1,987,500 shares of Class A common stock that we may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, Pearl and NGP will own 38,526,173 INR Units and the corresponding shares of Class B common stock, representing approximately 65.4% (or 63.3% if the underwriters’ option to purchase additional shares is exercised in full) of our total outstanding capital stock. All such shares are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between such parties and the underwriters described in “Underwriting (Conflicts of Interest)” but may be sold into the market in the future.

Certain of the Existing Owners will be party to a registration rights agreement with us that will require us to effect the registration of their shares in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. “Shares Eligible for Future Sale” and “Certain Relationships and Related Party Transactions—Registration Rights Agreement” contain more information.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

We will limit the liability of, and indemnify, our directors and officers.

Although our directors and officers are accountable to us and must exercise good faith, good business judgement and integrity in handling our affairs, our amended and restated certificate of incorporation and the

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indemnification agreements that we intend to enter into with all of our non-employee directors and officers will provide that our non-employee directors and officers will be indemnified to the fullest extent permitted under Delaware law. As a result, our stockholders may have fewer rights against our non-employee directors and officers than they would have absent such provisions in our Amended Charter and indemnification agreements, and a stockholder’s ability to seek and recover damages for a breach of fiduciary duties may be reduced or restricted.

Pursuant to our Amended Charter and indemnification agreements, each non-employee director and officer who is made a party to a legal proceeding because he or she is or was a non-employee director or officer, is indemnified by us from and against any and all liability, except that we may not indemnify a non-employee director or officer: (i) for breach of the director’s or officer’s duty of loyalty to the Corporation or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) with respect to any director, pursuant to Section 174 of the General Corporation Law of the State of Delaware, (iv) for any transaction from which the director or officer derived an improper personal benefit or (v) with respect to any officer, in any action by or in the right of INR. We will be required to pay or reimburse attorney’s fees and expenses of a non-employee director or officer seeking indemnification as they are incurred, provided the non-employee director or officer executes an agreement to repay the amount to be paid or reimbursed if there is a final determination by a court of competent jurisdiction that such person is not entitled to indemnification.

The representatives of the underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our Class A common stock.

We, the Existing Owners and all of our directors and executive officers have entered into lock-up agreements with respect to their ownership of Class A common stock and Class B common stock, pursuant to which we and they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part. The representatives of the underwriters, at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then Class A common stock will be available for sale into the public markets, which could cause the market price of our Class A common stock to decline and impair our ability to raise capital. “Underwriting (Conflicts of Interest)” provides additional information regarding the lock-up agreements.

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For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. In addition, we have reduced SOX compliance requirements, as discussed elsewhere, for as long as we are an emerging growth company, which may be up to five full fiscal years. Unlike other public companies, we will not be required to, among other things, (a) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (b) provide certain disclosure regarding executive compensation required of larger public companies or (c) hold nonbinding advisory votes on executive compensation.

Because we have elected to take advantage of the extended transition period pursuant to Section 107 of the JOBS Act, our financial statements may not be comparable to those of other public companies.

Section 107 of the JOBS Act provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are choosing to take advantage of this extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies. Accordingly, our financial statements may not be comparable to companies that comply with public company effective dates, and our stockholders and potential investors may have difficulty in analyzing our operating results by comparing us to such companies.

We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.

Our Amended Charter will authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.

Terms of subsequent financings may adversely impact stockholder equity.

If we raise more equity capital from the sale of Class A common stock, institutional or other investors may negotiate terms more favorable than the current prices of our Class A common stock. If we issue debt securities, the holders of the debt would have a claim to our assets that would be prior to the rights of stockholders until the debt is paid. Interest on these debt securities would increase costs and could negatively impact our operating results.

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If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our Class A common stock or if our operating results do not meet their expectations, our stock price could decline.

Our Amended Charter will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to bring a claim in a different judicial forum for disputes with us or our directors, officers, employees or agents.

Our Amended Charter will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (a) any derivative action or proceeding brought on our behalf, (b) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (c) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our Amended Charter or Amended Bylaws, or (d) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Notwithstanding the foregoing sentence, the federal district courts of the United States of America shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under U.S. federal securities laws, including the Securities Act and the Exchange Act. This choice of forum may limit a stockholder’s ability to bring a claim in a different judicial forum for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our Amended Charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial condition or results of operations.

We will be required to make payments under the Tax Receivable Agreement for certain tax benefits we may claim, and the amounts of such payments could be significant.

In connection with the consummation of this offering, we will enter into a Tax Receivable Agreement with the Existing Owners. This agreement generally provides for the payment by us to the Existing Owners of 85% of the net cash savings, if any, in U.S. federal, state and local income tax that Infinity Natural Resources (a) actually realizes with respect to taxable periods ending after this offering or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of Infinity Natural Resources board) or if the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of INR Units and the corresponding surrender of an equivalent number of shares of Class B common stock by the Existing Owners for a number of shares of Class A common stock on 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 Tax Receivable Agreement. Infinity Natural Resources will retain the benefit of the remaining 15% of these cash savings, if any. If we experience a change of control or the Tax Receivable Agreement terminates early, we could be required to make a substantial, immediate lump-sum payment. “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” contains more information.

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The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of INR Holdings. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The amounts payable, as well as the timing of any payments, under the Tax Receivable Agreement are dependent upon future events and assumptions, including the timing of the exchanges of INR Units along with surrendering a corresponding number of our Class B common stock, the price of our Class A common stock at the time of each exchange, the extent to which such exchanges are taxable transactions, the amount of the exchanging INR Unit Holder’s tax basis in its INR Units at the time of the relevant exchange, the depreciation, depletion and amortization periods that apply to the increase in tax basis, the amount and timing of taxable income we generate in the future, the U.S. federal, state and local income tax rates then applicable, and the portion of Infinity Natural Resources’ payments under the Tax Receivable Agreement that constitute imputed interest or give rise to depreciable, depletable or amortizable tax basis. We expect that the payments that we will be required to make under the Tax Receivable Agreement could be substantial. Any payments made by us to the Existing Holders under the Tax Receivable Agreement will not be available for reinvestment in INR Holdings (or indirectly, its business) and generally will reduce the amount of overall cash flow that might have otherwise been available to us. The term of the Tax Receivable Agreement will commence upon the completion of this offering and will continue until all such tax benefits have been utilized or expired and all required payments are made, unless we exercise our right to terminate the Tax Receivable Agreement (or the Tax Receivable Agreement is terminated due to other circumstances, including our breach of a material obligation thereunder or certain mergers or other changes of control) by making the termination payment specified in the agreement. In the event that the Tax Receivable Agreement is not terminated, the payments under the Tax Receivable Agreement are not anticipated to commence until 2030 at the earliest (with respect to the tax year 2025).

The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in us or INR Holdings. In addition, certain rights under the Tax Receivable Agreement (including the right to receive payments) will be transferable in connection with transfers permitted thereunder. “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” contains more information.

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits we realize, if any, in respect of the tax attributes subject to the Tax Receivable Agreement.

If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the Infinity Natural Resources board) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach), we could be required to make a substantial, immediate lump-sum payment. This payment would equal the present value of hypothetical future payments that could be required under the Tax Receivable Agreement. The calculation of the hypothetical future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including (a) the sufficiency of taxable income to fully utilize the tax benefits, (b) any INR Units (other than those held by us) outstanding on the termination date are exchanged on the termination date and (c) the utilization of certain loss carryovers. Our ability to generate net taxable income is subject to substantial uncertainty. Accordingly, as a result of the assumptions, the required lump-sum payment may be significantly in advance of, and could materially exceed, the realized future tax benefits to which the payment relates. This payment obligation could (i) make us a less attractive target for an acquisition, particularly in the case of an acquirer that cannot use some or all of the tax benefits that are the subject of the Tax Receivable Agreement and (ii) result in holders of our Class A common stock receiving substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. Accordingly, the Existing Owners’ interests may conflict with those of the holders of our Class A common stock.

As a result of either an early termination or a change of control, we could be required to make payments under the Tax Receivable Agreement that exceed our actual cash tax savings under the Tax Receivable

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Agreement. Consequently, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control. For example, assuming no material changes in the relevant tax law, we expect that if we experienced a change of control or the Tax Receivable Agreement were terminated immediately after this offering, the estimated lump-sum payment to the Existing Owners would be approximately $134.3 million (calculated using a discount rate equal to a per annum rate of 150 basis points, applied against an undiscounted liability of approximately $169.5 million), including approximately $6.8 million to each of our Chief Executive Officer and Chief Financial Officer, approximately $80.9 million to Pearl, approximately $27.0 million to NGP and the remainder to other members of management. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

In the event that our payment obligations under the Tax Receivable Agreement are accelerated upon certain mergers, other forms of business combinations or other changes of control, the consideration payable to holders of our Class A common stock could be substantially reduced.

If we experience a change of control (as defined under the Tax Receivable Agreement), our obligation to make a substantial, immediate lump-sum payment could result in holders of our Class A common stock receiving substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. The amount due will be equal to the present value of the anticipated future tax benefits that are the subject of the Tax Receivable Agreement, based on certain assumptions outlined in the Tax Receivable Agreement (including the discount rate to be used and that we will have sufficient taxable income to realize all potential tax benefits that are subject to the Tax Receivable Agreement), which payment may be made significantly in advance of the actual realization, if any, of such future tax benefits. Such cash payment to the Existing Holders could be greater than the specified percentage of any actual benefits we ultimately realize in respect of the tax benefits that are subject to the Tax Receivable Agreement. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control. Further, holders of rights under the Tax Receivable Agreement may not have an equity interest in us or INR Holdings. Accordingly, the interests of holders of rights under the Tax Receivable Agreement may conflict with those of the holders of our Class A common stock. Please read “Risk Factors—In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits we realize, if any, in respect of the tax attributes subject to the Tax Receivable Agreement” and “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.” There can be no assurance that we will be able to fund or finance our obligations under the Tax Receivable Agreement. We may need to cause INR Holdings to incur debt and make distributions to the holders of LLC Interests, including us, to finance payments under the Tax Receivable Agreement to the extent our cash resources are insufficient to meet our obligations under the Tax Receivable Agreement as a result of timing discrepancies or otherwise.

We will not be reimbursed for any payments made under the Tax Receivable Agreement in the event that any tax benefits are subsequently disallowed.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine, which are complex and factual in nature, and the IRS or another tax authority may challenge all or part of the tax basis increases upon which payments under the Tax Receivable Agreement are based, as well as other related tax positions that we take, and a court could sustain such challenge. The holders of rights under the Tax Receivable Agreement will not reimburse us for any payments previously made under the Tax Receivable Agreement if such basis increases or other benefits are subsequently disallowed, except that excess payments made to any such holder will be netted against payments otherwise to be made, if any, to such holder after our determination of such excess. However, we might not determine that we have effectively made an excess cash payment to an Existing Owner for a number of years following the initial time of such payment and, if any of our tax reporting positions are challenged by a taxing authority, we will not be permitted to reduce any future cash payments under the Tax Receivable Agreement until any such challenge is finally settled or determined. As a

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result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity. The applicable U.S. federal income tax rules for determining applicable tax benefits we may claim are complex and factual in nature, and there can be no assurance that the IRS or a court will not disagree with our tax reporting positions. As a result, payments could be made under the Tax Receivable Agreement significantly in excess of any actual cash tax savings that we realize in respect of the tax attributes with respect to an Existing Owner that are the subject of the Tax Receivable Agreement.

If INR Holdings were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and INR Holdings might be subject to potentially significant tax inefficiencies, and we would not be able to recover payments previously made by us under the Tax Receivable Agreement even if the corresponding tax benefits were subsequently determined to have been unavailable due to such status.

We intend to operate such that INR Holdings does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, exchanges of INR Units pursuant to the Exchange Right or other transfers of INR Units could cause INR Holdings to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that exchanges or other transfers of INR Units qualify for one or more such safe harbors.

If INR Holdings were to become a publicly traded partnership, significant tax inefficiencies might result for us and for INR Holdings, including as a result of our inability to file a consolidated U.S. federal income tax return with INR Holdings. In addition, we would no longer have the benefit of certain increases in tax basis covered under the Tax Receivable Agreement, and we would not be able to recover any payments previously made by us under the Tax Receivable Agreement, even if the corresponding tax benefits (including any claimed increase in the tax basis of INR Holdings’ assets) were subsequently determined to have been unavailable.

In certain circumstances, INR Holdings will be required to make tax distributions to us and the INR Unit Holders, and the tax distributions that INR Holdings will be required to make may be substantial.

INR Holdings will 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 will be allocated to the INR Unit Holders and us. Pursuant to the INR Holdings LLC Agreement, INR Holdings will generally make pro rata cash distributions, or tax distributions, to the INR Unit Holders and us, calculated using the highest marginal tax rate applicable to a corporation doing business in Morgantown, West Virginia. However, the board of managers of INR Holdings may determine to increase the tax rate applicable to tax distributions by INR Holdings.

Funds used by INR Holdings to satisfy its tax distribution obligations will not be available for reinvestment in our business. Moreover, the tax distributions that INR Holdings will be required to make may be substantial.

The Existing Owners’ interests may not be fully aligned with the interests of the holders of our Class A common stock.

The Existing Owners’ interests may not be fully aligned with yours, which, due to the concentrated ownership of our common stock by the Existing Owners, could lead to actions that are not in your best interests. Because the Existing Owners hold their economic interest in our business primarily through INR Holdings, the Existing Owners may have conflicting interests with holders of shares of our Class A common stock. For example, the Existing Owners may have different tax positions from us, which could influence their decisions regarding whether and when we should dispose of assets or incur new or refinance existing indebtedness, especially in light of the existence of the Tax Receivable Agreement that we will enter into in connection with

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this offering, and whether and when we should respond to a breach of any of our material obligations under the Tax Receivable Agreement, undergo certain changes of control for purposes of the Tax Receivable Agreement or terminate the Tax Receivable Agreement. In addition, the structuring of future transactions may take into consideration these tax or other considerations even where no similar benefit would accrue to us. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

Further, pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to INR Holdings’ U.S. federal income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from INR Holdings rather than from the Existing Owners directly, in which case we may economically bear a portion of such taxes (including any applicable penalties and interest) even though we did not economically benefit from the income giving rise to such taxes. INR Holdings may be permitted to make an election which would have the effect of requiring the IRS to collect any such taxes (including penalties and interest) from the members of INR Holdings (including the Existing Owners), rather than from INR Holdings, but there can be no assurance that INR Holdings will be permitted to or will make this election. If, as a result of any such audit adjustment, INR Holdings is required to make payments of taxes, penalties and interest, INR Holdings’ cash available for distributions to us may be substantially reduced. These rules are not applicable to INR Holdings for tax years beginning on or prior to December 31, 2017.

Further, the Existing Owners, who will be the only holders of INR Units other than us upon consummation of this offering, have the right to consent to certain amendments to the INR Holdings LLC Agreement, as well as to certain other matters. The Existing Owners may exercise these voting rights in a manner that conflicts with the interests of the holders of our Class A common stock. In addition, following this offering, Pearl, one of the Existing Owners, will hold a number of shares of our non-economic Class B common stock that will allow it to control our overall management and direction. Circumstances may arise in the future when the interests of the Existing Owners conflict with the interests of our stockholders.

Risks Related to Environmental and Regulatory Matters

Our operations are subject to stringent environmental, health and safety laws and regulations that may expose us to significant costs and liabilities that could exceed current expectations.

We are subject to stringent and complex federal, state and local environmental, health and safety (“EHS”) laws and regulations, including laws and regulations governing the discharge of materials into the environment, emissions controls and other environmental protection and occupational health and safety concerns. Any discharge by us of natural gas, NGLs, oil and other pollutants into the air, soil or water may give rise to liabilities on our part to the government and third parties. Environmental laws and regulations, such as the Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”) and comparable state laws, may impose strict, retroactive and joint and several, liability for environmental contamination, including the release of hazardous substances, which could render us potentially liable for remediation costs, damage to natural resources or other damages, without regard to fault or the legality of the conduct at the time of the release or if contamination was caused by prior owners, operators or other third parties. Governmental agencies, citizen organizations, neighboring landowners and other third parties could file claims for personal injury, property damage and recovery of response costs. Remediation costs and other damages arising as a result of environmental laws and regulations, and costs associated with changes to existing EHS laws and regulations or the interpretation thereof, or the adoption of new environmental laws and regulations over time could adversely impact our financial condition or results of operations. Moreover, any failure by us to comply with applicable EHS laws and regulations could result in the imposition of administrative, civil or criminal penalties or the issuance of injunctions that could delay or prohibit operations, which could in turn have an adverse impact on our business.

We are required to hold certain U.S. federal, state or local EHS permits or other authorizations and may require new or amended facility permits or licenses from time to time, including with respect to stormwater

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discharges, waste handling and disposal, or air emissions, which may subject us to new or revised permitting conditions that may be onerous or with which it may be costly to comply. These permits and authorizations often contain numerous compliance requirements, including monitoring and reporting obligations and operational restrictions, such as emissions limits. Given the number of EHS permits and other authorizations that are applicable to our operations, we may occasionally identify or be notified of violations of or noncompliance with certain requirements existing under various permits or may be required to obtain additional permits. Noncompliance with necessary permits or the failure to obtain additional permits could subject us to future penalties, operating restrictions, or delays in obtaining new or amended permits or permit renewals that could have a material adverse effect on our business, financial condition or results of operations.

EHS laws and regulations are constantly evolving and may become increasingly complicated and more stringent in the future. In addition, new or additional laws and regulations, new interpretations of existing requirements or changes in enforcement policies could impose unforeseen liabilities, significantly increase compliance costs, or result in delays of, or denial of rights to conduct, our development programs. For example, in June 2015, the Environmental Protection Agency (the “EPA”) and the U.S. Army Corps of Engineers (the “Corps”) issued a rule under the Clean Water Act (the “CWA”) defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the United States (“WOTUS”), which was repealed in December 2019 and replaced in June 2020 by the Navigable Waters Protection Rule (the “NWPR”) before ever taking effect. A coalition of states and cities, environmental groups and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021. In January 2023, the EPA and the Corps issued a final rule to revise the definition of WOTUS to put back into place the pre-2015 definition; however, this definition of WOTUS was impacted by the U.S. Supreme Court’s decision issued in May 2023 in Sackett v. EPA, wherein the Court held that the jurisdiction of the CWA extends only to those adjacent wetlands that are indistinguishable from traditional navigable bodies of water due to a continuous surface connection. In September 2023, the EPA and the Corps published a direct-to-final rule redefining WOTUS to amend the January 2023 rule and align with the decision in Sackett. Subsequent litigation from certain states and individuals is ongoing and seeks to vacate the September 2023 rule. To the extent a new rule or further litigation expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Such potential regulations or litigation could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which in turn could materially adversely affect our results of operations and financial position.

Future EHS laws and regulations (or changes to existing laws and regulations or their interpretation) may also negatively impact natural gas and oil exploration, production, gathering and transportation companies, which in turn could have a material adverse effect on our business, financial conditions and results of our operations.

We may be involved in legal and regulatory proceedings that could result in substantial liabilities.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury, environmental damage or property damage matters, in the ordinary course of our business. Such legal and regulatory proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management or other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in civil or criminal liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results or financial condition. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material. As of September 30, 2024, we are not aware of any potentially material legal proceeding that has been brought against the Company.

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Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and adversely affect our business.

More stringent laws and regulations relating to climate change and GHG emissions may arise from a variety of sources, including international, national, regional and state levels of government and associated administrative bodies and could cause us to incur material expenses to comply with such laws and regulations. In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment and in the absence of comprehensive federal legislation on GHG emission control, the EPA has adopted regulations pursuant to the federal Clean Air Act (the “CAA”) to reduce GHG emissions from various sources, but the future of these regulations is not clear. The EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil, natural gas and NGL production sources in the U.S. on an annual basis, which include certain segments of our operations. The EPA published a final rule in March 2024, entitled Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, which went into effect in May 2024 and requires, among other things, the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions), standardization of installation and maintenance of emission control devices, and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. Compliance with these and other air pollution control monitoring and permitting requirements, along with the required associated technical investments, has the potential to delay the development of natural gas projects and increase our costs of development, which costs could be significant.

Additionally, some states have issued mandates to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and potential cap-and-trade programs. For example, Pennsylvania has taken steps to bring the state into a consortium of Northeastern and Mid-Atlantic States, the Regional Greenhouse Gas Initiative (“RGGI”), that sets price and declining limits on CO2 emissions from power plants. In December 2021, the Pennsylvania Attorney General approved a proposed regulation which would allow Pennsylvania to join RGGI. Given legal challenges and general political controversy and pushback, the future of RGGI is unclear. Additionally, in March 2024, the Pennsylvania Governor unveiled the Pennsylvania Climate Emissions Reduction Initiative and it was later introduced in the Pennsylvania General Assembly in May 2024. This proposal would adopt a RGGI-like carbon-pricing program for the state, and the Governor stated he would withdraw Pennsylvania from RGGI if the Pennsylvania General Assembly enacts his proposal. Most of these types of programs require major sources of emissions or major producers of fuels to acquire and subsequently surrender emission allowances, with the number of allowances available being reduced each year until a target goal is achieved. The cost of these allowances could increase over time. While new laws and regulations that are aimed at reducing GHG emissions could increase demand for natural gas, they may also result in increased costs for permitting, equipping, monitoring and reporting GHGs associated with natural gas production and use.

Internationally, the United Nations-sponsored Paris Agreement (the “Paris Agreement”) requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. President Biden signed the instrument recommitting the U.S. to the Paris Agreement in January 2021 and, in April 2021, announced a goal of reducing U.S. emissions by 50-52% below 2005 levels by 2030. In September 2021, President Biden publicly announced the “Global Methane Pledge,” an international pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. Further, at the 28th Conference of the Parties (“COP28”) in December 2023, member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the agreement, among other things,

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are to accelerate efforts toward the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies and take other measures that drive the transition away from fossil fuels in energy systems. While non-binding, the agreements coming out of COP28 and future COPs could result in increased pressure on financial institutions and various stakeholders to reduce or otherwise impose more stringent limitations on funding for, and increase potential opposition to, the exploration and production of fossil fuels. Various state and local governments have also vowed to continue to enact regulations to satisfy their proportionate obligations under the Paris Agreement. Other actions that could be pursued include more restrictive requirements for the development of pipeline infrastructure or LNG export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities. For example, in January 2024, President Biden announced a temporary pause on pending decisions on new exports of LNG to countries that the U.S. does not have free trade agreements with, pending Department of Energy review of the underlying analyses for authorization, including an assessment of the impact of GHG emissions. In a July 2024 ruling, the Western District of Louisiana stayed this temporary pause on LNG exports to non-free trade agreement countries. The Biden Administration appealed the ruling in August 2024 and the litigation remains ongoing. We cannot predict whether the pause may be reinstated. This and other changes in law and governmental policy may have impacts on our business that are difficult to anticipate.

In addition, the SEC adopted its final rules for climate-related disclosures in March 2024 (the “SEC Climate Rules”), which will mandate detailed disclosure of certain climate-related information, including, among other items, material climate-related risks and related governance, strategy and risk management processes, certain financial statement disclosures, and Scopes 1 and 2 GHG emissions, if material, for certain public companies. The SEC Climate Rules are currently stayed pending legal challenges and are widely expected to face additional legal challenges going forward. For these reasons, we cannot currently predict with certainty the timing and costs of implementation or any potential adverse impacts resulting therefrom. However, assuming that the SEC Climate Rules take effect, they may result in our experiencing additional operational and compliance burdens and incurring significant additional costs relating to the assessment and disclosure of climate- and sustainability-related matters, including costs relating to establishment of additional internal controls and collecting, measuring and analyzing information relating to such matters. Similar burdens could affect our customers, resulting in lower demand for our products. Further, enhanced climate-related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the uncertainties and estimations involved in calculating and reporting GHG emissions. The SEC has also from time to time applied additional scrutiny to existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures are misleading or deficient.

More broadly, the adoption and implementation of new or more stringent international, federal, state, or local legislation, regulations or other regulatory initiatives related to climate change or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for our products, and could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory requirements, and to monitor and report on GHG emissions. Additionally, political, litigation, and financial risks may result in (a) restriction or cancellation of certain oil and natural gas production activities, (b) incurrence of obligations for alleged damages resulting from climate change or (c) impairment of our ability to continue operating in an economic manner. To the extent that governmental entities in the U.S. or other countries implement or impose climate change regulations on the oil and gas industry, it could have a material adverse effect on the Company’s business, including by restricting the Company’s ability to execute on its business strategy; requiring additional capital, compliance, operating and maintenance costs; increasing the cost of the Company’s products and services; reducing demand for its products and services; reducing its access to financial markets or creating greater potential for governmental investigations or litigation. While the Supreme Court’s decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. and end the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, many

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of these initiatives are expected to continue. Consequently, legislation and regulatory programs to address climate change or reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs, additional operating restrictions or delays, limits to the areas in which we can operate and reductions in our oil, natural gas and NGL production, which could adversely affect our production and business.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations, as does much of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the U.S. Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities. In addition, the EPA finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. New federal legislation regulating hydraulic fracturing may be considered again in the future. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, Ohio, Pennsylvania and West Virginia have each adopted a law requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells, and Ohio requires oil and natural gas operators to conduct pre-drill baseline water quality sampling of certain water wells near a proposed horizontal well. Unlike Ohio, Pennsylvania does not require oil and natural gas operators to conduct pre-drilling water supply sampling, but Pennsylvania law incentivizes testing as such sampling can preserve a legal defense regarding pollution of water supply. Additional states could also decide to place prohibitions on hydraulic fracturing. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have banned and others seek to ban hydraulic fracturing altogether. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays, curtailment in or exclusion from the pursuit of exploration, development or production activities.

Prolonged negative investor sentiment toward upstream oil and natural gas focused companies could limit our access to capital funding, damage our reputation and adversely impact our business, financial condition and results of operations.

Certain segments of the investor community have developed negative sentiment toward investing in our industry. There have been efforts in recent years, for example, to influence the investment community, including investment advisors, insurance companies and certain sovereign wealth, pension and endowment funds and other groups, by promoting divestment of fossil fuel equities and pressuring lenders to limit funding and insurance underwriters to limit coverages to companies engaged in the extraction of fossil fuel reserves. The lending and investment practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists and foreign citizenry concerned about climate change. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the natural gas and oil sector based on social and environmental considerations. There is also a risk that financial institutions may be required to adopt policies that

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have the effect of reducing the funding provided to the fossil fuel sector. Certain commercial and investment banks based both domestically and internationally have announced that they are adopting climate change guidelines for their banking and investing activities, often in connection with increased regulatory expectations and requirements, which may result in them limiting funding for natural gas and oil projects. Institutional lenders who provide financing to energy companies have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. Ultimately, these developments could reduce the availability of capital funding to us for potential development projects or to refinance our existing indebtedness, each of which could have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows.

Legislation or regulatory initiatives intended to address seismic activity, as well as government reviews of such activities, could restrict our drilling and production activities, as well as our ability to dispose of saltwater produced from such activities, which could limit our ability to produce oil, natural gas and NGLs economically and have a material adverse effect on our business.

Local, state and federal regulatory agencies, including in Pennsylvania and Ohio, have in the past focused on a possible connection between hydraulic fracturing-related activities, particularly the underground injection of wastewater into disposal wells and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, several lawsuits have been filed in some states, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states and local municipalities, including in Pennsylvania, are seeking to impose or have imposed additional requirements, including obligations regarding the permitting of produced water disposal wells or otherwise assessing the relationship between seismicity and the use of such wells. To the extent any new regulations are adopted to restrict hydraulic fracturing activities or the disposal of fluids associated with such activities, it may adversely affect our business, financial condition and results of operations.

We dispose of some of the saltwater produced from our drilling and production operations by injecting it into wells pursuant to permits issued to us and third parties by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of saltwater produced from our drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Our operations may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife species and/or habitats. The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species and similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”) and other federal and state statutes. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in material restrictions to land use and may materially delay or prohibit land access for drilling activities. In April 2024, the U.S. Fish and Wildlife Service finalized three rules governing critical habitat designation and expanding protection options for species listed as threatened pursuant to the ESA. Among other changes to the rules, a determination of whether a species is threatened or endangered will be made “without reference to possible economic or other impacts of such determination,” and protections

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that are granted to species found to be endangered will be automatically extended to species found to be threatened. The revised rules also make it easier to designate areas as critical for a species’ survival, even if the species is no longer found in those areas. Like the ESA, similar protections are offered to migratory birds under MBTA, which makes it illegal to, among other things, hunt, capture, kill, possess, sell or purchase migratory birds, nests or eggs without a permit. This prohibition covers most bird species in the U.S.

These rules, and any future rules, could materially affect our operations and development. For instance, permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. A critical habitat or suitable habitat designation in areas where we conduct our business could result in material restrictions to land use and may materially delay, or prohibit land access for, oil, natural gas and NGL development. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations.

We are subject to risks related to climate change, which could have a material adverse effect on our business, financial condition and results of operations.

Increasing attention from governmental and regulatory bodies, investors, consumers, industry and other stakeholders on combating climate change, together with technological advances in fuel economy and energy generation devices as well as climate change activism, governmental requirements and societal expectations on companies to address climate change, may create new competitive conditions that result in reduced demand for the oil, natural gas or NGLs we produce for our customers’ products. Such requirements, advancements and expectations may include, for instance, requirements to implement fuel conservation measures, regulations favoring renewable energy resources, increasing consumer demand for alternative forms of energy and lower emission products or services and other changes in consumer behavior. The potential impact of changing demand for oil, natural gas or NGLs services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows or those of the customers we serve, which could, in turn, affect demand for our products. Such developments may also adversely impact, among other things, the availability of necessary third-party services and facilities as well as market prices of, or our access to, raw materials such as energy and water, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy. Further, the enactment of climate change-related policies and initiatives across the market at the corporate level and/or investor community level may in the future result in increases in our compliance costs and other operating costs and have other adverse effects (e.g., greater potential for governmental investigations or litigation, reductions in demand for our products or stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels).

Furthermore, negative public perception regarding the oil and gas industry resulting from, among other things, concerns raised by advocacy groups about climate change, emissions, hydraulic fracturing, seismicity or oil spills may lead to increased litigation risk and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation for us or our customers, thereby reducing demand for our products.

Finally, many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere produce climate changes that may have significant physical effects, such as increased frequency and severity of storms, droughts, floods or other climatic events. Such effects could adversely affect or delay demand for our products, or our customers’ products, or cause us to incur significant costs in preparing for, or responding to, the effects thereof. Energy needs could increase or decrease as a result of weather conditions, depending on the duration and magnitude of any such weather events, and adversely impact our operating costs or revenues. To the

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extent the frequency of extreme weather events increases, due to climate change or otherwise, this could impact operations in various ways, including damage to or disruption of operations at our facilities, increased insurance premiums or increases to the cost of providing service, reduced availability of electrical power, road accessibility and transportation facilities, as well as impacts on personnel, supply chain, distribution chain or customers, as well as potentially increased costs for, or difficulty procuring, consistent levels of insurance coverages in the aftermath of such effects. Such physical risks may also impact the infrastructure on which we rely to produce or transport our products. In addition, while our consideration of changing weather conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or been prepared for every eventuality. Further, demand for our products, or our customers’ products, may increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate changes, such as to the extent warmer weathers reduce the demand for energy for heating purposes. The effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. If any such effects were to occur as a result of climate change or otherwise, they could have a material adverse effect on our assets, our financial condition and our results of operations. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a diversified portfolio of properties.

Increasing attention to Environmental, Social and Governance (“ESG”) and sustainability matters may expose us to additional risk, which could have an adverse effect on our business, financial condition and results of operations and damage our reputation.

In recent years, companies across all industries are facing increasing scrutiny from a variety of stakeholders, including investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies, related to their ESG and sustainability practices. If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters (including with respect to climate change) as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected.

Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events, or forecasts of expected risks or events, including the costs associated therewith. ESG-related disclosure continues to emerge as an area where we may be, or may become, subject to required disclosures in certain jurisdictions, depending on our purported nexus to such jurisdictions and any such mandatory disclosures may similarly necessitate the use of hypothetical, projected or estimated data, some of which is not controlled by us and is inherently subject to imprecision. Disclosures reliant upon such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation, given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Failure or a perception of failure to implement our ESG strategy or achieve sustainability goals and targets we have set, including emissions reduction targets, could damage our reputation, causing our investors or consumers to lose confidence in us and negatively impacting our operations. Our continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy, including any ESG goals, may also create additional operational risks and expenses and expose us to reputational, legal and other risks.

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Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

While our pipeline systems have not been regulated by FERC under the Natural Gas Act of 1938 (“NGA”) or the Natural Gas Policy Act of 1978 (“NGPA”), FERC has adopted certain regulations and policies that may subject certain of our otherwise non-FERC jurisdictional facilities to market transparency, anti-market-manipulation, and oversight requirements, including annual reporting requirements. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time. Under the Energy Policy Act of 2005 (the “EPAct of 2005”), FERC has civil penalty authority under the NGA and the NGPA to impose penalties for violations of up to $1,544,521 per day for each violation, in addition to disgorgement of profits associated with any violation. Failure to comply with FERC rules and regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, words such as “may,” “assume,” “forecast,” “could,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events at the time such statement was made. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus. Examples of forward-looking statements include, among others, statements we make regarding:

• our business strategy;

• our estimated proved reserves;

• our ability to achieve or maintain certain financial and operational metrics;

• our drilling prospects, inventories, projects and programs;

• actions taken by the OPEC and other allied countries (collectively known as “OPEC+”) as it pertains to the global supply and demand of, and prices for, oil, natural gas and NGLs;

• armed conflict, political instability, or civil unrest in oil and gas producing regions, including instability in the Middle East and the conflict between Russia and Ukraine, and the related potential effects on laws and regulations, or the imposition of economic or trade sanctions;

• our ability to replace the reserves we produce through drilling and property acquisitions;

• the occurrence or threat of epidemic or pandemic diseases, or any government response to such occurrence or threat;

• our financial strategy, leverage, liquidity and capital required for our development program;

• our pending legal matters;

• our ability to comply with environmental, health and safety laws, regulations, and obligations;

• our realized oil, natural gas and NGL prices;

• the timing and amount of our future production of oil, natural gas and NGLs;

• our ability to reduce or offset our GHG emissions, including our ability to achieve carbon neutrality;

• our hedging strategy and results;

• our competition and government regulations;

• our ability to obtain permits and governmental approvals;

• our marketing of oil, natural gas and NGLs;

• our leasehold or business acquisitions;

• our costs of developing our properties;

• general economic conditions;

• credit markets;

• uncertainty regarding our future operating results; and

• our plans, objectives, expectations and intentions contained in this prospectus that are not historical.

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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; 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 and the other risks described under “Risk Factors.”

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 prospectus 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 prospectus 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 prospectus.

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USE OF PROCEEDS

We expect to receive approximately $238.6 million (or approximately $276.0 million if the underwriters’ option to purchase additional shares of Class A common stock is exercised in full) of net proceeds from the sale of the Class A common stock offered by us, after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to contribute all of the net proceeds from this offering to INR Holdings in exchange for 13,250,000 INR Units. INR Holdings intends to use the net proceeds from this offering to repay borrowings outstanding under the Credit Facility and the excess, if any, for general corporate purposes.

As of September 30 and December 31, 2024, we had approximately $224.7 million and $259.5 million of outstanding borrowings under the Credit Facility, respectively. The Credit Facility matures on September 25, 2028. The unpaid principal amount outstanding of each ABR Loan (as defined in the Credit Agreement) under the Credit Facility bears interest from the date of the Borrowing (as defined in the Credit Agreement) thereof until maturity (whether by acceleration or otherwise) at a rate per annum that shall at all times be the Applicable Margin (as defined in the Credit Agreement) plus the ABR (as defined in the Credit Agreement), in each case, in effect from time to time. The unpaid principal amount outstanding of each SOFR Loan (as defined in the Credit Agreement) under the Credit Facility bears interest from the date of the Borrowing (as defined in the Credit Agreement) thereof until maturity (whether by acceleration or otherwise) at a rate per annum that shall at all times be the Applicable Margin plus the Adjusted Term SOFR (as defined in the Credit Agreement), in each case, in effect from time to time. Borrowings under the Credit Facility were used to pay down the Prior Credit Facility, for certain acquisitions and for drilling and completion costs.

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DIVIDEND POLICY

Following the completion of this offering, our board of directors may elect to declare cash dividends on our Class A common stock, subject to our compliance with applicable law, and depending on, among other things, economic conditions, our financial condition, results of operations, projections, liquidity, earnings, legal requirements, and restrictions in the agreements governing our indebtedness (as further discussed below). The payment of any future dividends will be at the discretion of our board of directors. We have not adopted, and do not currently expect to adopt, a written dividend policy.

Our Credit Facility contains restrictions on the payment of dividends. Such restrictions allow us to pay dividends after the completion of this offering only when such conditions are met, including but not limited to, on a pro forma basis:

• when the Consolidated Total Net Leverage Ratio (as defined in the Credit Agreement) is less than or equal to 2.00 to 1.00, availability under the Credit Facility is not less than 20%, Distributable Free Cash Flow (as defined in the Credit Agreement) exists and no default, event of default or loan limit deficiency exists; or

• when the Consolidated Total Net Leverage Ratio is less than or equal to 1.25 to 1.00, availability under the Credit Facility is not less than 20% and no default, event of default or loan limit deficiency exists.

See “Risk Factors—Risks Related to this Offering, Our Class A Common Stock and Capital Structure—We cannot assure you that we will be able to pay dividends on our Class A common stock” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing Agreements—Credit Facility.”

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CAPITALIZATION

The following table sets forth our cash position and capitalization as of September 30, 2024:

• on an actual basis for our predecessor; and

• on an as adjusted basis to give effect to the reorganization described under “Corporate Reorganization” and this offering at an initial public offering price of $20.00 per share, including the application of the net proceeds as set forth under “Use of Proceeds.”

The information set forth in the table below is illustrative only and will be adjusted based on the final terms of this offering. This table should be read in conjunction with, and is qualified in its entirety by reference to, the “Use of Proceeds” section and our financial statements and related notes appearing elsewhere in this prospectus.

	As of September 30, 2024
	Actual		As Adjusted
	(in thousands, except shares and par value)
Cash and cash equivalents(1)	$	1,565	$	23,096
Debt:
Credit Facility(2)	$	224,746	$	—
Notes Payable		184		184
Total Indebtedness	$	224,930	$	184
Members’ equity/stockholders’ equity:
Members’ equity	$	513,759	$	—
Class A common stock—$0.01 par value; no shares authorized, issued or outstanding, actual; 400,000,000 shares authorized, 13,250,000 shares issued and outstanding, pro forma		—		133
Class B common stock—$0.01 par value; no shares authorized, issued or outstanding, actual; 150,000,000 shares authorized, 45,638,889 shares issued and outstanding, pro forma		—		456
Additional paid-in capital		—		171,350
Retained earnings		—		—
Total members’ equity/stockholders’ equity	$	513,759	$	171,939
Non-controlling interest		—		592,233
Total equity		513,759		764,172
Total capitalization	$	738,689	$	764,356

(1) We expect to receive approximately $249.1 million of net proceeds from this offering, prior to deducting estimated offering expenses. Of the total estimated offering expenses of $10.5 million, $7.7 million has already been capitalized and is included in the historical unaudited consolidated balance sheet of INR Holdings as of September 30, 2024, within Prepaid expenses and other current assets, and $2.8 million is expected to be paid with the net cash proceeds along with repayment of $224.7 million borrowings outstanding under the Credit Facility.

(2) As of December 31, 2024, we had $259.5 million of borrowings outstanding under the Credit Facility.

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DILUTION

Purchasers of our Class A common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the Class A common stock for accounting purposes. Our net tangible book value as of September 30, 2024, after giving effect to the transactions described under “Corporate Reorganization,” was $525.6 million, or $11.52 per share. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of Class A common stock that will be outstanding immediately prior to the closing of this offering after giving effect to our corporate reorganization (assuming that 100% of our INR Units have been exchanged for Class A common stock and the cancellation of the corresponding shares of Class B common stock pursuant to the INR Holdings LLC Agreement). The only pro forma adjustment to net tangible book value related to our corporate reorganization is the addition of $11.8 million of deferred tax assets, net. After giving effect to the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of September 30, 2024 would have been approximately $764.2 million, or $12.98 per share. This represents an immediate increase in the net tangible book value of $1.46 per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $7.02 per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering (assuming that 100% of our INR Units have been exchanged for Class A common stock and the cancellation of the corresponding shares of Class B common stock pursuant to the INR Holdings LLC Agreement):

Initial public offering price per share			$	20.00
Pro forma net tangible book value per share as of September 30, 2024
(after giving effect to our corporate reorganization)	$	11.52
Increase in pro forma net tangible book value per share of Class A common stock attributable to new investors in this offering	$	1.46
As adjusted pro forma net tangible book value per share of Class A common stock after our corporate reorganization and this offering			$	12.98
Dilution in pro forma net tangible book value per share of Class A common stock to investors in this offering			$	7.02

If the underwriters exercise in full their option to purchase 1,987,500 additional shares of Class A common stock, the pro forma net tangible book value after the offering would be $13.17 per share, the increase in pro forma net tangible book value per share to existing stockholders would be $1.65 per share and the dilution to new investors would be $6.83 per share.

The following table summarizes, on an adjusted pro forma basis as of September 30, 2024, the total number of shares of Class A common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders (assuming that 100% of our INR Units have been exchanged for Class A common stock and the cancellation of the corresponding shares of Class B common stock pursuant to the INR Holdings LLC Agreement) and to be paid by new investors in this offering at our initial public offering price of $20.00 per share, calculated before deduction of estimated underwriting discounts and commissions:

	Shares Acquired					Total Consideration					Average Price Per Share
	Number		Percent			Amount		Percent
						(in thousands)
Existing stockholders		45,638,889		77.5	%	$	313,371		54.2	%	$	6.87
New investors in this offering		13,250,000		22.5	%	$	265,000		45.8	%	$	20.00
Total		58,888,889		100	%	$	578,371		100	%	$	9.82

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The above tables and discussion are based on the number of shares of our Class A common stock and Class B common stock to be outstanding as of the closing of this offering. If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to 15,237,500, or 100% of the total number of shares of Class A common stock.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following should be read in conjunction with our financial statements and related notes appearing elsewhere in this prospectus. 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. Some of the key factors that could cause actual results to vary from our expectations include those factors discussed below and elsewhere in this prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” (included elsewhere in this prospectus) contain important information. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise indicated, the historical financial information presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” speaks only with respect to our predecessor, INR Holdings, and does not give pro forma effect to our corporate reorganization described in “Corporate Reorganization.”

Overview

We are a growth oriented, free cash flow generating, independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible balance sheet. Additionally, we have proven our ability to grow our acreage position through organic leasing efforts and accretive acquisitions. We are an early mover into the core of the Utica Shale’s volatile oil window in eastern Ohio as well as the emerging dry gas Utica Shale in southwestern Pennsylvania. Our Marcellus Shale development overlays our deep dry gas Utica assets in Pennsylvania, providing highly economic stacked development inventory that leverages the same company owned midstream infrastructure. We have amassed approximately 93,000 net surface acres with exposure to the core of these plays providing us a unique and balanced portfolio of high return oil and natural gas drilling locations. This balance allows us to optimize our development plan across our portfolio to capitalize on changes in commodity pricing over time.

Market Conditions and Operational Trends

Our revenue, profitability, and ability to return cash to our equity holders can depend on factors beyond our control, such as economic, political, and regulatory developments that impact market supply and demand. Prices for crude oil, natural gas and NGLs have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future.

The oil and gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2022 through September 30, 2024, spot prices for NYMEX WTI crude oil ranged from $66.61 per Bbl to $123.64 per Bbl, while the range for NYMEX Henry Hub natural gas spot prices was between $1.25 per MMBtu and $9.85 per MMBtu. More recently, prices have increased due to seasonal demand and OPEC+ extending their oil production cuts through 2025 resulting in the NYMEX WTI spot price averaging $75.10 per Bbl during the third quarter of 2024. Natural gas prices have remained low throughout the first half of 2024 driven by an over-supply of production along with milder winter weather and liquefied natural gas (LNG) project delays. We expect that this 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.

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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 2022:

	2022								2023								2024
	Q1		Q2		Q3		Q4		Q1		Q2		Q3		Q4		Q1		Q2		Q3
Oil (per Bbl)	$	94.46	$	108.65	$	93.18	$	82.79	$	76.08	$	73.76	$	82.29	$	78.41	$	77.56	$	81.72	$	76.24
Gas (per MMBtu)	$	4.96	$	7.17	$	8.20	$	6.26	$	3.44	$	2.09	$	2.54	$	2.88	$	2.25	$	1.89	$	2.15

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

On July 9, 2024, we closed on our previously announced acquisition of leasehold located within Salt Fork State Park in Guernsey County Ohio for approximately $58.5 million. The acquisition adds over 5,700 net acres and is contiguous with our existing acreage and represents 23 new drilling locations.

On October 4, 2024, we entered into a lease with Muskingum Watershed Conservancy District for approximately 1,900 acres in Guernsey and Noble Counties, Ohio. The acreage is contiguous with our existing acreage and represents 19 new or enhanced (which includes increased working interest or longer lateral length) drilling locations.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our operations, including the following sources of our revenue, principal components of our cost structure and other financial metrics:

• Reserve and production levels;

• Realized prices on the sale of oil, natural gas and NGLs;

• Lease operating expense (“LOE”); and

• Adjusted EBITDAX.

Sources of Revenues

We derive our revenues predominantly from the sale of our oil and natural gas production and the sale of NGLs that are extracted from our natural gas during processing. Our production is entirely from within the continental United States and is similarly sold to purchasers within the United States; however, some of our production revenues are attributable to customers who may export our products.

Increases or decreases in our revenue, profitability and future production growth are highly dependent on the commodity prices we receive. Oil, natural gas, and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate. During 2023 and 2022, our oil, natural gas, and NGL revenues were comprised of 53% and 38%, respectively, from the sale of oil, 31% and 46%,

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respectively, from the sale of natural gas, and 15% and 15%, respectively, from the sale of NGLs. During the nine months ended September 30, 2024 and 2023, our oil, natural gas, and NGL revenues were comprised of 64% and 47%, respectively, from the sale of oil, 19% and 37%, respectively, from the sale of natural gas, and 17% and 16%, respectively, from the sale of NGLs.

We utilize unaffiliated third parties to market a portion of our oil, natural gas, and NGL production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations and super majors in our industry. The third parties collect proceeds directly from these purchasers and remit to us the total of all amounts collected on our behalf less the third party’s fee for making such sales. We do not believe the loss of any purchaser would have a material adverse effect on our business, as other purchasers or markets are currently accessible to us.

Midstream activities revenues, which consist of gathering, compression, and water handling, are derived from our ownership of INR Midstream. Our gathering and compression revenues relate to activities located within the dry gas areas of southwestern Pennsylvania. Our water handling revenues relate to activities associated with delivering water for stimulation activities in both eastern Ohio and southwestern Pennsylvania.

Principal Components of Our Cost Structure

Lease operating. LOE are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water disposal, materials, and supplies comprise the most significant portion of our LOE. Certain items, such as direct labor, materials, and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our well equipment or surface facilities result in increased LOE in periods during which they are performed. Certain operating cost components are variable and fluctuate based on production levels. For example, the disposal of produced water usually increases in conjunction with increased production. Also, we monitor our LOE in absolute dollar terms and on a per Boe and/or Mcfe basis to assess our performance and to determine if any wells or properties should be shut in, repaired or recompleted.

Gathering, processing, and transportation. Gathering, processing, and transportation (“GP&T”) expense includes fees paid to third parties who operate low- and high-pressure gathering systems that transport our gas. It also includes costs to process, extract, and fractionate NGLs from our liquids-rich gas and transport our natural gas and NGLs to market.

Production and ad valorem taxes. Pennsylvania imposes an annual impact fee on each producing shale well for a period of 15 years beginning in the year the well is spud. Ohio imposes a production tax which is based upon annual production. The proportion of our production and producing wells from each state may change over time and, as a result, the proportion of our production taxes and impact fees will vary depending on volumes produced from the Utica Shale, the number of producing shale wells in Pennsylvania, and the applicable production tax rates and impact fees then in effect. In addition, we are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties as well as the value of property and equipment.

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas. Under the full- cost method of accounting, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization. Accretion expense related to our asset retirement obligations is also included within this balance.

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General and administrative. General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, IT expenses, legal, audit and other fees for professional services. G&A expenses are offset by recoveries for overhead that are billed to our joint-interest partners as outlined in a joint operating agreement or other similar documents.

Interest expense. We have financed a portion of our working capital requirements and property acquisitions with borrowings under our Prior Credit Facility. As a result, we incur interest expense that is affected by fluctuations in interest rates and, in the case of the Prior Credit Facility based on outstanding borrowings. We expect that we would see a reduction in cash interest expense following the completion of this offering and could see further reductions in cash interest expense as we use free cash flow to lower borrowings outstanding under our Prior Credit Facility.

Gains and losses on derivatives. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of oil, natural gas, and NGLs. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are recorded at fair value as of the balance sheet date with changes in fair value recognized as a gain or loss in our results of operations. Our operating cash flows are impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

Non-GAAP Financial Measures

Adjusted EBITDAX

We define Adjusted EBITDAX as net income plus interest expense, net, income tax expense, depreciation, depletion, and amortization, unrealized gain (loss) on derivative instruments, net cash settlements received (paid) on derivatives, non-cash interest expense (amortization) and non-cash G&A. We believe Adjusted EBITDAX is useful because it makes for an easier comparison of our operating performance, without regard to our financing methods, corporate form or capital structure. We determined our adjustments from net income to arrive at Adjusted EBITDAX to reflect the substantial variance in practice from company to company within our industry depending upon accounting methods and book values of assets, capital structures, and the method by which the assets were acquired. Adjusted EBITDAX should not be considered more meaningful than or as an alternative to net income determined in accordance with U.S. GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may differ from and may not be comparable to similarly titled measures of other companies.

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The following table provides a reconciliation of our net income, the most directly comparable financial measure presented in accordance with U.S. GAAP, to Adjusted EBITDAX for the periods presented herein:

	Predecessor						Predecessor
	For the Nine Months Ended September 30,						For the Year Ended December 31,
	2024			2023			2023			2022
(in thousands)
Net income	$	54,803		$	26,444		$	86,672		$	68,129
Interest expense, net		16,263			6,968			11,910			2,574
Income tax expense		—			—			—			—
Depreciation, depletion, and amortization		56,344			29,289			53,796			18,336
Unrealized (gain) loss on derivative instruments		(6,397	)		(5,220	)		(45,322	)		24,820
Net cash settlements received (paid) on derivatives(1)		27,755			13,477			19,438			(37,888	)
Non-cash G&A		771			—			—			—
Adjusted EBITDAX	$	149,539		$	70,958		$	126,494		$	75,971

(1) Included non-recurring gain on derivative unwind for $7.2m for the 9 months ended September 30, 2024

PV-10

Certain of our oil and natural gas reserve disclosures included in this prospectus are presented on a PV-10 basis. PV-10 is a non-GAAP financial measure and represents the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV-10 of proved reserves generally differs from the Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of future income taxes, as is required under GAAP in computing the Standardized Measure. However, our PV-10 for proved reserves using SEC pricing and the Standardized Measure of proved reserves are equivalent because we were not subject to entity level taxation. Accordingly, no provision for federal or state income taxes has been provided in the Standardized Measure because taxable income is passed through to our unitholders.

We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and natural gas companies. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of PV-10 value provides greater comparability when evaluating oil and natural gas companies. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. However, the definition of PV-10 value as defined above may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value as defined may not be comparable to similar measures provided by other companies.

Investors should be cautioned that neither PV-10 nor Standardized Measure of proved reserves represents an estimate of the fair market value of our proved reserves. We and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities.

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Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Public Company Expenses. Upon completion of this offering, we expect to incur direct, incremental G&A expenses as a result of being publicly traded, including costs associated with Exchange Act compliance, tax compliance, PCAOB support fees, SOX compliance costs, investor relations activities, listing fees, registrar and transfer agent fees, stock-based compensation, incremental director and officer liability insurance costs, and independent director compensation. We estimate these direct, incremental G&A expenses could total approximately $4 million to $6 million per year, which are not included in our historical results of operations.

Corporate Reorganization. The historical consolidated financial statements included in this prospectus are based on the financial statements of our predecessor, INR Holdings, prior to our reorganization in connection with this offering as described in “Corporate Reorganization.” Our historical financial data may not yield an accurate indication of what our actual results would have been if those transactions had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. In connection with the closing of this offering, all outstanding performance-based incentive units will vest and an immediate recognition of a non-cash compensation expense of $126.1 million associated with all previously granted incentive units will occur in the current period.

Interest Expense. In connection with this offering, we expect to materially reduce our indebtedness. Depending on our use of proceeds, we expect an immediate reduction in cash interest expense and could see further reductions in cash interest expense as we use free cash flow to lower debt.

Income Taxes. Our predecessor, INR Holdings, was organized as a limited liability company not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to our members. Although we are a corporation under the Internal Revenue Code of 1986, as amended (the “Code”), we do not expect to report any income tax benefit or expense prior to the consummation of this offering.

Results of Operations

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

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 Nine Months Ended September 30,						Increase / (Decrease)
	2024(1)			2023			$			%
Net revenues (in thousands):
Oil sales	$	121,570		$	41,188		$	80,382			195	%
Natural gas sales		35,874			33,061			2,813			9	%
Natural gas liquids sales		31,433			14,052			17,381			124	%
Oil, natural gas, and natural gas liquids sales	$	188,877		$	88,301		$	100,576			114	%
Average sales prices:
Oil price (per Bbl)	$	69.75		$	70.92		($	1.17	)		(2	)%
Effects of derivative settlements on average price (per Bbl)	($	2.36	)	($	0.34	)	($	2.02	)		594	%
Oil price including the effects of derivatives (per Bbl)	$	67.39		$	70.58		($	3.19	)		(5	)%
Wtd. Average NYMEX WTI price for oil (per Bbl)(3)	$	78.31		$	77.21		$	1.10			1	%
Oil differential to NYMEX	($	8.56	)	($	6.29	)	($	2.27	)		36	%

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	For the Nine Months Ended September 30,						Increase / (Decrease)
	2024(1)			2023			$			%
Natural gas price (per Mcf)	$	1.65		$	1.79		$	(0.14	)		(8	)%
Effects of derivative settlements on average price (per Mcf)	$	0.82		$	0.68		$	0.14			20	%
Natural gas price including the effects of derivatives (per Mcf)	$	2.47		$	2.47		$	(0.00	)		0	%
Wtd. Average NYMEX Henry Hub price for natural gas (per MMBtu)(3)	$	2.09		$	2.74		$	(0.65	)		(24	)%
Natural gas differential to NYMEX	$	(0.44	)	$	(0.95	)	$	0.51			(54	)%
NGL price excluding GP&T (per Bbl)	$	24.14		$	20.46		$	3.68			18	%
Net production(1):
Oil (MBbls)		1,743			581			1,162			200	%
Natural gas (MMcf)		21,783			18,508			3,275			18	%
NGL (Bbls)		1,302			687			615			90	%
Net production (MBoe)(2)		6,676			4,353			2,323			53	%
Average daily net production(1):
Oil (Bbls/d)		6,361			2,127			4,234			199	%
Natural gas (Mcf/d)		79,500			67,795			11,705			17	%
NGLs (Bbls/d)		4,751			2,515			2,236			89	%
Average daily net production (Boe/d)(2)		24,362			15,941			8,421			53	%

(1) Includes the results of operations related to the assets acquired from Utica Resources Ventures and PEO Ohio on October 1, 2023.

(2) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

(3) Based on Netherland, Sewell and Associates Inc. (“NSAI”) found at https://netherlandsewell.com/resources/pricing-data/ and EIA commodity pricing. (“NSAI”) found at https://netherlandsewell.com/resources/pricing-data/ and U.S. Energy Information Administration (“EIA”). Weighted average is based on INR’s production in a given month during the course of the calendar year.

Revenues

Oil, natural gas, and NGL sales. Total oil, natural gas and NGL net revenues for the nine months ended September 30, 2024 increased by $100.6 million, or 114%, compared to the nine months ended September 30, 2023. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

Net production volumes for oil, natural gas, and NGLs increased 200%, 18% and 90%, respectively, between periods. The oil production volume increase resulted from placing eight Ohio Utica wells (approximately 98,428 lateral feet) on production since September 30, 2023 as compared to nine Ohio Utica wells (approximately 89,787 lateral feet) during the prior period. In addition, we placed into production three Pennsylvania Marcellus wells (approximately 33,750 lateral feet) during the nine months ended September 30, 2023. Oil production also benefited from wells acquired from Utica Resources Ventures and PEO Ohio. These oil volume increases were partially offset by normal production decline across our existing wells. NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in oil quantities sold. The higher increase in natural gas volumes between periods was due to the full year impact from three additional Pennsylvania Marcellus wells that were placed on production in June 2023. The combination of the 2023 wells along with the Ohio Utica wells placed into production assisted in the overall increase of 3.3 Bcf in natural gas production, an increase of 18% relative to the prior year.

Average realized sales prices for NGLs increased 18% during the period while average realized oil and natural gas sales prices decreased 2% and 8%, respectively, for the nine-month period ended September 30, 2024 compared to the prior year. The 2% decrease in the average realized oil price was mainly driven by higher

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NYMEX WTI oil prices during the period offset by higher regional differentials compared to the same period a year earlier. The average realized natural gas price decreased 8% due to 24% lower average NYMEX gas prices between periods offset by lower natural gas differentials. The 18% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in 2024 compared to 2023 and changes in product composition between periods.

Operating Expenses

	For the Nine Months Ended September 30,				Change
	2024		2023		Amount		Percent
(in thousands)
Gathering, processing, and transportation	$	37,852	$	18,378	$	19,475		106	%
Lease operating		20,715		10,808		9,909		92	%
Production and ad valorem taxes		1,264		396		868		219	%
Depreciation, depletion and amortization		56,344		29,289		27,055		92	%
General and administrative		8,268		3,472		4,795		138	%
Total operating expenses	$	124,443	$	62,343	$	62,102		100	%
($ per Boe)
Gathering, processing, and transportation	$	5.67	$	4.22	$	1.45		34	%
Lease operating		3.10		2.48		0.62		25	%
Production and ad valorem taxes		0.19		0.09		0.10		108	%
Depreciation, depletion and amortization		8.44		6.72		1.72		26	%
General and administrative		1.24		0.80		0.44		55	%
Total operating expenses	$	18.64	$	14.32	$	4.33		30	%

Gathering, processing, and transportation. Gathering, processing, and transportation (“GP&T”) for the nine months ended September 30, 2024, increased $19.5 million compared to nine month period ended September 30, 2023. This increase was mainly attributable to the acquisition of assets from Utica Resources Ventures and additional wells brought online in Ohio between periods. GP&T per Boe was $5.67 for the nine month period ended September 30, 2024, which represents an increase of $1.45 per Boe or 34% increase from the prior year period. This increase was primarily related to increased gas volumes on third party gathering systems and lower volumes on INR’s owned gathering system, and costs associated with well downtime in Ohio.

Lease operating. Lease operating expense (“LOE”) for the nine months ended September 30, 2023, increased $9.9 million compared to the prior year period. LOE per Boe was $3.10 for the nine-month period ended September 30, 2024, which represents an increase of $0.62 per Boe, or 25%, from the prior year period. This increase in LOE was primarily related to higher fixed and semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new producing wells drilled or acquired. The higher well count as of September 30, 2024 was primarily due to the acquisition of 50 gross operated horizontal wells acquired from Utica Resources Ventures that INR operated for the fourth quarter 2023 and 11 wells INR placed on production since September 30, 2023. In addition, the lower natural gas volumes from our assets located in Pennsylvania contributed to the metrics per unit increase.

Production and ad valorem taxes. Production and ad valorem taxes for the nine-month period ending September 30, 2024, increased $0.9 million compared to the prior year period. Production taxes in Ohio are based on our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate.

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Production taxes in Pennsylvania are assessed on producing wells by imposing an impact fee determined based on the market price for natural gas, which commences on the date the well is initially spud and continues for a period of 15 years.

Depreciation, Depletion and Amortization. For the nine months ended September 30, 2024, DD&A expense amounted to $56.3 million, an increase of $27.1 million over the same 2023 period. Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves.

General and Administrative Expenses. G&A expenses for the nine months ended September 30, 2024 were $8.3 million compared to $3.5 million for the nine months ended September 30, 2023. This increase was primarily due to fees related to legal and accounting and auditing services. In addition, higher payroll and employee-related costs associated with our higher G&A headcount, which increased from 35 as of September 30, 2023 to 75 as of September 30, 2024.

Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding; and (ii) monthly cash settlements on any closed out hedge positions during the period.

The following table presents gains and losses on our derivative instruments for the periods indicated:

	Nine Months Ended September 30,
	2024			2023
(in thousands)
Realized cash settlement gains (losses)	$	27,755		$	13,477
Non-cash mark-to-market derivative gain (losses)		(21,358	)		(8,257	)
Total	$	6,397		$	5,220

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For the Year Ended December 31, 2023 Compared to the Year Ended December 31, 2022

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:

	Year Ended December 31,						Change
	2023			2022			Amount			Percent
Net revenues (in thousands):
Oil sales	$	85,276		$	54,631		$	30,645			56	%
Natural gas sales		49,617			66,048			(16,431	)		(25	)%
Natural gas liquids sales		24,639			21,921			2,718			12	%
Oil, natural gas, and natural gas liquids sales	$	159,532		$	142,600		$	16,932			12	%
Average sales prices:
Oil price (per Bbl)	$	70.77		$	85.36		$	(14.59	)		(17	)%
Effects of derivative settlements on average price (per Bbl)	$	0.26		$	(11.27	)	$	11.53			(102	)%
Oil price including the effects of derivatives (per Bbl)	$	71.03		$	74.09		$	(3.06	)		(4	)%
Wtd. Average NYMEX WTI price for oil (per Bbl)	$	78.12		$	91.79		$	(13.67	)		(15	)%
Oil differential to NYMEX	$	(7.35	)	$	(6.43	)	$	(0.92	)		14	%
Natural gas price (per Mcf)	$	1.80		$	5.70		$	(3.90	)		(68	)%
Effects of derivative settlements on average price (per Mcf)	$	0.62		$	(2.22	)	$	2.84			(128	)%
Natural gas price including the effects of derivatives (per Mcf)	$	2.42		$	3.48		$	(1.06	)		(30	)%
Wtd. Average NYMEX Henry Hub price for natural gas (per MMBtu)	$	2.79		$	6.36		$	(3.57	)		(56	)%
Natural gas differential to NYMEX Henry Hub	$	(0.99	)	$	(0.66	)	$	(0.33	)		50	%
NGL price excluding GP&T (per Bbl)	$	22.16		$	33.42		$	(11.26	)		(34	)%
Effects of derivative settlements on average price (per Bbl)	$	1.84		$	(7.99	)	$	9.83			(123	)%
NGL price including the effects of derivatives (per Bbl)	$	24.00		$	25.43		$	(1.43	)		(6	)%
Net production:
Oil (MBbls)		1,205			640			565			88	%
Natural gas (MMcf)		27,506			11,585			15,921			137	%
NGL (MBbls)		1,112			656			456			70	%
Net production (MBoe)(1)		6,901			3,227			3,674			114	%
Average daily net production:
Oil (Bbls/d)		3,301			1,753			1,548			88	%
Natural gas (Mcf/d)		75,359			31,740			43,619			137	%
NGLs (Bbls/d)		3,047			1,797			1,250			70	%
Average daily net production (Boe/d)(1)		18,907			8,841			10,066			114	%

(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

Revenues

Oil, natural gas, and NGL sales

Total oil, natural gas and NGL net revenues for the year ended December 31, 2023 increased by $16.9 million, or 12%, compared to the year ended December 31, 2022. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.

Net production volumes for oil, natural gas, and NGLs increased 88%, 137% and 70%, respectively, between periods. The oil production volume increase resulted from placing seven Ohio Utica wells (total 68,385

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lateral feet) on production since December 31, 2022 as compared to four Ohio Utica wells (total 48,682 lateral feet) brought online during the year ended December 31, 2022. Oil production also benefited from wells acquired from Utica Resource Ventures and PEO Ohio, which collectively added 373,275 barrels of net oil production to the year ended December 31, 2023. These oil volume increases were partially offset by normal production decline across our existing wells. NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in oil quantities sold. The higher increase in natural gas volumes between periods compared to oil and NGLs was due to three additional Pennsylvania Marcellus (total 44,875 lateral feet) wells placed on production since December 31, 2022. The combination of the 2023 wells and a full year of production from the three Pennsylvania Marcellus wells (total 40,004) turned into sales in December 2022 wells assisted in the overall increase of 15.9 Bcf in natural gas production, an increase of 137% relative to the prior year.

These production increases were partially offset by decreases in the average realized sales prices for oil, natural gas, and NGLs which decreased 17%, 68% and 34%, respectively, for the year ended December 31, 2023 compared to the prior year. The 17% decrease in the average realized oil price was mainly the result of the lower NYMEX crude prices between periods and slightly higher oil differentials. The average realized natural gas price decreased 68% due to 56% lower average NYMEX gas prices between periods and higher natural gas differentials. The 34% decrease in average realized NGL prices between periods was primarily attributable to lower Mont Belvieu spot prices for plant products in 2023 compared to 2022. The decline was partially offset by changes in product mix as a result of the Utica Resource Acquisition and the PEO Ohio Acquisition.

Operating Expenses

	For the Year Ended December 31,				Change
	2023		2022		Amount			Percent
(in thousands)
Gathering, processing, and transportation	$	31,097	$	15,673	$	15,424			98	%
Lease operating		18,371		8,256		10,115			123	%
Production and ad valorem taxes		886		719		167			23	%
Depreciation, depletion and amortization		53,796		18,336		35,460			193	%
General and administrative		4,885		4,712		173			4	%
Total operating expenses	$	109,035	$	47,696	$	61,339			129	%
($ per Boe)
Gathering, processing, and transportation	$	4.51	$	4.86	$	(0.35	)		(7	)%
Lease operating		2.66		2.56		0.10			4	%
Production and ad valorem taxes		0.13		0.22		(0.09	)		(42	)%
Depreciation, depletion and amortization		7.79		5.68		2.11			37	%
General and administrative		0.71		1.46	$	(0.75	)		(52	)%
Total operating expenses	$	15.80	$	14.78	$	1.02			7	%

Gathering, processing, and transportation

GP&T for the year ended December 31, 2023 increased $15.4 million compared to the year ended December 31, 2022. GP&T decreased slightly on a per Boe basis from $4.86 for the year ended December 31, 2022 to $4.51 per Boe for the year ended December 31, 2023. While overall GP&T expenses increased, the decline in per unit GP&T expenses is driven by the assets acquired from Utica Resource Ventures which have a lower gas to oil ratio, and thus, a lower gathering fee on a per unit basis relative to our other assets.

Lease operating

LOE for the year ended December 31, 2023 increased $10.1 million compared to the year ended December 31, 2022. LOE per Boe was $2.66 for the year ended December 31, 2023, which represents an

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increase of $0.10 per Boe, or 4%, from the year ended December 31, 2022. This increase in LOE was primarily related to higher fixed and semi-variable well costs, such as water disposal, equipment rentals, repair work, wellhead chemicals, labor and electricity, associated with a higher well count from new producing wells drilled or acquired. The higher well count in 2023 was due to the acquisition of 50 gross operated horizontal wells acquired from Utica Resource Ventures that INR operated for the fourth quarter 2023 and 10 wells that INR placed on production since December 31, 2022.

Production and ad valorem taxes

Production and ad valorem taxes for the year ended December 31, 2023 increased approximately $0.2 million compared to the year ended December 31, 2022. Production taxes in Ohio are based on our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of our proved developed oil and gas properties and vary across the different counties in which we operate. Production taxes in Pennsylvania are assessed on producing wells by imposing an impact fee determined based on the market price for natural gas, which commences on the date the well is initially spud and continues for a period of 15 years.

Depreciation, depletion, and amortization

For the year ended December 31, 2023, DD&A expense was $53.8 million, an increase of $35.5 million from 2022. The primary factor contributing to higher DD&A expense in 2023 was the increase in overall production volumes between periods of 3.7 MMBoe, approximately 0.9 MMBoe of which related to the properties acquired in the Utica Resource Acquisition and the PEO Ohio Acquisition that closed on October 4, 2023.

General and administrative

G&A expenses for the year ended December 31, 2023 were $4.9 million compared to $4.7 million for the year ended December 31, 2022. Our increased G&A expenses in 2023 were primarily due to higher payroll and employee-related costs within our G&A functions related to headcount increases and costs to support the additional headcount. INR Holding’s headcount increased from 30 as of December 31, 2022, to 49 as of December 31, 2023, driven by the aforementioned acquisitions and increased support of operational activity.

Other Income and Expense

Interest expense, net

Interest expense was $9.3 million higher for the year ended December 31, 2023 compared to the year ended December 31, 2022, mainly due to higher weighted average borrowings outstanding and a higher effective interest rate during 2023.

Our weighted average borrowings outstanding under our Prior Credit Facility were $120.8 million during 2023 compared to $38.2 million in 2022. Our Prior Credit Facility’s weighted average effective interest rate was 9.10% and 5.84% for the years ended December 31, 2023, and 2022, respectively, due to higher rates on our variable-rate borrowings between periods.

Gain (loss) on derivative instruments

Our gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding and (ii) monthly

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cash settlements on any closed-out hedge positions during the period. During the year ended December 31, 2023, we realized a $19.4 million gain from the settlement of derivative instruments as compared to a realized loss of $37.9 million during the year ended December 31, 2022.

Liquidity and Capital Resources

Following the completion of this offering, we expect our primary sources of liquidity to be cash flows from operations, borrowings incurred under our Credit Facility, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and gas properties. Our future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary uses of capital have been for drilling and development capital expenditures and the acquisition of oil and natural gas properties.

We continually evaluate our capital needs and compare them to our capital resources. Our total cash capital expenditures incurred for development during the nine months ended September 30, 2024 were $189.6 million. We funded our capital expenditures for the nine months ended September 30, 2024 from cash flows from operations and borrowings incurred under our Credit Facility. We expect to continue to fund our 2024 capital expenditures budget through a combination of cash flows from operations and additional borrowings under our Credit Facility. Our ability to utilize cash flows from operations to fund our development program is driven by our oil and gas production, current commodity prices and our commodity hedge positions in place.

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.

Our liquidity requirements also include operating expenses, which have been impacted by elevated levels of inflation. High oil prices have historically led to more development activity in oil-focused shale basins and resulted in service cost inflation across all U.S. shale basins, including our areas of operation. Ongoing inflationary pressures may result in increases to the costs of our oilfield goods, services and personnel, which would, in turn, cause our capital expenditures and operating costs to rise. We closely monitor costs and are cost conscious in managing our operations. We may solicit bids from multiple vendors or contractors or source materials from multiple suppliers to take advantage of cost competition, and we may buy surplus materials if we can acquire them on attractive terms. Where we anticipate elevated costs may be more sustained, such as in the cost of services, we may enter into contracts with certain service providers to lock in rates. We are also strategic in the duration of our contracts to provide flexibility to take advantage of cost declines when they occur. Sustained levels of high inflation have also caused the U.S. Federal Reserve and other central banks to increase interest rates, which has raised the cost of capital and increased our interest expense.

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 date that our consolidated financial statements are issued.

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Cash Flow Activity

Our financial condition and results of operations, including our liquidity and profitability, are significantly affected by the prices that we realize for our oil, natural gas and NGLs and the volumes of oil and natural gas that we produce. Oil, natural gas and NGLs are commodities for which established trading markets exist.

Accordingly, our operating cash flow is sensitive to a number of variables, the most significant of which are the volatility of oil, natural gas and NGL prices and production levels both regionally and across the United States, the availability and price of alternative fuels, infrastructure capacity to reach markets, costs of operations, and other variable factors. We monitor factors that we believe could be likely to influence price movements including new or expanded oil and natural gas markets, gas imports, LNG and other exports, and regional and industry-wide capital intensity levels.

Our produced volumes have a high correlation to our level of capital expenditures such that our ability to fund it through operating and financing cash flows may be affected by multiple factors discussed further herein.

The following summarizes our cash flow activity for the periods indicated:

	For the Nine Months Ended September 30,						For the Year Ended December 31,
	2024			2023			2023			2022
(in thousands)
Net cash provided by operating activities	$	147,566		$	73,293		$	106,475		$	64,976
Net cash used in investing activities		(194,755	)		(142,755	)		(436,686	)		(95,661	)
Net cash provided by financing activities		47,250			92,615			330,976			28,997
Net increase (decrease) in cash and cash equivalents	$	61		$	23,153		$	765		$	(1,688	)

Analysis of Cash Flow Changes Between the Nine Months Ended September 30, 2024 and 2023

Operating activities

For the nine months ended September 30, 2024, we generated $147.6 million of cash from operating activities, an increase of $74.3 million from the same period in 2023. Cash provided by operating activities increased primarily due to higher production volumes and higher realized price of NGLs for the nine months ended September 30, 2024 as compared to the same 2023 period. These increasing factors were partially offset by higher LOE, severance and ad valorem taxes, GP&T, G&A, interest expense and lower realized prices for oil and gas during the nine months ended September 30, 2024 as compared to the same 2023 period. Refer to “Results of Operations” for more information on the impact of volumes and prices on revenues and on fluctuations in our operating costs between periods.

During the nine months ended September 30, 2024, cash flows from operating activities, cash on hand and net borrowings under our Prior Credit Facility were used to fund $189.6 million of drilling and development cash capital expenditures.

During the nine months ended September 30, 2023, cash flows from operating activities, cash on hand and net borrowings under our Prior Credit Facility were used to fund $133.1 million of drilling and development capital expenditures.

Investing activities

For the nine months ended September 30, 2024, we spent $189.6 million on capital expenditures in conjunction with our drilling program in which we drilled and brought online 9 gross (8.1 net) wells and leasehold costs. We also spent $5.2 million on other property and equipment.

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For the nine months ended September 30, 2023, we spent $133.1 million on capital expenditures in conjunction with our drilling program in which we drilled and brought online 10 gross (9.2 net) wells and leasehold costs. We also spent $9.6 million on other property and equipment.

Financing activities

For the nine months ended September 30, 2024, the change in financing activity was primarily related to borrowing $123.5 million under our Prior Credit Facility and payments of $69.7 million. We used funds from the Credit Facility of $243.4 million for repayment of the balance on the Prior Credit Facility in full. We also paid approximately $5.2 million of syndication fees associated with the Credit Facility.

For the nine months ended September 30, 2023, the change in financing activity was primarily related to borrowing $121.4 million under our Prior Credit Facility and payments of $51.3 million.

Analysis of Cash Flow Changes Between the Year Ended December 31, 2023 and 2022

Operating activities

Net cash provided by operating activities in 2023 increased by $41.5 million from 2022. Items impacting operating cash flows included increased total revenues of $18.6 million and increased cash settlements on derivatives of $57.3 million, which was offset by increased operating expenses of $25.9 million, predominantly GP&T expense and LOE, as well as increased interest expense of $9.3 million and decreased changes in working capital of $0.2 million during the year ended December 31, 2023 compared to December 31, 2022.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

Investing activities

Net cash used in investing activities in 2023 was primarily related to the $279.0 million purchase price of the assets acquired from Utica Resource Ventures and PEO Ohio, which was funded by the issuance of Class B interests and borrowings under our Prior Credit Facility, as discussed below as part of our financing activities.

During 2023, we spent $146.0 million on capital expenditures in conjunction with our drilling program in which we drilled and brought online 10 gross (9.1 net) wells and leasehold costs. We also spent $11.7 million on other property and equipment.

During 2022, we spent $84.1 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 7 gross (6.6 net) wells and leasehold costs. We also spent $11.6 million on other property and equipment.

Financing activities

Net cash provided by financing activities in 2023 increased primarily related to the issuance of $222.3 million of Class B interests in connection with the Utica Resource Acquisition and the PEO Ohio Acquisition. During 2023, we borrowed $203.9 million under our Prior Credit Facility, including $56.7 million to fund the purchase price of the Utica Resource Acquisition and the PEO Ohio Acquisition. We made payments of $90.8 million under the Prior Credit Facility and also made payments of $4.3 million related to debt issuance costs.

During 2022, we borrowed $127.6 million under our Prior Credit Facility and made payments of $98 million.

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Derivative Activities

We are exposed to volatility in market prices and basis differentials for oil, natural gas and NGLs, which impacts the predictability of our cash flows related to the sale of those commodities. Accordingly, to achieve more predictable cash flow and reduce our exposure to adverse fluctuations in commodity prices, we use commodity derivatives, such as swaps, to hedge price risk associated with our anticipated production and to underpin our development program. This helps reduce potential negative effects of reductions in oil and gas prices but also reduces our ability to benefit from increases in oil and gas prices. In certain circumstances, where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to utilize their value to further our strategic pursuits.

A fixed price swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

A basis swap involves swapping variable interest rates based on different reference rates. We receive a fixed price differential and pays the floating market price differential to the counterparty which is calculated based on the differential between NYMEX and the natural gas price at a specific delivery point.

A put option has an established floor price. The buyer of that put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless.

A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

The following tables provide information about our derivative financial instruments as of December 31, 2023:

	Volume		Weighted Average Price		Fair Value as of December 31, 2023
Oil	(in MBbls)		($ per Bbl)		(in thousands)
Fixed price swaps
2024		1,603	$	74.54	$	4,804
2025		776	$	70.53		1,583
2026		211	$	68.24		577
2027		13	$	66.49		31
Total		2,603			$	6,995
	Volume		Weighted Average Price		Fair Value as of December 31, 2023
Natural gas	(in MMBtu)		($ per MMBtu)		(in thousands)
Fixed price swaps
2024		20,249	$	3.49	$	18,580
2025		17,372	$	3.65		3,531
2026		2,713	$	4.07		303
2027		119	$	4.45		2
Total		40,453			$	22,416

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	Volume		Basis Differential			Fair Value as of December 31, 2023
Natural gas	(in MMBtu)		($ per MMBtu)			(in thousands)
Basis swaps
2024		22,736	$	(0.97	)	$	(2,255	)
2025		17,372	$	(1.07	)		(444	)
2026		2,713	$	(1.10	)		(129	)
2027		119	$	(0.99	)		(8	)
Total		42,940				$	(2,836	)
	Volume		Weighted Average Price			Fair Value as of December 31, 2023
Ethane	(in gallons)		($ per gallon)			(in thousands)
Fixed price swaps
2024		8,888,600	$	0.25		$	399
2025		4,932,000	$	0.25			41
2026		419,500	$	0.29			3
2027		8,000	$	0.35			—
Total		14,248,100				$	443
	Volume		Weighted Average Price			Fair Value as of December 31, 2023
Propane	(in gallons)		($ per gallon)			(in thousands)
Fixed price swaps
2024		15,737,800	$	0.73		$	819
2025		9,792,200	$	0.69			126
2026		2,685,500	$	0.70			112
2027		168,000	$	0.73			10
Total		28,383,500				$	1,067
	Volume		Weighted Average Price			Fair Value as of December 31, 2023
Isobutane	(in gallons)		($ per gallon)			(in thousands)
Fixed price swaps
2024		3,058,200	$	0.87		$	(216	)
2025		1,891,600	$	0.81			(121	)
2026		512,500	$	0.77			(31	)
2027		32,000	$	0.78			(2	)
Total		5,494,300				$	(370	)
	Volume		Weighted Average Price			Fair Value as of December 31, 2023
Normal butane	(in gallons)		($ per gallon)			(in thousands)
Fixed price swaps
2024		5,169,600	$	0.85		$	(185	)
2025		3,206,500	$	0.79			(155	)
2026		872,000	$	0.78			(31	)
2027		54,000	$	0.79			(1	)
Total		9,302,100				$	(372	)

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	Volume		Weighted Average Price		Fair Value as of December 31, 2023
Pentane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		3,816,000	$	1.44	$	102
2025		2,313,600	$	1.35		(3	)
2026		579,500	$	1.32		25
2027		35,000	$	1.30		2
Total		6,744,100			$	126

The following tables provide information about our derivative financial instruments as of September 30, 2024:

	Volume		Weighted Average Price			Fair Value as of September 30, 2024
Oil	(in MBbls)		($ per Bbl)			(in thousands)
Fixed price swaps
2024		349	$	73.97		$	2,127
2025		1,383	$	71.81			6,761
2026		519	$	69.58			1,863
2027		35	$	68.04			85
Total		2,286				$	10,836
	Volume		Weighted Average Price			Fair Value as of September 30, 2024
Natural gas	(in MMBtu)		($ per MMBtu)			(in thousands)
Fixed price swaps
2024		1,605	$	3.84		$	1,464
2025		28,452	$	3.47			4,598
2026		23,356	$	3.69			958
2027		3,663	$	4.18			150
Total		57,076				$	7,170
	Volume		Basis Differential			Fair Value as of September 30, 2024
Natural gas	(in MMBtu)		($ per MMBtu)			(in thousands)1
Basis swaps
2024		5,741	$	(1.34	)	$	(2,100	)
2025		30,529	$	(1.04	)		(6,583	)
2026		20,098	$	(1.06	)		(2,225	)
2027		1,239	$	(1.03	)		(141	)
Total		57,607				$	(11,048	)
	Volume		Weighted Average Price			Fair Value as of September 30, 2024
Ethane	(in gallons)		($ per gallon)			(in thousands)
Fixed price swaps
2024		2,546,800	$	0.24		$	56
2025		12,133,000	$	0.25			281
2026		6,063,500	$	0.28			135
2027		435,000	$	0.30			15
Total		21,178,300				$	487

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	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Propane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		3,780,200	$	0.75	$	57
2025		17,764,200	$	0.72		(257	)
2026		8,080,500	$	0.70		5
2027		577,000	$	0.72		10
Total		30,201,900			$	(185	)
	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Isobutane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		841,400	$	0.93	$	(122	)
2025		3,755,600	$	0.87		(410	)
2026		1,667,500	$	0.83		(94	)
2027		114,000	$	0.82		(6	)
Total		6,378,500			$	(633	)
	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Normal butane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		1,246,400	$	0.88	$	(204	)
2025		5,869,500	$	0.83		(480	)
2026		2,686,000	$	0.81		(62	)
2027		192,000	$	0.81		(2	)
Total		9,993,900			$	(749	)
	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Pentane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		1,078,000	$	1.46	$	29
2025		4,818,600	$	1.42		89
2026		2,168,500	$	1.38		107
2027		149,000	$	1.35		7
Total		8,214,100			$	232

(1) These natural gas basis swap contracts are settled based on the difference between Dominion South or TETCO M2 price and the NYMEX price of natural gas during each applicable monthly settlement period.

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Changes in the fair value of derivative contracts from December 31, 2023 to September 30, 2024, are presented below:

(in thousands)	Commodity Derivative Asset (Liability)
Net fair value of oil and gas derivative contracts outstanding as of December 31, 2023	$	27,469
Commodity hedge contract settlement payments, net of any receipts		(27,755	)
Cash and non-cash mark-to-market gains (losses) on commodity hedge contracts (1)		6,397
Net fair value of oil and gas derivative contracts outstanding as of September 30, 2024	$	6,111

(1) At inception, new derivative contracts entered into by us have no intrinsic value.

Financing Agreements

Credit Facility

On September 25, 2024, we entered into a new credit facility led by Citibank, N.A. (the “Credit Facility”). The Credit Facility has a total facility size of $1.5 billion, an initial borrowing base of $325.0 million and available capacity of $100.3 million as of September 30, 2024. The Credit Facility replaced our Prior Credit Facility, which was terminated in connection with the entry into the Credit Facility. As of September 30, 2024, our reserves supported a $325.0 million facility of which $224.7 million was outstanding leaving $100.3 of unused capacity.

The Credit Facility also requires us to maintain compliance with the following financial ratios:

• Current ratio – the ratio of consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Amended and Restated Credit Facility and non-cash derivative liabilities) of not less than 1.0 to 1.0; and

• Leverage ratio – the ratio of total funded debt to consolidated EBITDAX of not greater than 3.0 to 1.0.

We intend to use the net proceeds of this offering to repay outstanding borrowings under the Credit Facility.

We were in compliance with the covenants and applicable financial ratios described above as of September 30, 2024.

Prior Credit Facility

On October 4, 2023, we entered into an amended and restated credit facility with a syndicate of banks led by the Bank of Oklahoma. Borrowings under our Prior Credit Facility were subject to borrowing base limitations based upon the collateral value of the pledged assets and were subject to semi-annual redeterminations. The Prior Credit Facility was scheduled to mature in April 2026, but it was terminated on September 25, 2024, in connection with entry into the Credit Facility.

The Prior Credit Facility also required us to maintain compliance with the following financial ratios:

• Current ratio – the ratio of consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Amended and Restated Credit Facility and non-cash derivative liabilities) of not less than 1.0 to 1.0; and

• Leverage ratio – the ratio of total funded debt to consolidated EBITDAX of not greater than 3.0 to 1.0.

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We were in compliance with the covenants and applicable financial ratios described above as of December 31, 2023.

Other long-term debt

Other long-term debt principally relates to car loans associated with the Company’s car fleet to support the Company’s team to service and maintain its operated wells.

Payments due by fiscal year related to other long-term debt as of December 31, 2023, are as follows:

	Long-Term Note Payable
(in thousands)
2024	$	124
2025		99
2026		43
2027		11
2028		—
Total payments	$	277

Critical Accounting Estimates

Our financial statements are prepared in accordance with U.S. GAAP. In connection with preparing of our financial statements, we are required to make assumptions and estimates about future events, and to apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with U.S. GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.

Our significant accounting policies are discussed in our audited financial statements included elsewhere in this prospectus. Management believes that the following accounting estimates are those most critical to fully understanding and evaluating our reported financial results, and they require management’s most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain.

Method of Accounting for Oil and Natural Gas Properties

We account for oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs, including non-productive costs and certain general and administrative costs such as salaries, benefits and other internal costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Under the full cost method of accounting, capitalized costs are amortized based on units-of-production and proved oil and natural gas reserves. If we maintain production levels year over year, our depreciation, depletion, and amortization expense may be significantly different if our estimates of remaining reserves or future development costs change significantly. On a quarterly basis, we review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC, which is referred to as a cost center ceiling test.

The primary factors impacting this test are reserve estimates and the unweighted arithmetic average of index prices on the first day of each month within the 12-month period that ends as of each quarterly balance sheet

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date. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices may have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes (which our predecessor, INR Holdings, has not been subject to historically for federal income tax purposes), is generally written off as an expense. We did not record any impairment of oil and natural gas properties for the nine months ended September 30, 2024 and 2023 or the years ended December 31, 2023 and December 31, 2022.

Additionally, costs associated with unevaluated properties are excluded from properties subject to amortization until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property at least annually for possible impairment. This assessment is subjective and includes consideration of numerous factors, including drilling plans, remaining lease terms, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. We did not record any impairment on our unevaluated properties during the nine months ended September 30, 2024 and 2023 or the years ended December 31, 2023 and December 31, 2022, but any such future impairment could potentially be material to our consolidated financial statements.

Oil and Natural Gas Reserves

Proved oil and gas reserves, as defined by SEC Regulation S-X, Rule 4-10, are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation.

Reserve estimates are prepared by our internal engineers and audited by independent engineers. Revisions may result from changes in, among other things, reservoir performance, development plans, prices, operating costs, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in certain proved reserves due to reaching economic limits sooner. A material change in the estimated volume of reserves could have an impact on the depletion rate calculation and our consolidated financial statements.

We estimate future net cash flows from natural gas, NGLs and oil reserves based on selling prices and costs using a 12-month average price, which is calculated as the unweighted arithmetic average of the first-day-of-the- month price for each month within the 12-month period and, as such, is subject to change in subsequent periods. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Income tax expense (which our predecessor, INR Holdings, has not been subject to historically for federal income tax purposes) is based on currently enacted statutory tax rates and tax deductions and credits available under current laws.

Revenue Recognition

We derive revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Our performance obligations are satisfied at a point in time and payments from purchasers are unconditional once the performance obligations have been satisfied, which occurs when control is transferred to the purchaser upon delivery of production volumes at a specified point. The pricing provisions of our contracts with customers are based on market indices, with certain adjustments for quality, supply and demand conditions, and location differentials, among other factors.

At the end of each month, we estimate the amount of production delivered to purchasers for that month and estimate revenues based on the price we expect to receive. Payments are generally received between 30 and

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60 days after the date of production. Any variances between our accrued revenue estimates and the actual amounts of payments received for the sales of our production are recorded in the month that each payment is received from our purchasers. Such variances have historically not been significant.

The revenue derived from our midstream activities is generated from gathering assets owned by our wholly- owned subsidiary, INR Midstream. We charge a gathering fee per MMBtu transported through our gathering system and fees are recognized as revenue based on measured volumes at the specified delivery points when the associated service is performed.

Derivative Instruments

We use commodity derivatives for the purpose of mitigating the risk resulting from fluctuations in the market prices of crude oil and natural gas. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, the prices at which we enter into commodity derivative contracts and counterparty creditworthiness. We do not use commodity derivative instruments for speculative or trading purposes.

We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using various inputs and assumptions including established index prices and other sources which are based upon, among other things, futures prices, time to maturity, implied volatilities and counterparty credit risk.

These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.

Tax Receivable Agreement

As described in “Corporate Reorganization,” Infinity Natural Resources will enter into a Tax Receivable Agreement in connection with the closing of this offering under which it will be contractually committed to pay the Existing Owners 85% of the net cash savings, if any, in U.S. federal, state and local income tax that Infinity Natural Resources (a) actually realizes with respect to taxable periods ending after this offering or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the INR board of directors) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of INR Units and the corresponding surrender of an equivalent number of shares of Class B common stock by the Existing Owners for a number of shares of Class A common stock on a one-for-one basis or, at our option, the receipt of an equivalent amount of cash pursuant to the INR Holdings LLC Agreement and (ii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement.

The projection of future taxable income and utilization of tax attributes associated with the Tax Receivable Agreement involve estimates which require significant judgment. The amount of the Company’s actual taxable income (which may differ from our estimates), passage of future legislation, or consummation of significant transactions in the future may significantly impact the liability related to the Tax Receivable Agreement. The Company will account for amounts payable under the Tax Receivable Agreement in accordance with Accounting Standard Codification Topic 450, Contingencies.

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JOBS Act

The JOBS Act permits us, as an “emerging growth company,” to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. We have elected to take advantage of this extended transition period, which means that the financial statements included in this prospectus, as well as any financial statements that we file or furnish in the future, will not be subject to all new or revised accounting standards generally applicable to public companies for the transition period for so long as we remain an emerging growth company.

Recent Accounting Pronouncements

In November 2023, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (an “ASU”) 2023-07, Segment Reporting (Topic 280)—Improvements to Reportable Segment Disclosures (“ASU 2023-07”), which updates reportable segment disclosure requirements primarily by enhancing disclosures about significant segment expenses and information used to assess segment performance. Additionally, ASU 2023-07 enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss and provides new segment disclosure requirements for entities with a single reportable segment. The amendments are effective for annual periods beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures. Adoption of the update is not expected to have a material impact to the Company’s financial position, results of operations or liquidity.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740)—Improvements to Income Tax Disclosures, which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated and provides additional requirements regarding income taxes paid. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted, and should be applied either prospectively or retrospectively. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures. Adoption of the update is not expected to have a material impact to the Company’s financial position, results of operations or liquidity.

The Company considers the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or not material upon adoption.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of SOX and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules with respect to Section 302 of SOX, which will require certifications in our quarterly and annual reports and provision of an annual management report on the effectiveness of our internal control over financial reporting. In connection with the audit of our consolidated financial statements as of December 31, 2023, and for the year then ended, our management and our independent registered public accounting firm identified deficiencies that represented material weaknesses in our internal control over financial reporting. We have identified material weaknesses in our internal control over financial reporting which relate to: (a) our general segregation of duties, including the review and approval of journal entries; (b) the lack of a formalized risk assessment process; (c) identification and implementation of control activities, including over information technology; (d) identification and application of a sufficient level of formal accounting policies and procedures; and (e) maintaining a sufficient complement of accounting and financial reporting resources commensurate with our financial reporting requirements.

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We will continue to monitor the effectiveness of our internal control over financial reporting in the areas affected by the material weaknesses described above and perform additional procedures prescribed by management. See “Risk Factors.”

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. The following table summarizes our obligations and commitments as of December 31, 2023 to make future payments under long-term contracts for the time periods specified below:

	2024		2025		2026		2027		2028		Thereafter		Total
(in thousands)
Prior Credit Facility Principal		—		—	$	170,964		—		—		—	$	170,964
Prior Credit Facility Interest(1)		15,558		15,558		5,186		—		—		—		36,302
Drilling Rig		3,150		—		—		—		—		—		3,150
Notes Payable		124		99		43		11		—		—		277
Operating Lease Liabilities		105		130		87		87		87		797		1,293
Asset Retirement Obligation		—		—		—		—		—		970		970
Total	$	18,937	$	15,787	$	176,280	$	98	$	87	$	1,767	$	212,956

(1) This debt bears interest at the Secured Overnight Financing Rate (“SOFR”) plus a borrowing spread. In determining future interest, we used outstanding amounts at December 31, 2023 and the average borrowing cost for calendar year 2023.

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 major 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

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fluctuations in response to relatively minor changes in supply and demand. Historically, the oil, natural gas and NGL markets have been volatile. 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, depend on numerous factors beyond our control, some of which are described under “Risk Factors.”

Our primary market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. 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. Based on our production for the year ended December 31, 2023, our oil and gas sales for the year ended December 31, 2023 would have moved up or down $8.5 million for each 10% change in oil prices per Bbl, $5.0 million for each 10% change in gas prices per Mcf, and $2.5 million for each 10% change in NGL prices per Bbl. Based on our production for the nine months ended September 30, 2024, our oil and gas sales for the first half of 2024 would have moved up or down $12.2 million for each 10% change in oil prices per Bbl, $3.6 million for each 10% change in gas prices per Mcf, and $3.1 million for each 10% change in NGL prices per Bbl.

Due to this volatility, we have historically used, and we may elect to continue to selectively use, commodity derivative instruments (such as collars, swaps, puts and basis swaps) to mitigate price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flows that can emanate from fluctuations in oil and natural gas prices, and thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, but alternatively they partially limit our potential gains from future increases in prices. Our Credit Agreement limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated, projected production from proved properties. “Risk Factors” 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 the Company, 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 Company’s Credit Agreement, all of which have investment-grade credit ratings.

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 natural gas depends on numerous factors outside of our control, none of which can be predicted with certainty. For 2023, 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 December 31, 2023, the Company’s reserves supported a $275 million credit facility of which $171 million in borrowings was outstanding leaving $104 million of unused capacity. As of September 30, 2024, INR Holdings’ reserves supported a $325.0 million Credit Facility of which $224.7 million was outstanding leaving $ 100.3 million of unused capacity. Our largest exposure with respect to variable-rate debt comes from

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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 December 31, 2023 and September 30, 2024, variable-rate debt, annual interest expense on variable-rate debt would increase by approximately $0.9 million and $1.1 million, respectively.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

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BUSINESS

Our Company

We are a growth oriented, free cash flow generating, independent energy company focused on the acquisition, development, and production of hydrocarbons in the Appalachian Basin. We are focused on creating shareholder value through the identification and disciplined development of low-risk, highly economic oil and natural gas assets while maintaining a strong and flexible balance sheet. Additionally, we have proven our ability to grow our acreage position through organic leasing efforts and accretive acquisitions. We are an early mover into the core of the Utica Shale’s volatile oil window in eastern Ohio as well as the emerging dry gas Utica Shale in southwestern Pennsylvania. Our Marcellus Shale development overlays our deep dry gas Utica assets in Pennsylvania, providing highly economic stacked development inventory that leverages the same company-owned midstream infrastructure. We have amassed approximately 93,000 net surface acres with exposure to the core of these plays providing us a unique and balanced portfolio of high-return oil and natural gas drilling locations. This balance allows us to optimize our development plan across our portfolio to capitalize on changes in commodity pricing over time.

We believe our technical and managerial expertise allow us to execute our strategies and deliver industry leading results. Our expertise is bolstered by the continuity of our core team, which has worked together for a decade. Since our initial acquisition in southwestern Pennsylvania in March 2018, we have drilled 47 wells and increased our operated horizontal well count from 2 to 131 with an additional two PDNP wells and seven DUCs, as of December 31, 2024. In total, we have increased our net daily production from virtually zero at the beginning of 2021 to 25 Mboe/d (29% oil and 49% liquids) for the quarter ended September 30, 2024. Since quarter end, we have placed an additional seven operated Ohio Utica wells into sales representing approximately 96,000 lateral feet.

The following chart shows our average net daily production by area for each quarter since bringing our first horizontal wells online in January 2021:

As of December 31, 2023, our total estimated proved reserves were 141,587 MBoe with 48% proved developed and 22% oil, 18% NGLs and 60% natural gas. As of December 31, 2024, our total drilling inventory consisted of 333 gross horizontal drilling locations (73 proved locations and 260 unproved locations), two PDNP wells and seven DUCs. Our drilling inventory represents 4.6 million lateral feet, implying 19 years of inventory at our current drilling pace of approximately 18 wells per year. Approximately 85% of our acreage is HBP, held by operations or held-by-storage, meaning we maintain development flexibility and have limited obligations to access our current inventory.

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The following table provides a summary of our approximate net acreage, gross drilling locations, net producing wells and lateral footage as of December 31, 2024 separated by shale (including acreage prospective for dual-zone development):

	As of December 31, 2024
	Net Horizon Acres(1)		Operated Producing Wells (#)		Operated Lateral Footage (in thousands)		Development Drilling Locations (#)			Development Lateral Footage (in thousands)		Development Average Well Lateral Length
Utica Shale Oil (OH)		62,702		118		954		158	(3)		2,109		13,349’
Marcellus Shale Dry Gas (PA)(2)		30,305		13		126		118	(4)		1,715		14,532’
Utica Shale Deep Dry Gas (PA)(2)		30,029		—		—		66			594		9,000’	(5)

(1) Does not include 12,605 net acres located in the Marcellus Shale in Ohio that is not part of our development plan.

(2) The acreage in this table reflects net horizon acres. Substantially all of our surface acreage in Pennsylvania is prospective for both the Utica and Marcellus Shales for dual-zone development. As a result, most of our net surface acres represent one horizon acre for the Utica Shale and one horizon acre for the Marcellus Shale. Our total net surface acreage irrespective of dual-zone development was 93,127 net acres and our total horizon acres were 123,036. See “—Our Operations—Acreage as of December 31, 2023” for information regarding our undeveloped and developed surface acreage.

(3) Includes two PDNP wells and two DUCs.

(4) Includes five DUCs.

(5) Utica Shale Deep Dry Gas (PA) land picture supports 14,000+ foot laterals.

Our oil volumes provide us with a unique advantage compared with many of our Appalachian Basin peers. Since our initial entry into the Utica Shale’s volatile oil window in April 2021, we have increased our oil production from less than approximately 300 Bbls/d to approximately 7,110 Bbls/d for the quarter ended September 30, 2024. The increase in our oil volumes is due to a combination of strategic acquisitions and organic development of our assets by placing into sales 22 wells during that period. We have also placed an additional seven operated Ohio Utica wells into sales (approximately 96,000 lateral feet) since quarter end. We believe that the oil component of our production provides greater revenue per Boe resulting in higher operating margins compared to our natural gas focused public peers in the Appalachian Basin.

The following chart shows our average net daily oil production for each quarter by county in Ohio since April 2021:

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Our Properties

Utica Shale Oil – Ohio

Given recent strength in the price of oil, our current activities are focused on developing our Ohio properties which are centered in the volatile oil window of the Utica Shale. Early commercial development of the Ohio Utica began principally in 2011 and has delineated bands of black oil, volatile oil, rich gas, and dry gas. Since 2019 through December 19, 2024, 322 wells have been drilled in the play, delineating the core of the play located in Carroll, Tuscarawas, Harrison, Guernsey, Noble, Muskingum and Morgan counties. Since January 2021 through September 2024, there have been 208 wells drilled that have been producing for over 90 days with an average IP 90 of 930 barrels of oil per day normalized to a 15,000’ lateral making the volatile oil window one of the leading oil resource plays in the lower 48 (compared to an average IP 90 of 1,098 barrels of oil per day per well normalized to 15,000’ lateral for our drilled Ohio Utica wells). When combined with the play’s low operating costs, low water production and low drilling costs, the Utica’s volatile oil window maintains one of the lowest breakeven costs amongst all oil resource plays in the United States.

We first acquired our properties in the volatile oil window of the Utica Shale in Ohio in April 2021 through our Carroll County Acquisition. Since that time, we have acquired 3,715 additional acres in Carroll County in close proximity to our existing assets through our organic leasing efforts that have added or extended 25 operated locations. In October 2023, we acquired assets from Utica Resource Ventures and PEO Ohio, including approximately 39,185 net acres, further expanding our operations in the core of the play. Since our acquisition, we have drilled 14 wells on the acquired acreage, 11 of which have been turned into sales and another one of which is PDNP. In February 2024, we were awarded the nomination for approximately 5,705 net acres within Salt Fork State Park in Guernsey County Ohio, adding over 23 locations averaging over 15,500 lateral feet per well to our inventory. On October 4, 2024, we entered into a lease with Muskingum Watershed Conservancy District for approximately 1,900 acres in Guernsey and Noble Counties, Ohio, representing 19 new or enhanced (which includes increased working interest or longer lateral length) drilling locations. Our understanding of geology, technical expertise and local presence gave us early insight into the quality of the play which led us to amass approximately 62,000 net surface acres with 154 identified horizontal drilling locations, two PDNP wells and two DUCs representing over 2 million lateral feet and nine years of drilling inventory based on our current one-rig program. We intend to operate 100% of our future drilling locations. As of December 31, 2024, we have 118 operated producing wells, two PDNP wells and two DUCs. Approximately 40,000 of our net surface acres in the Utica Shale in Ohio are located in Guernsey and Carroll counties of eastern Ohio, which, according to Enverus, have demonstrated among the highest oil production in the volatile oil window and are competitive with some of the best oil producing counties in the lower 48.

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The following chart shows the average first 12-months production in MBbls for wells drilled in the volatile oil window of Ohio compared to the top oil producing counties in the lower 48:

Source: Enverus.

Our management team has developed efficiencies and adopted procedures to enhance well performance and economics for the volatile oil window. Initial entrants did not have the benefit of current directional drilling technology or modern rig specifications to increase lateral lengths and ensure lateral placement in a progressively refined window. Early completions designs were sub-optimal and many operators used linear and cross linked gel that damaged the formation and reduced permeability which adversely impacted production rates. Our designs utilize enhanced completion fluids that allow for the placement of large proppant loads without reducing fracture permeability, which has resulted in some of the most productive development in the history of the play. To date, we have drilled the top eight, and 15 of the top 25, wells drilled in Carroll County since 2021 based on IP 90 of barrels of oil per day normalized to a 15,000’ lateral as shown in the following chart.

Source: Enverus.

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The characteristics that have contributed to our well performance include:

• improved wellbore targeting and placement accuracy in a tighter window in the lower zone of the Utica / Point Pleasant play;

• increasing average lateral lengths;

• optimized size and intensity of proppant and fluid pumped per lateral foot;

• optimized completion fluid chemistry and composition;

• optimized fracture stage lengths and cluster spacing;

• improved management of production rates to preserve downhole pressure; and

• improved adjustment of well spacing and development patterns.

Successful implementation of these measures has resulted in leading well performance relative to that of other major operators⁽¹⁾ in Carroll County since 2021 through October 2024 as seen in the chart below.

(1) Represents all INR drilled Carroll County wells.

(2) Peers include EOG and Encino.

(3) Represents the average cumulative production of the wells drilled on each respective pad.

Source: Enverus.

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Marcellus Shale Dry Gas and Utica Deep Dry Gas – Pennsylvania

Our Pennsylvania properties, which we initially acquired in March 2018, are predominately located to the northeast of Pittsburgh in Westmoreland, Armstrong and Indiana counties. We have expanded our leasehold position through a series of subsequent acquisitions and today have approximately 31,000 net surface acres with exposure to both Marcellus and Utica Shales and operate 13 producing horizontal wells and five DUCs. We maintain an inventory of 113 and 66 undeveloped Marcellus and Utica locations in Pennsylvania, respectively, representing approximately a decade of drilling inventory based on a one-rig drilling program. We intend to operate 100% of our future drilling locations and over 98% of our acreage is HBP or held-by-storage.

Marcellus Shale Dry Gas

Development of the Marcellus Shale initially began in the historic core in Washington and Greene counties in Pennsylvania. Outside that area, the acreage ownership remained fragmented, which resulted in slower upstream and midstream development despite attractive geology. Today, we have the opportunity to apply modern technology to this area of historic underdevelopment and generate not only attractive return potential, but also operational flexibility. We have drilled and completed 18 and 13 horizontal wells, respectively, in our Pennsylvania acreage with a 100% success rate. We have approximately 113 identified highly economic locations and five DUCs, which our independent reserve engineer has estimated have an EUR of 1.7 Bcf per 1,000 feet, and our returns are bolstered by our wholly owned midstream system. We currently own a gathering system and therefore are not subject to onerous takeaway contracts that burden the results of some of our Marcellus peers.

Utica Deep Dry Gas

Our Pennsylvania acreage overlays the dry gas Utica Shale providing 66 highly prospective locations, which our independent reserve engineer has estimated has an EUR of 3.0 Bcf per 1,000 feet. Development of the southwestern Pennsylvania deep dry gas Utica continues to emerge and show attractive commercial characteristics. Utica development in our vicinity began in 2015 when CNX turned into sales the Gaut 4HU well, which had a 24-hr IP rate of 61.4 MMcf/d and has produced 14.4 Bcf since July 2015. Since 2015, the industry has drilled twelve deep dry gas Utica wells in Westmoreland and Armstrong counties with another twelve wells currently in various stages of development all near our leasehold position. CNX recently drilled two wells (Bell Point 6NHSU and 6OHSU) with an average of 14,600 lateral feet per well approximately seven miles from our acreage position. We have 66 identified drilling locations in this area, and our land picture supports lateral lengths of 12,500 to 14,000+ feet. Moreover, the industry has shown an ability to develop offset locations to initial development by repeatedly returning to pad locations to drill. Industry advancement has led to a broader understanding of the technical drilling, targeted depths, completion designs, and production profiles associated with the Utica. These wells are characterized by maintaining a high level of initial gas production ranging between 20 MMcf/d to 30 MMcf/d of natural gas for an extended period of 15 to 20 months prior to initial decline. While early in its development, operators’ recent return to pad drilling further underscores the industry’s transition away from exploration to managed development highlighting the deliverability of results. The well performance makes the deep dry gas Utica in southwestern Pennsylvania an exciting emerging natural gas resource opportunity.

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Since 2015, cumulative dry gas production from Utica development has shown relatively flat production declines during the initial period of production as seen in the chart below.⁽¹⁾

(1) Gray lines represent recent Utica Dry Gas wells normalized to 9,000’ lateral: Aikens 5 S5JHSUT, Aikens 5 5MHSUT, Bell Point 6PHSU, Gaut 4IHSU, Poseidon 4U, Shaw 1DHSU, Shaw 1HHSU, Bell Point BP6NHSU, Bell Point BP6OHSU, Athena 4U and Athena 6U.

Business Strategy

Our strategy is to create value for our stockholders through the identification and disciplined development of attractive oil and natural gas assets to achieve sustainable growth in our production and reserves and enhance our value. Our strategy has the following principal elements:

• Disciplined growth through development of our high-return drilling inventory. Our technical acumen and in-basin experience enable us to optimize our assets and produce some of the highest performing wells in the region. We have achieved this performance through relentless focus on costs, consistent lengthening of our laterals, careful lateral placement in the target zone and thoughtful completion design. Our assets include over 19 years of operated drilling locations. In Ohio, our Utica oil productivity per lateral foot compares favorably with premier oil basins across the lower 48 such as the Permian, Eagle Ford and Bakken. In Pennsylvania, our contiguous HBP acreage and company-owned midstream infrastructure allow us to maximize the economics of the stacked Marcellus and Utica plays. We intend to continue our disciplined operating approach and to develop our inventory in order to achieve the highest available rates of return.

• Optimize return-on-capital through focus on profitably increasing well recoveries while minimizing costs and leveraging midstream infrastructure. We take pride in carefully evaluating every step of the operational process to optimize production while minimizing costs. This includes potentially changing completion designs at the stage level from well to well to enhance recoveries. We continuously review and examine our AFEs to drive our drilling and completion costs lower. Further, we promote cross-discipline communication to ensure that decisions are made on an integrated basis across our enterprise. Our owned midstream infrastructure in Pennsylvania significantly enhances returns by reducing upstream costs and generating third party revenue, while enabling us to control development timing, capital deployment and future strategic takeaway. We have improved netbacks on our Ohio assets through facility optimization and successful contract renegotiation. In addition to a relentless focus on new well planning

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and execution, we also review operations of acquired assets to determine whether upgrading or replacing equipment will be profitable. We have successfully enhanced production on a large number of wells that we have acquired.

• Ensure financial flexibility with balanced commodity exposure, and conservative financing. In building our company, we sought to preserve flexibility to maintain our focus on achieving the highest possible returns on investment. We have exposure to a range of assets that allow us to optimize our drilling economics across volatile commodity price environments. Additionally, we are not subject to any material midstream commitments or acreage expirations, which provides us the flexibility to match an optimal development pace to prevailing commodity prices and the hedging environment at any given time. Further, at the completion of this offering, we expect to have low net leverage positioning us to be immediately acquisitive. However, we intend to maintain a conservative capital structure with a target net leverage of less than 1.0x Adjusted EBITDAX.

• Leverage extensive industry and local experience to capture value through strategic acquisitions and asset base optimization. We have significant experience in sourcing, evaluating, executing and integrating acquisitions, including 14 privately sourced transactions. We believe our in-basin experience and local presence provides us with a competitive advantage in identifying opportunities and creating value through superior execution. We regularly initiate and review acquisition opportunities and intend to pursue future acquisitions that meet our strategic and financial objectives. We believe there are substantial opportunities to grow our acreage footprint across the Appalachian Basin through both acquisition and leasing. Additionally, our growth has been driven by increased operational efficiency, including reduced drilling days, well design modifications, facility optimization and continued focus on strategic, local procurement throughout our operations. Furthermore, we believe our contiguous acreage position and our ability to drill long-lateral wells will enhance our returns by increasing our EUR per well, reducing unit drilling and completion costs and providing economies of scale to allow us to better leverage our infrastructure. Further, given that we will be implementing an “Up-C” structure in connection with this offering, we will have the option in the future to offer acquisition targets equity in INR Holdings that can be exchanged for our Class A common stock (or cash of equivalent value) and offer a tax deferral mechanism, increasing the financial attractiveness of our platform to potential targets.

• Steward the health and safety of our employees and the environment, while taking an active role in our local community. We are dedicated to responsible energy development guided by our core values of environmental stewardship, safety and community engagement. While maintaining our commitment to our values, we actively seek business partners who share that commitment and will amplify our ability to achieve our goals. We use a top-down approach to provide resources and ensure our employees and partners are equipped to work in a safe environment. In 2023, our internal total recordable incident rate remained at 0.0 and our contractor blended rate was 1.6 with over 450,000 logged man-hours. We take pride in selectively choosing business partners with similar core values to help us achieve our goals. In addition to prioritizing high environmental standards and safe operations, we are committed to enriching the areas where we operate. We work diligently to make a strong economic impact in our communities and routinely volunteer both our time and resources to make a difference. Since our inception in 2017, we have partnered with 20 organizations in the region and have formed a community advisory panel to help actively expand our engagement within the area. Focusing on unconventional plays, we prioritize sustainable economic growth by producing natural resources responsibly. We invest considerable time and capital into accurately measuring and reducing production-related emissions like CO₂ and methane. Through innovative facility design and state of the art technology, we achieved a 51.9% reduction in CO₂e per MMBoe from 16,217.3 mT CO₂e/MMBoe in 2022 to 7,804 mT CO₂e/MMBoe in 2023, while methane intensity dropped from 0.14% to 0.076% of production between 2022 and 2023. Along with our environmental initiatives, we have established a culture which prioritizes safety.

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Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our business strategy, including:

• Disciplined operator with industry-leading costs and well performance. We profitably develop our drilling inventory by optimizing our well performance while also minimizing costs. Our leading well performance is driven by our high reservoir quality, technical expertise and unique acreage positions that allow for extended laterals. We have drilled 48 horizontal wells and participated in 19 non-operated wells since 2020 across our properties. Our proven approach is rooted in our ability to target well placement within the most productive layer of the reservoir for miles, routinely staying “in-zone” for the duration of the lateral. Further, we thoughtfully engineer the completion design for each well to place the ideal amount and type of proppant throughout the wellbore. The combination of these two practices contributes to higher recoveries per well. Our per unit development costs are improved by the economies of scale generated when consistently drilling long laterals, routinely exceeding 14,500 lateral feet, drilling these wells in multi-well deployments and building pads that allow for multiple drilling projects. Our Ohio Utica wells have an average IP 90 of 1,098 barrels of oil per day per well normalized to 15,000’ lateral. Further, we maintain low operating expenses and successfully navigate various commodity cycles by minimizing term acreage and long-term midstream and services commitments. We own and operate our gathering system in our Pennsylvania assets, which reduces our total midstream costs. These factors underpin our preference for operated positions in which we can control development techniques and capital allocation decisions. As a result, our Capital Efficiency Ratio was 3.0x for 2023, versus 1.0x for our Appalachia-Focused Public Peers and 2.0x for our Liquids-Focused Public Peers.

• Expansive portfolio of low-risk and high-return oil and natural gas inventory across multiple acreage positions. Our operations target an expansive portfolio of low-risk, high-return development opportunities with exposure to oil, natural gas and NGLs. Our oil-weighted activities are focused on the development of the Utica Shale’s volatile oil window in eastern Ohio. We operate 118 producing wells, two PDNP wells and two DUCs and have identified 154 additional drilling locations (greater than 2 million lateral feet) in the Ohio Utica Shale representing approximately nine years of repeatable development potential utilizing a one-rig development cadence as of December 31, 2024. Our natural gas activities are focused on the development of the dry gas Marcellus and dry gas Utica Shales in southwestern Pennsylvania. We currently operate 13 producing wells and five DUCs and maintain an inventory of approximately 179 drilling locations. We evaluate the risk-adjusted performance of our drilling results through two primary metrics: DROI and IRR. Applying both metrics in development decisions ensures that we are adequately balancing both the timing and amount of return of capital. Since 2021, we have drilled 32 wells and turned 28 wells into sales in the Utica volatile oil window, with an average IP 90 of 1,098 barrels of oil per day per well normalized to 15,000’ lateral. When combined with our leading cost structure, oil and natural gas development opportunities both generate significant cash flow and attractive rates of return.

• Balanced portfolio of oil and natural gas enables us to capitalize on commodity price volatility. The attractive rates of return possible in both our oil and natural gas properties provide us with a competitive advantage versus our peers, enabling us to selectively develop areas with the highest expected rate of return based on the prevailing commodity price environment. Our drilling inventory is approximately 46% oil weighted and 54% natural gas weighted measured by gross operated locations with attractive DROIs across both our oil and natural gas assets allowing us to pivot drilling activity quickly to take advantage of commodity prices. Our exposure to high return, oil-weighted inventory is unique within the Appalachian Basin enhancing our operating margins and cash flows relative to our regional peers. Our high quality natural gas position offers dual zone co-development of the Marcellus and deep dry gas Utica allowing us to leverage our infrastructure lowering our operating costs relative to our peers. Our optionality to oscillate between high quality natural gas and oil opportunities allows us to high-grade our portfolio and maximize resultant cash flow for our investors.

• Superior capital efficiency to support production growth with attractive free cash flow. We believe our full-cycle ratio compares favorably versus other industry players, illustrating our superior capital efficiency. Our superior capital efficiency enabled us to reduce acquisition borrowings over time and

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improve leverage while growing production from 5 MBoe/d to 25 MBoe/d over the course of April 2021 to September 2024. Looking forward, maintaining this level of capital efficiency will allow us to continue to prudently grow our assets while preserving optionality to return value to stockholders, manage liquidity and pursue strategic opportunities in our focus areas. Historically, we have used this free cash flow to develop our assets, grow production and repay debt.

• Conservatively capitalized balance sheet with strong liquidity profile. Maintaining a strong balance sheet is a principal focus of ours and a differentiator that creates a competitive advantage relative to our peers. Since our founding in 2017, we have regularly maintained leverage of less than 1.0x while prioritizing repaying amounts borrowed in connection with acquisitions. We expect to have minimal debt outstanding upon the completion of this offering and intend to maintain modest debt loads in the near term for working capital purposes. We believe our conservative leverage and substantial liquidity provide us the financial flexibility to fund our planned capital expenditures, return value to stakeholders and pursue strategic acquisitions. To date, we have maintained a disciplined hedging program that aims to hedge at least 70% of anticipated production for the next 24 months. We have and will continue to hedge into near term development programs to lock in project returns. In addition to benchmark pricing, we also hedge basis due to the historic volatility of basis differentials within our operating areas as well as individual commodities across oil, natural gas and NGLs. As of December 19, 2024, we have entered into hedging contracts covering approximately 1.58 MMBbls (approximately 4,350 Bbls/d) of our oil production for 2025 at a weighted average swap price of $71.51 per Bbl, approximately 1.0 MMBbls (approximately 2,790 Bbls/d) of our NGL production for 2025 at a weighted average swap price of $28.95 per Bbl, and approximately 33,321,000 MMBtu (approximately 91,000 MMBtu/d) of our gas production for 2025 at a weighted average swap price of $3.49 per MMBtu.

• Long track record of leveraging expertise and local presence to capture value through drill bit and mergers and acquisitions. We believe our management team’s experience in the Appalachian Basin and the continuity of our core team, which has worked together for over a decade, offers a distinguishing competitive advantage. Because of our local presence, we have extensive knowledge and deep relationships that enhance our ability to be a low-cost and highly productive operator and acquire assets at attractive valuations. We believe our local expertise has been a key contributor to our acquisition and leasing success, and we have earned a reputation as a partner of choice in the local community, which enhances our ability to compete for acreage. Our ability to quickly begin drilling on leased acreage has helped us manage our land costs and is a benefit to mineral owners. Additionally, we routinely increase our working interests in front of the drill bit to lengthen our wells and add incremental locations within and adjacent to our existing drilling units to leverage our existing infrastructure. Since our founding in 2017, we have completed 14 transactions across four distinct operated fields. Within each area, we have both improved performance of new wells by leveraging our drilling and completion techniques and optimized the legacy assets. Our local presence also helps to reduce service costs and improve availability. We believe that leveraging our strong and lasting relationships throughout the basin provides us with a unique and compelling competitive advantage that will yield positive returns for our stockholders.

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Our Operations

Operating Data

The following table provides certain operating information by operating area:

	Utica Shale Oil						Marcellus Shale Dry Gas		Utica Shale Deep Dry Gas
	Wolf Run		Warrior West		Warrior Central		PA North		PA North
Gross Locations		65		8		17		93		66
Locations Normalized to 10,000 feet		100		9		24		150		66
EUR (Mboe)		1,466		1,992		1,838		4,274		4,503
EUR per Lateral Foot(1) (Boe)		98		133		123		285		500
Percent Oil		47%		38%		25%		0%		0%
Average Lateral Length (in feet)		15,000		15,000		15,000		15,000		9,000	(5)
Average Well Cost(3) (in thousands)		11,295		11,220		11,220		10,993		10,152
$ per Lateral Foot	$	753	$	748	$	748	$	733	$	1,128
IRR		79%		94%		38%		66%		179%
Pre-Tax PV-10(4) (in millions)		12.8		15.9		6		15.7		26.5
DROI(4)		2.1x		2.4x		1.5x		2.4x		3.6x
Breakeven Price(2)	$	27.80/Bbl	$	20.00/Bbl	$	37.20/Bbl	$	1.35/Mmbtu	$	1.03/Mmbtu
Payback(4) (in months)		9		9		17		13		8

Note: All type curves reflect third party reserve audited forecasts. Well costs and operating costs are internal projections. Revenue is based on flat $70.00 oil and $3.50 gas prices.

(1) Normalized based on average EUR and Average lateral length in the area.

(2) Based on 10% discount rate.

(3) Excludes select road and location expenses.

(4) PV-10, DROI, and Payback are non-GAAP measures. See “Prospectus Summary—Non-GAAP Financial Measures” for a description of PV-10 and a reconciliation to the most directly comparable U.S. GAAP measure.

(5) PA North (Utica) land picture supports 14,000+ foot laterals.

Reserve Data and Presentation

The information with respect to our estimated reserves has been prepared in accordance with the rules and regulations of the SEC. Our estimated proved reserves as of December 31, 2023 and December 31, 2022 are based on valuations prepared by our independent reserve engineer, Wright. Copies of the summary reports of our reserve engineers as of December 31, 2023 and December 31, 2022 are filed as exhibits to the registration statement of which this prospectus forms a part. “—Preparation of Reserve Estimates” contains additional definitions of proved reserves and the technologies and economic data used in their estimation. The following tables summarize estimated reserves based on reports prepared by Wright. The information in the following tables does not give any effect to or reflect our commodity hedge portfolio.

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Summary of Reserves as of December 31, 2023 and 2022 Based on SEC Pricing

The following table provides the estimated reserves of INR Holdings as of December 31, 2023 and 2022 based on SEC pricing:

	December 31, 2023(1)			December 31, 2022(2)
Proved developed reserves:
Crude oil (MBbls)		13,172			2,995
Natural Gas (MMcf)		252,832			143,632
NGL (MBbls)		12,644			6,132
Total proved developed reserves (MBoe)(3)		67,954			33,066
Proved undeveloped reserves:
Crude oil (MBbls)		17,866			2,918
Natural Gas (MMcf)		255,893			214,706
NGL (MBbls)		13,118			8,020
Total proved undeveloped reserves (MBoe)(3)		73,633			46,723
Total proved reserves:
Crude oil (MBbls)		31,038			5,913
Natural Gas (MMcf)		508,725			358,338
NGL (MBbls)		25,762			14,152
Total proved reserves (MBoe)(3)(4)		141,587			79,788
Proved developed reserves (%)		48.0	%		41.4	%
Proved undeveloped reserves (%)		52.0	%		58.6	%
Reserve values (in thousands):
Standardized measure of discounted future net cash flows	$	938,384		$	1,017,607
Discounted future income tax expense		N/A			N/A
Total proved pre-tax PV-10(5)	$	938,384		$	1,017,607

(1) Our estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC regulations. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $78.22 per Bbl for oil and $2.637 per MMBtu for natural gas at December 31, 2023. These base prices were adjusted for differentials on a per property basis, including local basis differentials and fuel costs, resulting in $73.73 per Bbl for oil, $1.739 per MMBtu for natural gas, and $26.87 per Bbl for NGLs at December 31, 2023.

(2) Our estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC regulations. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $93.67 per Bbl for oil and $6.357 per MMBtu for natural gas at December 31, 2022. These base prices were adjusted for differentials on a per property basis, including local basis differentials and fuel costs, resulting in $88.67 per Bbl for oil, $5.606 per MMBtu for natural gas, and $41.21 per Bbl for NGLs at December 31, 2022.

(3) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

(4) All proved reserves as of December 31, 2023 were part of a development plan adopted by management indicating that such locations were scheduled to be drilled within five years of initial classification.

(5) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves and less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows. For more information on how we calculate PV-10 and a reconciliation of proved reserves PV-10 to its nearest GAAP measure, see “Prospectus Summary—Non-GAAP Financial Measures.” With respect to PV-10 calculated as of an interim date, it is not practicable to calculate the taxes for the related interim period because GAAP does not provide for disclosure of Standardized Measure on an interim basis.

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Proved Undeveloped Reserves (in MBoe)

Our 2023 proved undeveloped reserves increased by approximately 27 MMBoe, or 58%, compared to 2022. The following reconciliation from 2022 to 2023 is presented to meet SEC requirements to provide material changes to our proved undeveloped reserves during the year. All of our PUDs are associated with drilling locations that are scheduled to be drilled within five years of the initial disclosure of proved reserves.

Proved undeveloped reserves at December 31, 2022	46,723
Conversions into proved developed reserves(1)	(12,629	)
Acquisitions of in-place reserves(2)	27,778
Revisions(3)	(20,770	)
Extensions and discoveries(4)	32,532
Proved undeveloped reserves at December 31, 2023	73,633

(1) Conversions of PUD drilling locations in 2023 included developing eight (8) wells that were PUDs as of December 31, 2022, for which $74.2 million of capital expenditures were incurred during the year ended December 31, 2023.

(2) Acquisitions of in-place reserves relate to the Utica Resource Acquisition and the PEO Ohio Acquisition that closed on October 4, 2023 during the year ended December 31, 2023.

(3) Downward revisions of 20.8 MMBoe were comprised of 1.2 MMBoe of positive revisions related to increases in working interest, increased lateral length, and improvement in type curve, offset by downward revisions of 0.9 MMBoe in PUDs from 2022 to 2023 due to decreases in prices during the year ended December 31, 2023, as well as downward revisions of 21.1 MMBoe due to changes to our development plan that resulted in 18 PUD locations being reclassified as they were outside the 5 year development window while the Company performs further technical refinements and analysis to evaluate well spacing assumptions.

(4) Extensions primarily related to the addition of 21 PUD locations to be developed by 2028 (as that year entered the 5-year development window). These locations reside within the 5-year development window, which permits their recognition as PUD reserves based upon their continuing satisfaction of the engineering requirements for recognition as proved reserves. Extensions include the addition of new locations associated with our drilling program and additional Utica drilling in the 5-year development window.

Adjusted Index Prices Used in Reserve Calculations

The following tables show index prices used in our reserve calculations as of the dates indicated under historical SEC pricing:

Pricing Used for Proved Reserves as of December 31, 2023
Based on Historical SEC Pricing:
Oil (per Bbl)	$	73.73
Natural gas (per Mcf)	$	1.739
Natural gas liquids (per Bbl)	$	26.87
Pricing Used for Proved Reserves as of December 31, 2022
Based on Historical SEC Pricing:
Oil (per Bbl)	$	88.67
Natural gas (per Mcf)	$	5.606
Natural gas liquids (per Bbl)	$	41.21

Preparation of Reserve Estimates

Our reserve estimates as of December 31, 2023 and December 31, 2022 included in this prospectus are based on reports prepared by Wright, our independent reserve engineer, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC in effect

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at such time. Copies of the reports are included as exhibits to the registration statement containing this prospectus. Wright provides a variety of services to the oil and gas industry, including field studies, oil and gas reserve estimations, appraisals of oil and gas properties and reserve report for their clients.

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information and property ownership interests. Our independent reserve engineer uses this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves and EURs are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy). Proved undeveloped drilling locations that are more than one offset from a proved developed well utilized reliable technologies to confirm reasonable certainty. The reliable technologies that were utilized in estimating these reserves include log data, performance data, log cross sections, seismic data, core data, and statistical analysis.

Internal Controls

Our internal staff of petroleum engineers and geoscience professionals works closely with Wright to ensure the integrity, accuracy and timeliness of data furnished to Wright. Periodically, our technical team meets with Wright to review properties and discuss methods and assumptions used by us to prepare reserve estimates. Wright is an independent petroleum engineering and geological services firm.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs.

For all of our properties, our internally prepared reserve estimates and the reserve report prepared by Wright are reviewed and approved by our SVP of Commercial and Production.

Qualifications of Responsible Technical Persons

Our SVP of Commercial & Production, Ryan Warner, is responsible for overseeing the preparation of the reserves estimates. Mr. Warner is a founding member at Infinity Natural Resources and has over 10 years of relevant experience in reservoir engineering and reserve estimation. He holds a degree in Petroleum Engineering from West Virginia University and is a registered Professional Engineer.

Wright was founded in 1988 by Mr. D. Randall Wright and performs consulting petroleum engineering services including but not limited to annual reserves audits, property evaluation, and reservoir analysis. Mr. Wright is the primary technical person in charge of the estimates of reserves and associated cash flow and economics on behalf of Wright for the results presented. He holds a Master of Science degree in Mechanical Engineering from Tennessee Technological University. He is a registered Professional Engineer in the state of Texas (TBPE #43291), granted in 1978, a member of the Society of Petroleum Engineers (“SPE”) and a member of the Order of the Engineer.

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Mr. Adam Null, a registered Professional Engineer in the State of Tennessee (TBAEE #122667), has provided technical assistance in the estimates of reserves and cash flow results presented. Mr. Null is a member of the SPE and has been practicing petroleum engineering for more than ten years. He currently holds the title of Chief Operating Officer at Wright.

Mr. Wright and Mr. Null are qualified reserves evaluators as set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the SPE. This qualification is based on years of practical experience in the estimation and evaluation of petroleum reserves.

Production, Revenue, Price and Production Costs

The following table sets forth information regarding our production, revenues and realized prices and production costs for the years ended December 31, 2023 and 2022. The information presented as of and for the year ended December 31, 2023, includes the assets acquired in the Utica Resource Acquisition and the PEO Ohio Acquisition that closed on October 4, 2023. All of our production is derived from the Appalachian Basin. For additional information on price calculations, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Year Ended December 31,
	2023		2022
Production data:
Oil (MBbls)		1,205		640
Natural gas (MMcf)		27,506		11,585
NGL (MBbls)		1,112		656
Total (MBoe)(1)		6,901		3,227
Average daily production (MBoe/d)(1)		18.9		8.8
Average wellhead realized prices (before giving effect to realized derivatives):
Oil (/Bbl)	$	70.77	$	85.36
Natural gas (/Mcf)	$	1.80	$	5.70
NGL (/Bbl)	$	22.16	$	33.42
Average wellhead realized prices (after giving effect to realized derivatives):
Oil (/Bbl)	$	71.03	$	74.09
Natural gas (/Mcf)	$	2.42	$	3.48
NGL (/Bbl)	$	24.00	$	25.43
Operating costs and expenses (per Boe)(1):
Gathering, processing and transportation	$	4.51	$	4.86
Lease operating		2.66		2.56
Production and ad valorem taxes		0.13		0.22
Depreciation, depletion, and amortization		7.79		5.68
General and administrative		0.71		1.46
Total	$	15.80	$	14.78

(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

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Productive Wells as of December 31, 2023

As of December 31, 2023, we owned interests in the following number of productive wells:

	Productive Wells
	Gross		Net
Oil		114.0		86.6
Natural Gas		13.0		11.9
Total		127.0		98.5

Acreage as of December 31, 2023

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2023:

	Surface Acreage
	Gross		Net
Undeveloped acres		59,102		53,250
Developed acres		30,828		27,289
Total		89,930		80,539

Undeveloped Acreage Expirations as of December 31, 2023

The following table sets forth the gross and net undeveloped acreage, as of December 31, 2023, that will expire over the next five years unless production is established within the spacing units covering the acreage, the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates or pursuant to other terms of the lease agreements. We expect to drill wells on such acreage or make extension payments prior to lease expiration.

	Acreage
	Gross		Net
2024		795		664
2025		597		560
2026		694		582
2027		2,869		2,425
2028 and thereafter		1,556		1,556
		6,511		5,787

As of December 31, 2023, we had 14.6 MMBoe of proved undeveloped reserves that were associated with potentially expiring acreage.

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Drilling Activity

The table below sets forth the results of our operated drilling activities for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

	For the Year Ended December 31,
	2023				2022				2021
	Gross		Net		Gross		Net		Gross		Net
Development
Productive		10.0		9.1		7.0		6.6		6.0		6.0
Dry Hole		—		—		—		—		—		—
Exploratory
Productive		—		—		—		—		—		—
Dry Hole		—		—		—		—		—		—
Total		10.0		9.1		7.0		6.6		6.0		6.0

As of December 31, 2023, we had 8.0 gross (6.8 net) operated wells in process.

Major Customers

We generally sell our oil, natural gas and NGL production to purchasers at prevailing market prices, which in certain cases are adjusted for contractual differentials, and the majority of our revenue contracts have terms greater than twelve months.

We normally sell production to a relatively small number of customers, as is customary in our business. The table below summarizes the purchasers that accounted for 10% or more of our total net revenues for the periods presented:

	Year Ended December 31,
	2023			2022
Marathon Oil Company		49	%		38	%
BP America		28	%		46	%
Blue Racer Midstream		13	%		15	%

During these periods, no other purchaser accounted for 10% or more of our net revenues. As of December 31, 2023, INR Holdings’ accounts receivable balance related to oil and gas sales was comprised of amounts due from various purchasers, including amounts due from Marathon Oil Company, BP America, and Ergon comprising 56%, 24%, and 11%, respectively, of the total balance. As of December 31, 2022, INR Holdings’ accounts receivable balance related to oil and gas sales was comprised of amounts due from Marathon Oil Company and BP America, which accounted for 56% and 39%, respectively, of the total balance. The loss of any of our major purchasers could materially and adversely affect our revenues in the near-term. However, since crude oil and natural gas are fungible products with well-established markets and numerous purchasers and are based on current demand for oil and natural gas, we believe that the loss of any major purchaser would not have a material adverse effect on our financial condition or results of operations.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with

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respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

Prior to completing an acquisition of producing leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and/or encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

Seasonality

Generally, demand for oil, natural gas and NGL decreases during the spring and fall months and increases during the summer and winter months. However, certain natural gas and NGL markets utilize storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. In addition, seasonal anomalies such as mild winters or mild summers can have a significant impact on prices. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages, increased costs or delay operations.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in evaluating and bidding for oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may

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ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Legislative and regulatory environment

Our oil, natural gas and NGL exploration, development, production and related operations and activities are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with such rules and regulations can result in administrative, civil or criminal penalties, compulsory remediation and imposition of natural resource damages or other liabilities. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, we believe these obligations generally do not impact us differently or to any greater or lesser extent than they affect other operators in the natural gas and oil industry with similar operations and types, quantities and locations of production.

Regulation of production

In most states, oil and natural gas companies are generally required to obtain permits for drilling operations, provide drilling bonds, file reports concerning operations and meet other requirements related to the exploration, development and production of oil, natural gas and NGLs. Such states also have statutes and regulations addressing conservation and reclamation matters, including provisions for unitization or pooling of natural gas and oil interests, rights and properties, the surface use and restoration of properties upon which wells are drilled and disposal of water produced or used in the drilling and completion process. These regulations include the establishment of maximum rates of production from natural gas and oil wells, rules as to the spacing, plugging and abandoning of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production, as well as rules governing the surface use and restoration of properties upon which wells are drilled.

These laws and regulations may limit the amount of oil, natural gas and NGLs that can be produced from wells in which we own an interest and may limit the number of wells, the locations in which wells can be drilled or the method of drilling wells. Additionally, the procedures that must be followed under these laws and regulations may result in delays in obtaining permits and approvals necessary for our operations and therefore our expected timing of drilling, completion and production may be negatively impacted. These regulations apply to us directly as the operator of our leasehold. The failure to comply with these rules and regulations can result in substantial penalties.

Regulation of sales and transportation of hydrocarbon liquids

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress has enacted price controls in the past and could reenact such controls in the future.

Our sales of oil and NGLs are affected by the availability, terms and cost of transportation. The transportation of oil, NGLs and other hydrocarbon liquids in common carrier pipelines is subject to rate and access regulation. FERC regulates the rates and terms and conditions of service of interstate transportation of oil, NGL and other liquids by pipeline under the Interstate Commerce Act. Typically, liquids pipelines’ interstate transportation rates are set using a generally applicable annual indexing methodology; however, a pipeline may also use a cost-of-service approach, set rates via settlement with shippers or utilize market-based rates in certain circumstances. The rates we pay for interstate transportation of liquids by pipeline, and the related terms of service, may change as a result of regulatory proceedings.

Rates for intrastate transportation on liquids pipelines are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. Insofar as effective interstate and

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intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of liquids transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of transportation and sales of natural gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by agencies of the U.S. federal government, primarily FERC and its predecessor agency. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation of natural gas in interstate commerce remains subject to extensive regulation primarily under the NGA and NGPA, pursuant to regulations and orders promulgated by FERC. The rates we pay for transportation of natural gas by pipeline, and related terms of service, may change as a result of regulatory proceedings. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected, directly or indirectly, by laws enacted by Congress and by FERC regulations.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical and financial sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EPAct of 2005 and by the CFTC under the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Act, and regulations promulgated thereunder. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity as well as certain disruptive trading practices. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

The EPAct of 2005 amended the NGA and NGPA to add an anti-market-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC. The EPAct of 2005 also provided FERC with the power to assess civil penalties of up to $1,000,000 per day (adjusted annually for inflation) for violations of the NGA and NGPA. As of 2024, the new adjusted maximum penalty amount is $1,544,521 per violation, per day, in addition to disgorgement of profits associated with any violation. The civil penalty provisions are applicable to entities that engage in the sale and transportation of natural gas for resale in interstate commerce.

On January 19, 2006, FERC issued Order No. 670, implementing the anti-market-manipulation provision of the EPAct of 2005, and subsequently denied rehearing. The resulting rules make it unlawful, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to: (a) use or employ any device, scheme or artifice to defraud; (b) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (c) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-FERC jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services. FERC has also interpreted its authority to reach otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order No. 704, described below. However, in October 2022, the Fifth Circuit ruled that FERC’s jurisdiction to regulate market manipulation and assess penalties is limited to interstate natural gas transactions only and does not reach intrastate natural gas transactions.

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On December 26, 2007, FERC issued Order No. 704, a final rule on the annual natural gas transaction reporting requirements, as amended and clarified by subsequent orders on rehearing. As a result of these orders, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including oil and natural gas producers, gatherers and marketers, are now required to report, by May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance provided by FERC. Market participants must also indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transportation services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC. Although FERC has set forth a general test for determining whether natural gas facilities perform a non-jurisdictional gathering function or a jurisdictional transportation function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transportation facilities on which we transport our production as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. We believe that the natural gas pipelines in our own gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transportation services and federally unregulated gathering services could be the subject of litigation, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

In addition, the pipelines in the gathering systems on which we rely may be subject to safety regulation by the U.S. Department of Transportation through its Pipeline and Hazardous Materials Safety Administration (“PHMSA”). PHMSA has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. Over the past several years, PHMSA has taken steps to expand the regulation of rural gathering lines and impose a number of reporting and inspection requirements on regulated pipelines, and additional requirements are expected in the future. On November 15, 2021, PHMSA released a final rule that expands the definition of regulated gathering pipelines and imposes safety measures on certain previously unregulated gathering pipelines. The final rule also imposes reporting requirements on all gathering pipelines and specifically requires operators to report safety information to PHMSA. We could incur significant costs or liabilities to comply with these PHMSA requirements or similar State safety requirements. Failure to comply with the applicable requirements could result in penalties or fines. As of January 2024, the maximum civil penalties PHMSA can impose are $266,015 per violation per day, with a maximum of $2,660,135 for a related series of violations. Furthermore, the future adoption of laws or regulations that apply more comprehensive or stringent safety standards could increase the expenses we incur.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. As such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

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Changes in law and to FERC, PHMSA, CFTC, or state policies and regulations may adversely affect our own operations as well as the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines on which we transport natural gas. We cannot predict what future action FERC, PHMSA, CFTC, or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other oil and natural gas producers and marketers with which we compete.

Regulation of environmental and occupational safety and health matters generally

Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing environmental protection, occupational safety and health, and the release, discharge or disposal of materials into the environment, some of which carry substantial costs to maintain compliance and may impose substantial administrative, civil and criminal penalties for failure to comply. Applicable U.S. federal environmental laws include, but are not limited to, CERCLA, the CWA and the CAA. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the prevention and cleanup of pollutants and other matters. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit construction or drilling activities in sensitive areas such as wilderness, wetlands, frontier or other protected areas; require investigatory or remedial actions to prevent or mitigate pollution conditions caused by our operations; impose obligations to reclaim and abandon well sites and pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, loss of leases, the imposition of investigatory or remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be feasible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. It is possible that, over time, environmental regulation could evolve to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or remediation requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot be certain that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our business, there can be no assurance that this will continue in the future.

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The following is a summary of some of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and wastes

CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons known as potentially responsible parties, with respect to the release of “hazardous substances” into the environment. Potentially responsible parties include the current and past owners or operators of a disposal site or site where the release occurred and third parties who disposed or arranged for the disposal of the hazardous substances found at such sites. Under CERCLA, such persons may be subject to strict, joint and several and retroactive liability for the remediation of hazardous substances that have been released into the environment and for damages to natural resources. Neighboring landowners, governmental agencies, citizen organizations and other third parties may file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. We are only able to directly control the operation of those wells that we operate. The failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA and other environmental laws but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect our business operations. While petroleum and crude oil fractions are generally not considered hazardous substances under CERCLA and its analogues because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past.

We also generate, handle, transport, store and dispose of solid and hazardous wastes that may be subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and analogous state laws. RCRA regulates the generation, handling, storage, treatment, transport and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes “drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy” from regulation as hazardous wastes. With the approval of the EPA, individual states can administer some or all of the provisions of RCRA, and some states have adopted their own, more stringent requirements. However, legislation has been proposed from time to time and various environmental groups have filed lawsuits that, if successful, could result in the reclassification of certain natural gas and oil exploration and production wastes as “hazardous wastes,” and potentially subject such wastes to much more stringent handling, disposal and clean-up requirements. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes are determined to have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own, lease or operate numerous properties that may have been used by prior owners or operators for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations where such substances have been taken for recycling or disposal. In addition, some of our properties may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and/or analogous state laws. Under such laws, we could be

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required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water discharges

The CWA, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other natural gas wastes, into or near waters of the United States or state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The discharge of dredge and fill material into regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the Corps. In April 2020 the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. Further, the U.S. Supreme Court’s decision issued in May 2023 in Sackett v. EPA, held that the jurisdiction of the CWA to regulate WOTUS extends only to those adjacent wetlands that are indistinguishable from traditional navigable bodies of water due to a continuous surface connection. In September 2023, the EPA and the Corps published a direct-to-final rule redefining WOTUS to align with the decision in Sackett. To the extent a stay of recent rules or the implementation of a revised rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits, including for dredge and fill activities in wetland areas. Additionally, many states have similar requirements that apply to state waters where federal jurisdiction ends.

The process for obtaining permits also has the potential to delay our operations. For example, in January 2021, the Corps released the final version of a rule renewing twelve of its Nationwide Permits (“NWPs”), including NWP 12, the general permit issued by the Corps for pipelines and utility projects. The new rule, which took effect on March 15, 2021, splits NWP 12 into three parts; NWP 12 will continue to be available to oil and gas pipelines. On March 28, 2022, the Corps published a notice announcing that it is undertaking formal review of NWP 12 and sought public comments. The comment period ended on May 27, 2022. Any further changes to NWP 12 could have an impact on our business. We cannot predict at this time how the new Corps rule will be implemented because permits are issued by the local Corps district offices. If new oil and gas pipeline projects are unable to utilize NWP 12 or identify an alternate means of CWA compliance, such projects could be significantly delayed.

Additionally, spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” are required by federal law in connection with on-site storage of significant quantities of oil. Compliance may require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak.

Safe Drinking Water Act

The SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans. The SDWA also regulates saltwater disposal wells under the Underground Injection Control Program. The federal EPAct of 2005 amended the Underground Injection Control provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of “underground injection,” but disposal of hydraulic fracturing fluids and produced water or their injection for enhanced oil recovery is not excluded. In 2014, the EPA issued permitting guidance governing hydraulic fracturing with diesel fuels. While we do not currently use diesel fuels in our hydraulic fracturing fluids, we may become subject to federal permitting under SDWA if our fracturing formula changes or if there are other changes to the applicable provisions of the SDWA.

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Air emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and other requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 parts per billion. The EPA initiated a new review of the ozone NAAQS in August, 2023, and the results of the review remain outstanding. Further, in June 2016, the EPA also finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. These rules could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These and other laws and regulations concerning air emissions may increase the costs of compliance for some facilities where we operate.

State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In March 2024, the EPA adopted new rules under the CAA that require the reduction of volatile organic compound (“VOC”) and methane emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In addition, the regulations place new requirements to detect and repair volatile organic compound and methane at certain well sites and compressor stations. In December 2023, the EPA announced a final rule targeting methane emissions from new and existing oil and gas sources, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for certain requirements to a construction date of December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states, along with federal tribes, two years to develop and submit their plans for reducing methane emissions from existing sources, and those existing sources themselves have three years from the plan submission deadline to comply. Several states, including West Virginia and Ohio, are considering their own regulations related to methane emissions from oil and gas operations. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of natural gas projects and increase our costs of development, which costs could be significant. Further, compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment and increased frequency of maintenance and repair activities to address emissions leakage at certain well sites and compressor stations, and also may require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance.

Climate change

More stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses to comply with such laws and regulations. These requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. The EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations.

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At the international level, President Biden signed the instrument recommitting the U.S. to the Paris Agreement in January 2021 and, in April 2021, announced a goal of reducing U.S. emissions by 50-52% below 2005 levels by 2030. In September 2021, President Biden announced the “Global Methane Pledge,” an international pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. At COP28 in December 2023, member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the agreement, among other things, are to accelerate efforts toward the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies and take other measures that drive the transition away from fossil fuels in energy systems.

Additionally, in 2022, President Biden signed the Inflation Reduction Act (the “IRA”) which could accelerate the transition to a lower carbon economy. The IRA provides incentives for the development of renewable energy, clean hydrogen, clean fuels and supporting infrastructure and carbon capture and sequestration. In addition, the IRA includes a methane emissions reduction program that amends the Clean Air Act to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program. The methane charge and the incentives for renewable energy infrastructure development could impose additional costs on our operations and further accelerate the transition of the economy away from the use of natural gas towards lower- or zero-carbon emissions alternatives, which could in turn have an adverse impact on our business. Separately, various state and local governments have also vowed to continue to enact regulations to satisfy their proportionate obligations under the Paris Agreement. Additionally, some states have issued mandates to reduce emissions of GHGs, primarily through planned development of GHG emission inventories and potential cap-and-trade programs. Most of these types of programs require major sources of emissions or major producers of fuels to acquire and subsequently surrender emission allowances, with the number of allowances available being reduced each year until a target goal is achieved.

In addition, the SEC adopted the SEC Climate Rules, which will mandate detailed disclosure of certain climate-related information, including, among other items, material climate-related risks and related governance, strategy and risk management processes, certain financial statement disclosures and Scopes 1 and 2 GHG emissions, if material, for certain public companies. The SEC Climate Rules are currently stayed pending legal challenges and are widely expected to face additional legal challenges going forward. For these reasons, we cannot currently predict with certainty the timing and costs of implementation or any potential adverse impacts resulting therefrom. However, assuming that the SEC Climate Rules take effect, they may result in us experiencing additional operational and compliance burdens and incurring significant additional costs. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors. Regulations requiring the disclosure of similar climate-related information have also passed at the state-level.

Further, in January 2024, President Biden announced a temporary pause on pending decisions on exports of LNG to non-free trade agreement countries until the Department of Energy can update the underlying analyses for authorizations, including an assessment of the impact of GHG emissions. In a July 2024 ruling, the Western District of Louisiana stayed this temporary pause on LNG exports to non-free trade agreement countries. The Biden Administration appealed the ruling in August 2024 and the litigation remains ongoing. We cannot predict whether the pause may be reinstated. This and other changes in law and governmental policy may have impacts on our business that are difficult to anticipate.

The adoption and implementation of new or more stringent international, federal, state, or local legislation, regulations or other regulatory initiatives related to climate change or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for our products, and could require us to incur increased operating costs or otherwise have an adverse effect on our business, financial condition and results of operations.

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Hydraulic fracturing

Hydraulic fracturing is a common practice that is used to stimulate production of oil and/or natural gas from low permeability subsurface rock formations and is important to our business. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the hydrocarbon-bearing rock formation and stimulate production of hydrocarbons. We regularly use hydraulic fracturing as part of our operations. Presently, hydraulic fracturing is primarily regulated at the state level, but the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation. For example, the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels.

In addition, there are heightened concerns by the public about hydraulic fracturing causing damage to aquifers, and there is potential for future regulation to address those concerns. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that certain activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. To date, the EPA has taken no further action in response to the 2016 report.

At the state level, several states have adopted or are considering legal requirements that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. Local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Oil Pollution Act

The Oil Pollution Act of 1990 (the “OPA”) establishes strict liability for owners and operators of facilities that are the source of a release of oil into WOTUS. The OPA and its associated regulations impose a variety of requirements on responsible parties, including owners and operators of certain facilities from which oil is released, related to the prevention of oil spills and liability for damages resulting from such spills. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation or if the party fails to report a spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies to evaluate major federal actions having the potential to significantly impact the environment. The process involves the preparation of an environmental assessment and, if necessary, an environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action have the potential to significantly impact the environment. The NEPA process involves public input through comments, which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, may increase the costs of permitting and developing some facilities and could result, in certain instances, in the cancellation of existing leases. In July 2020, the Council on Environmental Quality (“CEQ”) revised NEPA’s implementing regulations to make the NEPA process more efficient, effective and

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timely. The rule required federal agencies to develop procedures consistent with the new rule within one year of the rule’s effective date (which was extended to two years in June 2021). These regulations are subject to ongoing litigation in several federal district courts, and in October 2021, CEQ issued a notice of proposed rulemaking to amend the NEPA regulatory changes adopted in 2020 in two phases. Phase 1 of the CEQ’s rulemaking process was finalized on April 20, 2022, and generally restored provisions that were in effect prior to 2020. In May 2024, the CEQ finalized the Phase 2 rule that would streamline and clarify NEPA reviews while maintaining consideration of relevant environmental, climate change and environmental justice effects. The final rule took effect in July 2024. However, several states and environmental groups have filed challenges to this rulemaking, and CEQ’s amendments are subject to reconsideration and may be subject to reversal or change in the future. Further, the Infrastructure and Investment Jobs Act, signed into law in November 2021, codified some of the July 2020 amendments in statutory text. These amendments must be implemented into each agency’s implementing regulations, and each of those individual rulemakings could be subject to legal challenge. Additionally, on June 3, 2023, President Biden signed the Fiscal Responsibility Act of 2023, which includes important changes to NEPA to streamline the environmental review process. The impact of changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our operations and our ability to obtain governmental permits.

Endangered Species Act and Migratory Bird Treaty Act

The ESA restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the MBTA. We may conduct operations on natural gas leases in areas where certain species that are or could be listed as threatened or endangered are known to exist. In February 2016, the FWS published a final policy which alters how it may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for natural gas development. The Trump administration issued rules that narrowed the definition of “habitat” and altered a policy in a way that made it easier to exclude territory from critical habitat. In October 2021, the Biden administration published two rules that reversed those changes, and in June and July 2022, the FWS issued final rules rescinding Trump-era regulations concerning the definition of “habitat” and critical habitat exclusions. In June 2023, the FWS issued three proposed rules governing critical habitat designation and expanding protection options for species listed as threatened pursuant to the ESA. Final rules were published in April 2024, and took effect in May 2024. The designation of previously unprotected species as threatened or endangered or new critical or suitable habitat designations in areas where we conduct operations could result in limitations or prohibitions on our operations and could adversely impact our business. It is possible the new rules could increase the portion of our lease areas that could be designated as critical habitat. It is also possible the October 2021 rules could increase the portion of our lease areas that could be designated as critical habitat. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

The Department of the Interior issued an opinion in December 2017 that would narrow certain protections afforded to migratory birds pursuant to the MBTA and finalized a rule in January 2021 limiting application of the MBTA. The MBTA makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests or eggs without a permit. The Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment to the Department of the Interior’s plan to develop regulations that authorize incidental take under certain prescribed conditions. The notice of proposed rulemaking was initially expected in October 2023 with a final rule to follow by April 2024; however, the notice of proposed rulemaking has not yet been issued. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

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Worker health and safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, the purpose of which is to protect the health and safety of workers. For example, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we maintain, organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Related permits and authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for ongoing operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

Related insurance

We maintain insurance against some contamination risks associated with our development activities, including a coverage policy for gradual pollution events. However, this insurance is limited to activities at the well site, and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

Employees

As of September 30, 2024, we had 75 employees, none of whom were subject to a collective bargaining agreement.

Legal Proceedings

We are party to various legal proceedings and claims in the ordinary course of our business. We believe these matters will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

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MANAGEMENT

Directors and Executive Officers

The following table sets forth the names, ages and titles of our directors, director nominees and executive officers.

Name	Age		Title
Zack Arnold		42	President, Chief Executive Officer and Director
David Sproule		45	Executive Vice President, Chief Financial Officer and Director
Raleigh Wolfe		38	General Counsel
Steven Cobb		36	Director
William J. Quinn		54	Director
Katherine M. Gallagher		41	Director Nominee
Scott Gieselman		61	Director Nominee
Steven D. Gray		65	Director Nominee
Sarah James		42	Director Nominee
David Poole		62	Director Nominee
Brian Seline		35	Director Nominee

Zack Arnold is our President and Chief Executive Officer and a director. Mr. Arnold has served as the President and Chief Executive Officer of Infinity Natural Resources, LLC since June 2017, when he also was appointed to Infinity Natural Resources Board of Managers. From 2014 to 2017, Mr. Arnold acted as the General Manager of Operations at Northeast Natural Energy (“NNE”). Prior to joining NNE, Mr. Arnold held various roles at Chesapeake Energy Corp. (Nasdaq: CHK) including Drilling Engineer, Completions Superintendent and Operations Manager. Mr. Arnold began his career as a Production Engineer with Chevron Corporation (NYSE: CVX) in Bakersfield, CA where he was exposed to the safety culture, operational excellence and the process-oriented mindset of a major energy company. Mr. Arnold is a graduate of Marietta College where he holds a degree in petroleum engineering.

We believe Mr. Arnold’s extensive industry background and deep knowledge of our business make him well qualified to serve on our board of directors.

David Sproule is our Executive Vice President and Chief Financial Officer and a director. Mr. Sproule was appointed Executive Vice President and Chief Financial Officer of Infinity Natural Resources, LLC in June 2017. Prior to joining Infinity Natural Resources, from July 2015 to June 2017, Mr. Sproule acted as a consultant advising exploration and production companies operating within the Appalachian Basin. Prior to that, Mr. Sproule was a director at Tudor Pickering, Holt & Co. advising exploration and production companies predominantly within the Appalachian Basin on strategic M&A and capital raising activities. Mr. Sproule is a graduate of Yale University where he holds a B.A. in History.

We believe Mr. Sproule’s extensive industry background and deep knowledge of our business make him well qualified to serve on our board of directors.

Raleigh Wolfe is our General Counsel. Mr. Wolfe has served as the General Counsel of Infinity Natural Resources, LLC since June 2024. Mr. Wolfe previously served as an attorney at Vinson & Elkins L.L.P. from October 2013 to June 2024, most recently in the role of Counsel, where he represented public and private companies in capital markets offerings and mergers and acquisitions, primarily in the oil and natural gas industry. Mr. Wolfe holds a Bachelor of Science degree from Clemson University, a Master of Business Administration from Louisiana State University and a Juris Doctor from Louisiana State University.

Steven Cobb is a member of our board of directors. Mr. Cobb is also a Partner of Pearl Energy Investments and has held such role since January 2025, and prior to that he was a Managing Director since August 2015. As a

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member of Pearl’s investment team, Mr. Cobb is involved in portfolio management, firm strategy, business development, LP relations and fundraising. Prior to joining Pearl, from August 2011 to August 2015, Mr. Cobb was employed at Pioneer Natural Resources, where he served as an Operations Engineer, Reservoir Engineer, and most recently, Supervisor of Investor Relations. Steven holds a B.S. in Petroleum Engineering from the University of Oklahoma and an M.B.A. in finance from Southern Methodist University.

We believe Mr. Cobb’s deep industry and investing experience make him well qualified to serve on our board of directors.

William J. Quinn is a member of our board of directors. Mr. Quinn is also a Founder and Managing Partner of Pearl Energy Investments. Prior to founding Pearl in 2015, Mr. Quinn served as Managing Partner of Natural Gas Partners. In his capacity as Managing Partner, he co-managed NGP’s investment portfolio and played an active role in the full range of NGP’s investment process. Mr. Quinn also serves on the boards of directors of a number of Pearl companies and their affiliates. Mr. Quinn currently serves on the board of directors of Permian Resources Corporation (NYSE: PR), a position he has held since September 2022. From September 2021 until May 2022, he served as a director and Chairman of the board of directors of Spring Valley Acquisition Corporation, which is now called NuScale Power Corporation (NYSE: SMR) following the company’s business combination in May 2022. Mr. Quinn holds a Master of Business Administration degree from the Stanford University Graduate School of Business and a Bachelor of Science degree in Economics, with honors, from the Wharton School of the University of Pennsylvania with a concentration in Finance.

We believe Mr. Quinn’s deep industry and investing experience make him well qualified to serve on our board of directors.

Katherine M. Gallagher currently serves as Co-President of the Board of Magdalene House Austin, and as a board member of the White Star Ranch Homeowner’s Association. Ms. Gallagher previously served as a Corporate Regulatory Advisor for Pioneer Natural Resources from September 2014 to May 2017. Prior to that, Ms. Gallagher served in various roles for Pioneer Natural Resources from September 2007 to September 2014, including as a Field Operations Manager, Operations Engineering Supervisor, Special Project Engineer and Senior Operations Engineer. Before that, Ms. Gallagher served as a Materials Engineer for Chevron Corp. from June 2005 to September 2007. Ms. Gallagher holds a Bachelor of Science degree in Metallurgical and Materials Engineering, with a minor in Economics, from the Colorado School of Mines, and a Master of Science degree in Petroleum Engineering from Texas A&M University.

We believe Ms. Gallagher’s deep experience and intimate knowledge of the oil, gas and energy industry makes her well qualified to serve on our board of directors.

Scott Gieselman was a Partner for NGP Energy Capital Management until 2023, a position he held since April 2007. Mr. Gieselman served as a director of certain private and public NGP portfolio companies. Prior to joining NGP, Mr. Gieselman served in various positions in the investment banking energy group of Goldman Sachs & Co. LLC, where he became a partner in 2002. Mr. Gieselman served as a director for Switchback II Corporation from December 2020 until the closing of its business combination with Bird Rides, Inc. in November 2021, Switchback Energy Acquisition Corporation from May 2019 until the closing of its business combination with ChargePoint Holdings, Inc. (NYSE: CHPT) in February 2021, HighPoint Resources Corporation from March 2018 until the closing of its merger with Bonanza Creek Energy, Inc. in April 2021, WildHorse Resource Development Corporation from September 2016 until it was acquired by Chesapeake Energy Corporation (NASDAQ: CHK) in February 2019, Chesapeake Energy Corporation from May 2019 to November 2019, Rice Energy, Inc. from January 2014 until April 2017, Memorial Resource Development Corp. from June 2014 until it was acquired by Range Resources Corporation (NYSE: RRC) in September 2016, and Memorial Production Partners GP LLC from December 2011 until March 2016. Mr. Gieselman holds a Master of Business Administration degree and a Bachelor of Science degree from Boston College.

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We believe Mr. Gieselman’s considerable financial and energy investment banking experience, as well as his experience on the boards of several public and private energy companies, makes him well qualified to serve on our board of directors.

Steven D. Gray served as Co-founder, Director, and Chief Executive Officer of RSP Permian Inc. from 2010 until its merger with Concho Resources (“Concho”) in 2018. After the merger with Concho, he joined Concho’s Board of Directors and served until Concho was acquired by ConocoPhillips (NYSE: COP) in 2021. Prior to forming RSP Permian, Mr. Gray founded several successful oil and gas ventures spanning nearly 20 years in partnerships with Natural Gas Partners, a Dallas, Texas based private equity firm. Before that, Mr. Gray spent 11 years employed in the oil and gas industry in various capacities as a petroleum engineer. Mr. Gray currently serves as Chairman of the Board of Directors of Permian Resources Corporation (NYSE: PR), as well as a Director on the Texas Tech Foundation Advisory Board. Mr. Gray previously served as a Director on the Board of Directors of Range Resources Corporation (NYSE: RRC) from October 2018 to October 2024. Mr. Gray holds a Bachelor of Science in Petroleum Engineering degree from Texas Tech University.

We believe Mr. Gray’s prior executive roles for numerous upstream oil and gas companies, including as CEO, as well as experience serving on the boards of multiple public oil and gas companies, makes him well qualified to serve on our board of directors.

Sarah James is currently a partner at Penvest Holdings, a private investment holding company. Ms. James served as Chief Financial Officer for Beard Energy Transition Acquisition Corporation (NYSE: BRD) from November 2021 to December 2023. From March 2020 to July 2021, Ms. James served as Chief Financial Officer for Alussa Energy Acquisition Corporation (NYSE: ALUS). From February 2013 to April 2020, Ms. James served as a vice president of finance and business development at Caelus Energy Alaska, LLC, a private company specializing in oil and gas exploration and production. Ms. James oversaw the company’s business development strategy, debt and equity fundraising and ongoing financial reporting functions. From January 2008 to August 2010, she served as a private equity associate at Riverstone Holdings, an energy, power and infrastructure-focused private equity firm. Prior to that, Ms. James served as an analyst at JPMorgan Securities, Inc., in the diversified industrials and natural resources group. Ms. James currently serves on the board of directors and audit committee of North American Helium Inc as well as the board of directors and nominating and governance committee of Stronghold Digital Mining, Inc. (Nasdaq: SDIG). Ms. James holds a Bachelor of Arts degree in Economics and English from Duke University and a Master of Business Administration and Master of Science: School of Earth Sciences from Stanford University.

We believe Ms. James’ financial expertise and experience makes her well qualified to serve on our board of directors.

David Poole is currently Of Counsel at the law firm of Wick Phillips LLP. Mr. Poole previously served as General Counsel and Corporate Secretary of Range Resources Corporation (NYSE: RRC) from June 2008 until March 2023. Prior to joining Range, Mr. Poole was with TXU Corp. (“TXU”) in its legal department from 2004 to 2008, serving most recently as General Counsel. Prior to joining TXU, Mr. Poole spent 16 years at the law firm of Hunton & Williams LLP, most recently as a Partner. Mr. Poole holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University and a Juris Doctor degree from the Texas Tech School of Law.

We believe Mr. Poole’s deep industry and legal experience, and prior roles in public oil, gas and energy companies makes him well qualified to serve on our board of directors.

Brian Seline is a Partner at NGP where he concentrates on the firm’s efforts in sourcing new investments, acquisition evaluation and serving on the boards of several private oil and gas investments. Mr. Seline joined NGP in July 2013 and has over a decade of experience in the energy industry. In his time with NGP, Mr. Seline has worked directly with over 20 upstream and midstream companies across the investment lifecycle. Prior to NGP, Mr. Seline was an Investment Banking Analyst with Barclays Capital’s Natural Resources Group in Houston from June 2011 to July 2013, where he focused on financing and merger and acquisition transactions in

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the oil and gas industry. Mr. Seline received a B.B.A. in Finance and a B.A. in Economics and minor in Government in 2011 from The University of Texas at Austin, where he graduated with Honors and was a member of the Phi Beta Kappa scholastic honor society.

We believe Mr. Seline’s deep industry experience and financial expertise make him well qualified to serve on our board of directors.

Board of Directors

In connection with the consummation of this offering, it is anticipated that our board of directors will be increased to ten directors. We currently have four directors, and, upon receiving notice of the effectiveness of the registration statement of which this prospectus forms a part, we plan to appoint six additional independent directors.

Our board of directors has determined that Messrs. Cobb, Gieselman, Gray, Poole, Quinn and Seline and Mses. Gallagher and James are each independent under the NYSE listing standards.

Our Amended Charter will provide Pearl with the right to nominate a majority of the members of our board of directors so long as it and its affiliates beneficially own more than 50% of the voting power of our common stock entitled to vote generally in the election of directors. When Pearl, together with its affiliates, beneficially owns less than 50% but more than 30% of the voting power of our common stock entitled to vote generally in the election of directors, Pearl will have the right to nominate a number of individuals to the board of directors proportionate to Pearl’s beneficial ownership of the voting power of the common stock of the Corporation entitled to vote generally in the election of directors, rounded up to the nearest whole number, which shall not be less than three (3). When Pearl, together with its affiliates, beneficially owns less than 30% but more than 20% of the voting power of our common stock entitled to vote generally in the election of directors, Pearl will have the right to nominate a number of individuals to the board of directors proportionate to Pearl’s beneficial ownership of the voting power of the common stock of the Corporation entitled to vote generally in the election of directors, rounded up to the nearest whole number, which shall not be less than two (2). When Pearl, together with its affiliates, beneficially owns less than 20% but at least 10% of the voting power of our common stock entitled to vote generally in the election of directors, Pearl will have the right to nominate one member to the board of directors. Furthermore, our Amended Charter will provide NGP with the right to nominate one (1) individual to our board of directors so long as it and its affiliates beneficially own at least 10% of the voting power of our common stock entitled to vote generally in the election of directors.

In evaluating a director candidate’s qualifications, we will assess whether such a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance our ability to manage and direct our affairs and business, including our board of directors’ committees. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.

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Committees of the Board of Directors

Upon the conclusion of this offering, we will have an audit committee, a compensation committee and a nominating, governance and sustainability committee of our board of directors, and we may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

Our board of directors has authorized the formation of an audit committee upon the completion of this offering. Our audit committee will consist of Mses. Gallagher and James and Mr. Gieselman, and Ms. James will serve as the committee chair. As required by the rules of the SEC and listing standards of the NYSE, the audit committee will consist solely of independent directors, subject to the phase-in exceptions. Those rules permit us to have an audit committee that has one independent member at the date our Class A common stock is first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. SEC rules also require that a public company disclose whether or not its audit committee has an “audit committee financial expert,” which is defined as a person whose experience yields the attributes outlined in such rules. Ms. James satisfies this requirement.

This committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to them, their performance and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements. We have adopted an audit committee charter to be effective upon the completion of this offering defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards, including SOX.

Compensation Committee

Our board of directors has authorized the formation of a compensation committee upon the completion of this offering. Our compensation committee will consist of Messrs. Gieselman, Gray and Poole, and Mr. Gieselman will serve as the committee chair. As required by the rules of the SEC and listing standards of the NYSE, the compensation committee will consist solely of independent directors, subject to the phase-in exceptions. Those rules permit us to have a compensation committee that has one independent member at the date our Class A common stock is first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter.

This committee establishes salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee also administers our incentive compensation and benefit plans. See “Executive Compensation” for a brief description of how we intend to make grants following this offering. We have adopted a compensation committee charter to be effective upon the completion of this offering defining the committee’s primary duties in a manner consistent with the rules of the SEC, the PCAOB and applicable NYSE standards.

Nominating, Governance and Sustainability Committee

Our board of directors has authorized the formation of a nominating, governance and sustainability committee (“NGS Committee”) upon the completion of this offering. Our NGS Committee will consist of Mses. Gallagher and James and Mr. Poole, and Mr. Poole will serve as the committee chair. As required by the rules of the SEC and listing standards of the NYSE, the NGS Committee will consist solely of independent directors, subject to the phase-in exceptions. Those rules permit us to have a NGS Committee that has one independent member at the date our Class A common stock is first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter.

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The NGS Committee will identify, evaluate and recommend qualified nominees to serve on our board of directors; develop and oversee our internal corporate governance processes; and maintain a management succession plan. We have adopted a charter for the NGS Committee to be effective upon the completion of this offering defining the committee’s primary duties in a manner consistent with the rules of the SEC and the listing standards of the NYSE.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve on the board of directors or compensation committee of another public company that has an executive officer that serves on our board of directors or compensation committee. No member of our board is an executive officer of another public company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors adopted a code of business conduct and ethics to be effective upon the completion of this offering applicable to our employees, directors and officers that complies with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

Prior to the completion of this offering, our board of directors adopted corporate governance guidelines to be effective upon the completion of this offering in accordance with the corporate governance rules of the NYSE.

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EXECUTIVE COMPENSATION

We are currently considered an “emerging growth company” within the meaning of the Securities Act for purposes of the SEC’s executive compensation disclosure rules. In accordance with those rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures regarding executive compensation for our last completed fiscal year. Further, our reporting obligations extend only to our “Named Executive Officers,” who are our principal executive officer and our next two other most highly compensated executive officers at the end of the fiscal year ending December 31, 2024 (the “2024 Fiscal Year”). Accordingly, our “Named Executive Officers” for the 2024 Fiscal Year are:

Name	Principal Position
Zack Arnold	President & Chief Executive Officer
David Sproule	Executive Vice President & Chief Financial Officer
Raleigh Wolfe	General Counsel(1)

(1) Mr. Wolfe was appointed as General Counsel of the Company on June 24, 2024.

2024 Summary Compensation Table

The following table summarizes the compensation awarded to, earned by or paid to our Named Executive Officers for the 2024 Fiscal Year and the fiscal year ended December 31, 2023.

Name and Principal Position	Year		Salary(1)		Bonus(2)		Option Awards(3)		All Other Compensation(4)		Total
Zack Arnold		2024	$	350,000	$	200,000	$	0	$	22,641	$	572,641
Chief Executive Officer		2023	$	281,250	$	141,000		—	$	30,796	$	453,046
David Sproule		2024	$	350,000	$	200,000	$	0	$	22,713	$	572,713
Executive Vice President & Chief Financial Officer		2023	$	281,250	$	141,000		—	$	33,000	$	455,250
Raleigh Wolfe		2024	$	155,738	$	156,000		—		—	$	311,738
General Counsel

(1) Amounts in this column reflect the base salary earned by each Named Executive Officer in the 2024 Fiscal Year. Mr. Wolfe’s annual base salary for the 2024 Fiscal Year was $300,000.

(2) Amounts in this column reflect for each of Messrs. Arnold, Sproule and Wolfe, (i) discretionary spot and holiday bonuses and (ii) a bonus for the 2024 Fiscal Year. Mr. Wolfe’s bonus for the 2024 Fiscal Year is a guaranteed bonus amount, subject to his continued employment, pursuant to the terms of the Wolfe Offer Letter (as defined in the section titled “Narrative Disclosure to Summary Compensation Table—Wolfe Offer Letter and Non-Disclosure Agreement”). The bonuses for Messrs. Arnold and Sproule for the 2024 Fiscal Year are discretionary bonuses earned by Messrs. Arnold and Sproule with respect to services performed during the 2024 Fiscal Year.

(3) In the 2024 Fiscal Year, Messrs. Arnold and Sproule were awarded 2024 Incentive Units (as defined in the section titled “Narrative Disclosure to Summary Compensation Table—Long-Term Equity Incentive Compensation”) that are intended to constitute profits interests for U.S. federal income tax purposes. Despite the fact that the 2024 Incentive Units do not require the payment of an exercise price, they are most similar economically to stock options. Accordingly, they are classified as “options” under the definition provided in Item 402(a)(6)(i) of Regulation S-K as an instrument with an “option-like feature.” The amounts in this column represent the aggregate grant date fair value of the 2024 Incentive Units granted to Messrs. Arnold and Sproule as computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718. The amounts reported in this column reflect the accounting cost for the 2024 Incentive Units and do not correspond to the actual economic value that may be received by Messrs. Arnold and Sproule in respect of the 2024 Incentive Units. See the section titled “Narrative Disclosure to Summary Compensation Table—Long-Term Equity Incentive Compensation” below for additional details on the 2024 Incentive Units.

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(4) Amounts in this column reflect (i) for each of Messrs. Arnold and Sproule, employer-paid 401(k) plan matching contributions equal to $17,250, respectively, (ii) for each of Messrs. Arnold and Sproule, a health insurance premium subsidy equal to $4,676 and (iii) for Messrs. Arnold and Sproule, the Company’s payment of their life insurance policy premiums equal to $715 and $787, respectively.

Narrative Disclosure to Summary Compensation Table

Confidentiality and Non-Compete Agreements

Messrs. Arnold and Sproule have not entered into any employment agreements with the Company (or any of its subsidiaries or affiliates). However, on June 6, 2017, Messrs. Arnold and Sproule each entered into a confidentiality and non-compete agreement (“Confidentiality Agreement”) with INR Holdings in connection with the commencement of his employment. The Confidentiality Agreements provide for the following restrictive covenants: (i) non-competition during employment and for a certain period (up to 24 months) following termination (as described further below), (ii) non-solicitation of employees or service providers during employment and for 24 months following termination, (iii) perpetual non-disclosure of confidential information, and (iv) assignment of intellectual property. The non-competition provisions in the Confidentiality Agreements are effective for either (a) the 24-month period following the termination of the executive’s employment for Cause (as defined in the Confidentiality Agreements), voluntary resignation, or breach of the Confidentiality Agreement, or (b) up to a 24-month period during which INR Holdings (or any of its subsidiaries or affiliates) makes severance payments to the executive following the termination of the executive’s employment without Cause, subject to the executive’s compliance with the Confidentiality Agreement. Any severance payments payable pursuant to the Confidentiality Agreements, if made at the discretion of INR Holdings (or any of its subsidiaries or affiliates) for purposes of enforcing the applicable non-competition provisions, are cash payments equal to the current monthly salary of the executive, payable in equal monthly installments for a period of up to 24 months following termination.

Wolfe Offer Letter and Non-Disclosure Agreement

Mr. Wolfe has not entered into any employment agreement with the Company (or any of its subsidiaries or affiliates). In connection with the commencement of his employment, Mr. Wolfe entered into an offer letter (the “Wolfe Offer Letter”) with the Company. The Wolfe Offer Letter provides for an annual base salary, an annual bonus opportunity (including a guaranteed bonus of $150,000 for the 2024 Fiscal Year) and eligibility to participate in the Company’s benefit plans and programs.

In addition, on June 24, 2024, Mr. Wolfe entered into a confidentiality and non-disclosure agreement with the Company in connection with the commencement of his employment, which provides for the non-disclosure of confidential information and assignment of intellectual property.

Long-Term Equity Incentive Compensation

We granted long-term equity incentive awards to Messrs. Arnold and Sproule in the form of membership interests in INR Holdings on July 17, 2024 (the “2024 Incentive Units”) and in 2017 (the “2017 Incentive Units,” and together with the 2024 Incentive Units, the “Incentive Units”), that are intended to constitute profits interests for U.S. federal income tax purposes. The Incentive Units are subject to time- and performance-based vesting requirements. The 2024 Incentive Units that are subject to time-based vesting requirements all remain unvested as of December 31, 2024. The 2017 Incentive Units that are subject to time-based vesting became fully vested prior to December 31, 2024. The Incentive Units that are subject to performance-based vesting all remain unvested as of December 31, 2024 and were not subject to any accelerated vesting provisions as of December 31, 2024.

Mr. Wolfe has not received any long-term equity incentive awards (including any Incentive Units) as of December 31, 2024.

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Outstanding Equity Awards at 2024 Fiscal Year-End

The following table reflects information regarding outstanding equity-based awards held by our Named Executive Officers as of December 31, 2024.

Name(1)	Option Awards(2)
	Number of Securities Underlying Unexercised Options (#) Exercisable(3)		Number of Securities Underlying Unexercised Options (#) Unexercisable(4)		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)(5)		Option Exercise Price ($)		Option Expiration Date
Zack Arnold		—		253,500		—		N/A		N/A
		—		—		760,500		N/A		N/A
		260,000		—		—		N/A		N/A
		—		—		780,000		N/A		N/A
David Sproule		—		253,500		—		N/A		N/A
		—		—		760,500		N/A		N/A
		260,000		—		—		N/A		N/A
				—		780,000		N/A		N/A

(1) As of December 31, 2024, Mr. Wolfe does not hold any outstanding equity-based awards.

(2) Awards in this table represent Incentive Units, which are intended to constitute profits interests for U.S. federal income tax purposes. Despite the fact that the Incentive Units do not require the payment of an exercise price or have an expiration date, they are most similar economically to stock options. Accordingly, they are classified as “options” under the definition provided in Item 402(a)(6)(i) of Regulation S-K as an instrument with an “option-like feature.”

(3) Awards in this column represent Incentive Units that have vested in accordance with their terms.

(4) Awards in this column represent Incentive Units that are unvested as of December 31, 2024 and (i) vest on an annual basis over a five-year period following July 17, 2024 (with vesting between such anniversaries after the first anniversary occurring pro rata) and (ii) accelerate and vest in full upon the occurrence of a Fundamental Change (as defined and discussed in the section titled “Additional Narrative Disclosure—Potential Payments Upon Termination or Change in Control”).

(5) Awards in this column represent Incentive Units that become vested when the members of INR Holdings who have contributed capital to INR Holdings receive cash distributions from INR Holdings equal to certain multiples of their capital contributions.

Additional Narrative Disclosure

Employee and Retirement Benefits

We currently provide broad-based health and welfare benefits, including health, life, vision, and dental insurance, to our full-time employees, including our Named Executive Officers. In addition, we currently make available a retirement plan intended to provide benefits under Section 401(k) of the Code, pursuant to which employees (including our Named Executive Officers) may elect to defer a portion of their compensation on a pre-tax basis and have it contributed to the plan. Pre-tax contributions are allocated to each participant’s individual account and are then invested in selected investment alternatives according to the participant’s directions. We match 100% of elective deferrals up to a maximum per participant per calendar year equal to 5% of the participant’s eligible compensation, in addition to making non-elective employer contributions. Employer-paid non-elective contributions pursuant to the 401(k) plan for the 2024 Fiscal Year, if any, have not yet been determined as of the date of this prospectus. Matching contributions to our 401(k) plan are not subject to vesting requirements. All contributions under our 401(k) plan are subject to certain annual dollar limitations in

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accordance with applicable laws, which are periodically adjusted for changes in the cost of living. Other than the 401(k) plan, we do not provide any qualified or non-qualified retirement or deferred compensation benefits to our employees, including our Named Executive Officers.

Potential Payments Upon Termination or Change in Control

Under the INR Holdings LLC Agreement, upon the occurrence of a “Fundamental Change” (as defined below), any then-unvested Incentive Units subject to time-based vesting requirements will automatically vest. See “Actions Taken in Connection with this Offering—Treatment of Incentive Units in Connection with this Offering” below for more information.

For this purpose, the term “Fundamental Change” generally means the occurrence of any of the following events: (i) (a) INR Holdings merges with an unrelated party, (b) the holders of outstanding interests of INR Holdings sell such interests in a transaction (or series of transactions) to an unrelated party or (c) INR Holdings sells all or substantially all of its assets to an unrelated party, and, in the case of any transaction described in this clause (i), our directors immediately before the consummation of such transaction are not at least a majority of the members of the managing body of the relevant entity immediately following the completion of such transaction; (ii) without approval of the board of INR Holdings, an unrelated party acquires 50% or more of the total voting power of all the then outstanding voting securities of INR Holdings; or (iii) INR Holdings is dissolved and liquidated.

Other than as described above and in the section entitled “Narrative Disclosure to Summary Compensation Table—Confidentiality and Non-Compete Agreements,” the Named Executive Officers are not eligible to receive any other potential payments upon a termination of employment or in connection with a change in control.

Director Compensation

We did not pay any compensation, make any equity awards or non-equity awards to, or pay any other compensation to, any of the non-employee members of our board of directors for the 2024 Fiscal Year.

We intend to implement a non-employee director compensation program that will take effect as of the closing of this offering, the terms of which have not yet been determined as of the date of this prospectus.

Actions Taken in Connection with this Offering

Treatment of Incentive Units in Connection with this Offering

In connection with the closing of this offering, it is anticipated that all outstanding (i) unvested Incentive Units will automatically vest and (ii) vested Incentive Units, including those that will have been unvested immediately prior to the closing as contemplated by the foregoing clause (i), will be recapitalized into INR Units. Messrs. Arnold and Sproule will receive approximately 1,796,588 and 1,796,581 INR Units, respectively, as a result of the recapitalization of their Incentive Units. See “Corporate Reorganization” for additional details regarding the treatment of outstanding Incentive Units in connection with the closing of this offering. Following the closing of this offering, there will be no further liability with respect to the Incentive Units and it is expected that any long-term incentive compensation will be awarded to our Named Executive Officers pursuant to the Omnibus Plan that we expect our board of directors to adopt in connection with this offering, as described in the paragraph below.

Omnibus Incentive Plan

Following the completion of this offering, we anticipate that our board of directors will adopt the Infinity Natural Resources, Inc. Omnibus Incentive Plan (the “Omnibus Plan”) for employees, consultants and directors prior to the

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completion of this offering. Our Named Executive Officers will be eligible to participate in the Omnibus Plan, which we expect will become effective upon the consummation of this offering. We anticipate that the Omnibus Plan will provide for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards intended to align the interests of service providers, including our Named Executive Officers, with those of our stockholders.

Securities to be Offered

Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the Omnibus Plan, a number of shares of Class A common stock equal to 10% of the number of shares of Class A common stock outstanding at the closing of this offering (on a fully diluted basis) (the “Share Reserve”) will be reserved for issuance pursuant to awards under the Omnibus Plan. No more than the Share Reserve may be issued pursuant to incentive stock options. Shares of Class A common stock subject to an award that expires or is canceled, forfeited, exchanged, settled in cash or otherwise terminated without delivery of shares and shares withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to, an award will again be available for delivery pursuant to other awards under the Omnibus Plan.

Administration

The Omnibus Plan will be administered by a committee of our board of directors (the “Committee”), except to the extent our board of directors does not duly authorize such Committee to administer the Omnibus Plan and in which case our board of directors will serve as the administrator. The Committee has broad discretion to administer the Omnibus Plan, including the power to determine the eligible individuals to whom awards will be granted, the number and type of awards to be granted and the terms and conditions of awards. The Committee may also accelerate the vesting or exercise of any award and make all other determinations and to take all other actions necessary or advisable for the administration of the Omnibus Plan. To the extent the Omnibus Plan administrator is not the Committee, our board of directors will retain the authority to take all actions permitted by the administrator under the Omnibus Plan. Additionally, our board of directors retains the right to exercise the authority of the Committee to the extent consistent with applicable law.

Eligibility

Our employees, consultants and non-employee directors, and employees and consultants of our affiliates, will be eligible to receive awards under the Omnibus Plan.

Non-Employee Director Compensation Limits

Under the Omnibus Plan, in a single fiscal year, a non-employee director may not be granted awards for such individual’s service on our board of directors having a value, taken together with any cash fees paid to such non-employee director, in excess of $750,000 (except that, for any year in which a non-employee director (i) first commences service on our board of directors, (ii) serves on a special committee of our board of directors or (iii) serves as lead director or non-executive chair of our board of directors, such limit is increased to $1,000,000).

Types of Awards

Stock Options. We may grant stock options to eligible persons, except that incentive stock options may only be granted to persons who are our employees or employees of one of our subsidiaries, in accordance with Section 422 of the Code. The exercise price of a stock option generally cannot be less than 100% of the fair market value of a share of Class A common stock on the date on which the stock option is granted and the stock option must not be exercisable for longer than 10 years following the date of grant. In the case of an incentive stock option granted to an individual who owns (or is deemed to own) at least 10% of the total combined voting

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power of all classes of our equity securities, the exercise price of the option must be at least 110% of the fair market value of a share of Class A common stock on the date of grant and the option must not be exercisable more than five years from the date of grant.

Stock Appreciation Rights. A stock appreciation right (“SAR”) is the right to receive an amount equal to the excess of the fair market value of one share of Class A common stock on the date of exercise over the grant price of the SAR. The grant price of a SAR generally cannot be less than 100% of the fair market value of a share of Class A common stock on the date on which the SAR is granted. The term of a SAR may not exceed 10 years. SARs may be granted in connection with, or independent of, other awards. The Committee has the discretion to determine other terms and conditions of a SAR award.

Restricted Stock Awards. A restricted stock award is a grant of shares of Class A common stock subject to the restrictions on transferability and risk of forfeiture imposed by the Committee. Unless otherwise determined by the Committee and specified in the applicable award agreement, the holder of a restricted stock award has rights as a stockholder, including the right to vote the shares of Class A common stock subject to the restricted stock award or to receive dividends on the shares of Class A common stock subject to the restricted stock award during the restriction period. In the discretion of the Committee or as set forth in the applicable award agreement, dividends distributed prior to vesting may be subject to the same restrictions and risk of forfeiture as the restricted stock with respect to which the distribution was made.

Restricted Stock Units. A restricted stock unit (“RSU”) is a right to receive cash, shares of Class A common stock or a combination of cash and shares of Class A common stock at the end of a specified period equal to the fair market value of one share of Class A common stock on the date of vesting. RSUs may be subject to the restrictions, including a risk of forfeiture, imposed by the Committee. If the Committee so provides, a grant of RSUs may provide a participant with the right to receive dividend equivalents.

Performance Awards. A performance award is an award that vests and/or becomes exercisable or distributable subject to the achievement of certain performance goals during a specified performance period, as established by the Committee. Performance awards (which include performance stock units) may be granted alone or in addition to other awards under the Omnibus Plan, and may be paid in cash, shares of common stock, other property or any combination thereof, in the sole discretion of the Committee.

Stock Awards. A stock award is a transfer of unrestricted shares of Class A common stock on terms and conditions, if any, determined by the Committee.

Dividend Equivalents. Dividend equivalents entitle a participant to receive cash, shares of Class A common stock, other awards or other property equal in value to dividends or other distributions paid with respect to a specified number of shares of Class A common stock. Dividend equivalents may be granted on a free-standing basis or in connection with another award (other than stock options, SARs, restricted stock or stock awards).

Other Stock-Based Awards. Other stock-based awards are awards denominated or payable in, valued in whole or in part by reference to, or otherwise based on or related to, the value of our shares of Class A common stock.

Cash Awards. Cash awards may be granted on terms and conditions, including vesting conditions, and for consideration, including no consideration or minimum consideration as required by applicable law, as the Committee determines in its sole discretion.

Substitute Awards. In connection with an entity’s merger or consolidation with the Company or the Company’s acquisition of an entity’s property or stock, awards may be granted in substitution for any other award granted before the merger or consolidation by such entity or its affiliates.

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Certain Transactions

If any change is made to our capitalization, such as a share split, share combination, share dividend, exchange of shares or other recapitalization, merger or otherwise, that results in an increase or decrease in the number of outstanding shares of Class A common stock, appropriate adjustments will be made by the Committee in the shares subject to an award under the Omnibus Plan. The Committee will also have the discretion to make certain adjustments to awards in the event of a change in control, such as accelerating the vesting or exercisability of awards, requiring the surrender of an award, with or without consideration, or making any other adjustment or modification to the award that the Committee determines is appropriate in light of such transaction.

Clawback

All awards granted under the Omnibus Plan will be subject to clawback, cancellation, recoupment, rescission, payback, reduction, or other similar action in accordance with any Company clawback or similar policy or any applicable law related to such actions.

Plan Amendment and Termination

Our board of directors or the Committee may amend or terminate any award, award agreement or the Omnibus Plan at any time; however, stockholder approval will be required for any amendment to the extent necessary to comply with applicable law. Stockholder approval will be required to make amendments that (i) increase the aggregate number of shares that may be issued under the Omnibus Plan or (ii) change the classification of individuals eligible to receive awards under the Omnibus Plan. The Omnibus Plan will remain in effect for a period of 10 years (unless earlier terminated by our board of directors).

Equity Grants

In connection with this offering, we expect to grant awards under the Omnibus Plan to our employees with respect to a total of approximately 162,500 shares of Class A common stock, including awards with respect to approximately 62,500 shares to Mr. Wolfe. These awards will be in the form of time-vested restricted stock units and will cliff vest on the one-year anniversary of the date of grant, subject to such employee’s continued service through such vesting date.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common stock (assuming the underwriters do not exercise their option to purchase additional common stock) that, in connection with the completion of this offering, will be owned by:

• each person known to us to beneficially own more than 5% of any class of our outstanding common stock;

• each of our Named Executive Officers;

• each member of our board of directors and each director nominee; and

• all of our directors, director nominees and executive officers as a group.

Except as otherwise noted, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the directors or Named Executive Officers, as the case may be.

To the extent that the underwriters sell more than 13,250,000 shares of common stock, the underwriters have the option to purchase up to an additional 1,987,500 shares from us.

The table below excludes any purchases that may be made in this offering through our directed share program or otherwise in this offering. See “Underwriting (Conflicts of Interest)—Directed Share Program.”

	Shares of Class A Common Stock Beneficially Owned					Shares of Class B Common Stock Beneficially Owned					Total Common Stock Beneficially Owned
Name of Beneficial Owner(1)	Number		Percentage			Number		Percentage			Number		Percentage
5% Stockholders:
Investment Funds managed by Pearl Energy Investments, L.P.(2)		—		—			28,894,732		63.3	%		28,894,732		49.1	%
Investment Funds managed by NGP(3)		—		—			9,631,441		21.1	%		9,631,441		16.4	%
Named Executive Officers, Directors and Director Nominees:
Zack Arnold		—		—			1,796,588		3.9	%		1,796,588		3.1	%
David Sproule		—		—			1,796,581		3.9	%		1,796,581		3.1	%
Steven Cobb		—		—			—		—			—		—
William J. Quinn(4)		—		—			28,894,732		63.3	%		28,894,732		49.1	%
Katherine M. Gallagher		—		—			—		—			—		—
Scott Gieselman		—		—			—		—			—		—
Steven D. Gray(5)		—		—			232,439		*			232,439		*
Sarah James		—		—			—		—			—		—
David Poole		—		—			—		—			—		—
Brian Seline		—		—			—		—			—		—
Raleigh Wolfe		—		—			—		—			—		—
Executive Officers, Directors and Director Nominees as a Group (11 persons)		—		—			32,720,340		71.7	%		32,720,340		55.6	%

* Less than 1%.

(1) Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Each of the holders listed has sole voting and investment power with respect to the common stock beneficially owned by the holder unless noted otherwise, subject to community property laws where applicable. Unless otherwise noted, the address for each beneficial owner listed below is 2605 Cranberry Square, Morgantown, WV 26508.

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(2) Represents the common stock held by PEI INR Holdings, L.P., Pearl Energy Investments III, L.P., PEI Infinity-S, LP and PEI INR Co-Invest-B Corp (the “Pearl Funds”). Pearl Energy Investments controls the investment decisions of the Pearl Funds and has management control over the Pearl Funds and accordingly may be deemed to share beneficial ownership of the common stock held by the Pearl Funds. The Pearl Funds are controlled by William J. Quinn, the founder and managing partner of Pearl Energy Investments. The principal address for each of the above referenced entities is 2100 McKinney Ave, Suite 1675, Dallas, TX 75201.

(3) Represents the common stock held by NGP XI US Holdings, L.P. (the “NGP Fund”). NGP XI Holdings GP, L.L.C. is the sole general partner of the NGP Fund, and NGP Natural Resources XI, L.P. is the sole member of NGP XI Holdings GP, L.L.C. G.F.W. Energy XI, L.P. is the sole general partner of NGP Natural Resources XI, L.P., and GFW XI, L.L.C. is the sole general partner of G.F.W. Energy XI, L.P. GFW XI, L.L.C. has delegated full power and authority to manage the NGP Fund to NGP Energy Capital Management, L.L.C. Chris Carter, Craig Glick, Philip Deutch and Jill Lampert serve on the Executive Committee of NGP Energy Capital Management, L.L.C. The principal address for each of the above referenced entities is 2850 N. Harwood Street, 19^th Floor, Dallas, TX 75201.

(4) Includes 28,894,732 shares of common stock held of record by the Pearl Funds. The Pearl Funds are controlled by William J. Quinn, the founder and managing partner of Pearl Energy Investments, L.P. Each of the Pearl Funds and Mr. Quinn may be deemed to have beneficial ownership of the shares of common stock held by the Pearl Funds. Mr. Quinn disclaims beneficial ownership of the shares held by the Pearl Funds except to the extent of his pecuniary interest therein. The principal address for Mr. Quinn is 2100 McKinney Ave, Suite 1675, Dallas, TX 75201.

(5) Includes (i) 23,244 shares of common stock held by Steven D. Gray and (ii) 209,195 shares of common stock held by the SD Gray Family Partnership LP (“SD Gray Family Partnership”), over which Mr. Gray has control. Mr. Gray controls the investment decisions of the SD Gray Family Partnership and has management control over the SD Gray Management Co., which is the general partner of the SD Gray Family Partnership, and accordingly may be deemed to share beneficial ownership of the common stock held by the SD Gray Family Partnership. The principal address for the SD Gray Family Partnership is 6440 Cherry Hills Dr, Frisco, TX 75036.

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CORPORATE REORGANIZATION

Infinity Natural Resources is a Delaware corporation that was formed for the purpose of making this offering. Following this offering and the transactions related thereto, Infinity Natural Resources will be a holding company whose sole material asset will consist of membership interests in INR Holdings. INR Holdings owns all of the outstanding membership interests in each of INR Operating, INR Ohio, INR Midstream, Block Island and Cheat Mountain, the operating subsidiaries through which INR Holdings operates its assets. After the consummation of the transactions contemplated by this prospectus, Infinity Natural Resources will be the managing member of INR Holdings and will control and be responsible for all operational, management and administrative decisions relating to INR Holdings business and will consolidate the financial results of INR Holdings and will report non-controlling interests in its consolidated financial statements related to the INR Units that the Existing Owners will own in INR Holdings.

This offering is being conducted through what is commonly referred to as an “Up-C” structure, which is often used by partnerships and limited liability companies undertaking an initial public offering. The Up-C structure provides the Existing Owners of the Company with the tax advantage of continuing to own interests in a pass-through structure, which is tax efficient because their allocable shares of income from INR Holdings will not be subject to entity-level tax. The Up-C structure will also provide potential future tax benefits for both the public company and the Existing Owners when they ultimately exchange their pass-through interests for shares of Class A common stock, which is expected to result in tax basis adjustments in the assets of INR Holdings and produce favorable tax attributes for us. We are a holding company, and immediately after the consummation of the reorganization transactions as described herein and this offering, our principal asset will be our ownership interests in INR Holdings. See “Corporate Reorganization—Holding Company Structure” and “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

In connection with this offering: (a) the Existing Owners’ LLC Interests (both capital interests and management incentive units) in INR Holdings will be recapitalized into a single class of units, the newly issued INR Units, with the INR Units to be allocated among the Existing Owners in accordance with the terms of the INR Holdings LLC Agreement and calculated using an implied valuation for INR Holdings based on the initial public offering price of our Class A common stock and (b) INR will contribute the net proceeds of this offering to INR Holdings in exchange for newly issued INR Units and a managing member interest in INR Holdings. Pursuant to the terms of the INR Holdings LLC Agreement, the INR Units to be issued to the Existing Owners in connection with the corporate reorganization will be calculated using an implied equity value of INR Holdings immediately prior to this offering, and the current relative levels of ownership in INR Holdings with the allocation of such units among our Existing Owners to be determined based on the initial public offering price. After giving effect to these transactions and the offering contemplated by this prospectus, (a) INR will own an approximate 22.5% interest in INR Holdings (or 25.0% if the underwriters’ option to purchase additional shares is exercised in full) and (b) the Existing Owners will own an approximate 77.5% interest in INR Holdings (or 75.0% if the underwriters’ option to purchase additional shares is exercised in full).

Each share of Class B common stock will entitle its holder to one vote on all matters to be voted on by stockholders. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation. We do not intend to list the Class B common stock on any stock exchange.

Based on its ownership in INR Holdings subsequent to the transactions and the offering contemplated by this prospectus, Infinity Natural Resources will have a variable interest in INR Holdings and INR Holdings will be a variable interest entity (“VIE”). Infinity Natural Resources will have an approximate 22.5% interest in INR Holdings (or 25.0% if the underwriters’ option to purchase additional shares is fully exercised) through which it will absorb the risks created and distributed by INR Holdings. As the managing member of INR Holdings based on the terms of the INR Holdings LLC Agreement, Infinity Natural Resources will have the sole power to direct

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the activities that most significantly impact the entity’s economic performance, with the remaining INR Unit Holders having no substantive kick-out or participating rights.

As such, Infinity Natural Resources determined that INR Holdings will be a VIE and that Infinity Natural Resources will be the primary beneficiary of INR Holdings. To make this determination, Infinity Natural Resources determined that its economic interest will give it both the power to direct the activities of INR Holdings that most significantly impact INR Holdings’ economic performance, as well as the obligation to absorb losses or the right to receive benefits that could potentially be significant to INR Holdings. In making this determination, Infinity Natural Resources considered the total economics of INR Holdings and whether its share of the economics through its ownership of INR Units will be significant, using qualitative and quantitative factors, where applicable.

Accordingly, Infinity Natural Resources as the primary beneficiary of INR Holdings will include INR Holdings in its consolidated financial statements. The portion of the consolidated INR Holdings that is owned by the INR Unit Holders and any related activity will be eliminated through non-controlling interests in the consolidated balance sheets and income attributable to non-controlling interests in the consolidated statements of operations of Infinity Natural Resources.

We will enter into a Tax Receivable Agreement with the Existing Owners. This agreement generally provides for the payment by INR to the Existing Owners of 85% of the net cash savings, if any, in U.S. federal, state and local income tax that INR (a) actually realizes with respect to taxable periods ending after this offering or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the INR board of directors) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of INR Units and the corresponding surrender of an equivalent number of shares of Class B common stock by the Existing Owners for a number of shares of Class A common stock on 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 Tax Receivable Agreement. INR will retain the benefit of the remaining 15% of these cash savings, if any. If we experience a change of control or the Tax Receivable Agreement terminates early, we could be required to make a substantial, immediate lump-sum payment. “Certain Relationships and Related Party Transactions—Tax Receivable Agreement” contains more information.

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The following diagrams indicate our simplified current ownership structure and our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised):

Simplified Current Ownership Structure

(1) Includes PEI INR Holdings, L.P., Pearl Energy Investments III, L.P., PEI Infinity-S, LP, Pearl Energy Investments, L.P., PEI INR Co-Invest-B Corp, NGP XI US Holdings, L.P. and certain members of management and the board of directors.

(2) Includes INR Ohio, INR Midstream, Block Island, INR Operating and Cheat Mountain.

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Simplified Ownership Structure After Giving Effect to this Offering

(1) Includes PEI INR Holdings, L.P., Pearl Energy Investments III, L.P., PEI Infinity-S, LP, Pearl Energy Investments, L.P., PEI INR Co-Invest-B Corp and NGP XI US Holdings, L.P., members of management and certain other individuals.

(2) Includes INR Ohio, INR Midstream, Block Island, INR Operating and Cheat Mountain.

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Existing Owners Ownership

The table below sets forth the percentage ownership of the Existing Owners in INR Holdings prior to this offering and after the consummation of this offering:

Existing Owners(1)	Percentage Ownership in INR Holdings Prior to this Offering			Equity Interests Following this Offering(2)
				Common Stock		Voting Power(%)
Pearl Energy Investments		73.4	%		28,894,732		49.1	%
NGP		24.5	%		9,631,441		16.4	%
Executive officers(3)		*	%		3,593,169		6.1	%
Other employees		*	%		2,896,193		4.9	%
Other investors		1.6	%		623,354		1.1	%

* Less than 1%.

(1) The number of INR Units and shares of Class B common stock to be issued to our Existing Owners is based on an implied equity value of INR Holdings immediately prior to this offering. Our Existing Owners will receive 45.6 million INR Units and an equal number of shares of our Class B common stock. The actual number of INR Units and shares of Class B common stock received by our Existing Owners will be determined after the closing of this offering based on the initial public offering price.

(2) Reflects the number of shares of Class B common stock (and corresponding INR Units) held by the Existing Owners, which are exchangeable for Class A common stock.

(3) Includes Messrs. Arnold and Sproule.

Offering

Only Class A common stock will be sold to investors pursuant to this offering. Immediately following this offering, there will be 13,250,000 shares of Class A common stock issued and outstanding and 45,638,889 shares of Class A common stock reserved for exchanges of INR Units (and the cancellation of the corresponding shares of Class B common stock pursuant to the INR Holdings LLC Agreement). We estimate that our net proceeds from this offering, after deducting estimated underwriting discounts and commissions and other offering related expenses, will be approximately $238.6 million. We intend to contribute all of the net proceeds of this offering to INR Holdings in exchange for 13,250,000 INR Units. INR Holdings will use approximately $224.7 million to pay off borrowings outstanding under the Credit Facility and the excess, if any, for general corporate purposes. “Use of Proceeds” contains more information.

As a result of the corporate reorganization and the offering described above (and prior to any exchanges of INR Units):

• the investors in this offering will collectively own 13,250,000 shares of Class A common stock (or 15,237,500 shares of Class A common stock if the underwriters exercise in full their option to purchase additional shares of Class A common stock);

• the Existing Investors will hold 45,638,889 shares of Class B common stock and a corresponding number of INR Units;

• the investors in this offering will collectively hold 22.5% of the voting power in us (or 25.0% if the underwriters exercise in full their option to purchase additional shares of Class A common stock); and

• the Existing Owners will hold 77.5% of the voting power in us (or 75.0% if the underwriters exercise in full their option to purchase additional shares of Class A common stock).

Effect of the Reorganization

The reorganization transactions are intended to create a holding company that will facilitate public ownership of, and investment in, us and are structured in a tax-efficient manner for the Existing Owners and are intended to provide tax advantages to the public company and such Existing Owners. The Existing Owners desire

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that their investment maintain its existing tax treatment as a partnership for U.S. federal income tax purposes not subject to entity-level tax and, therefore, will continue to hold their ownership interests in INR Holdings until such time in the future as they may elect to cause us to redeem or exchange their INR Units for a corresponding number of shares of our Class A common stock. Additionally, because the Existing Owners are entitled to have their INR Units redeemed or exchanged for a corresponding number of shares of our Class A common stock, the Up-C structure also provides the Existing Owners with potential liquidity for the LLC Interests that holders of non-publicly traded limited liability companies are not typically afforded.

The Up-C structure also provides future tax benefits for both the public company and the Existing Owners. As described further below under “—Holding Company Structure” and “Certain Relationships and Related Party Transactions—Tax Receivable Agreement,” additional acquisitions by Infinity Natural Resources of INR Units from any of the Existing Owners and any future taxable redemptions or exchanges by the Existing Owners of INR Units for shares of our Class A common stock are expected to result in tax basis adjustments with respect to the assets of INR Holdings that will be allocated to us and thus produce favorable tax attributes for us. These tax attributes are expected to reduce the amount of tax that we would otherwise be required to pay in the future. While the Tax Receivable Agreement will require us to pay the Existing Owners 85% of the amount of cash savings, if any, in our U.S. federal, state and local income tax or franchise tax that we actually realize from the utilization of such tax attributes, we will be able to retain the benefit of the remaining 15% of these tax savings.

Holding Company Structure

Our post-offering organizational structure will allow the INR Unit Holders to retain their equity ownership in INR Holdings, a partnership for U.S. federal income tax purposes and, as such, generally will not be subject to any entity-level U.S. federal income tax. Instead, any taxable income of INR Holdings will be allocated to holders of LLC Interests, including us. Investors in this offering will, by contrast, hold their equity ownership in the form of shares of Class A common stock in us, a corporation for U.S. federal income tax purposes. The holders of INR Units will generally incur U.S. federal, state and local income taxes on their proportionate share of any taxable income of INR Holdings.

In addition, pursuant to our certificate of incorporation and the INR Holdings LLC Agreement, our capital structure and the capital structure of INR Holdings will generally replicate one another and will provide for customary antidilution mechanisms in order to maintain the one-for-one exchange ratio between the INR Units (and a corresponding number of shares of Class B common stock) and our Class A common stock, among other things.

We and the INR Unit Holders will generally incur U.S. federal, state and local income taxes on our proportionate share of any taxable income of INR Holdings and will be allocated our proportionate share of any taxable loss of INR Holdings. The INR Holdings LLC Agreement will provide, to the extent cash is available, for distributions pro rata to us and the INR Unit Holders in an amount at least sufficient to allow us to pay our taxes and make payments under the Tax Receivable Agreement.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Corporate Reorganization

In connection with our corporate reorganization, we will engage in transactions with certain affiliates and our existing equity holders. “Corporate Reorganization” contains a description of these transactions.

INR Holdings LLC Agreement

Under the INR Holdings LLC Agreement, we will have the right to determine when distributions will be made to us and the INR Unit Holders and the amount of any such distributions. Following this offering, if we authorize a distribution, such distribution will be made to the INR Unit Holders and us on a pro rata basis in accordance with our respective percentage ownership of INR Units.

We and the INR Unit Holders will generally incur U.S. federal, state and local income taxes on our proportionate share of any taxable income of INR Holdings and will be allocated our proportionate share of any taxable loss of INR Holdings. Net profits and net losses of INR Holdings generally will be allocated to us and the INR Unit Holders on a pro rata basis in accordance with our respective percentage ownership of INR Units, except that certain non-pro rata adjustments will be required to be made to reflect built-in gains and losses and tax depreciation, depletion and amortization with respect to such built-in gains and losses. The INR Holdings LLC Agreement will provide, to the extent cash is available, for pro rata tax distributions to us and the INR Unit Holders in an amount at least sufficient to allow us to pay our taxes and make payments under the Tax Receivable Agreement.

The INR Holdings LLC Agreement will provide that, except as otherwise determined by us, at any time we issue a share of our Class A common stock or any other equity security (other than pursuant to an incentive plan, shareholders rights plan or to a member in connection with redemption of INR Units by such member), the net proceeds received by us with respect to such issuance, if any, shall be concurrently contributed to INR Holdings, and INR Holdings shall issue to us one INR Unit or other economically equivalent equity interest. Conversely, if at any time, any shares of our Class A common stock are redeemed, repurchased or otherwise acquired, INR Holdings shall redeem, repurchase or otherwise acquire an equal number of INR Units held by us, upon the same terms and for the same price, as such shares of our Class A common stock are redeemed, repurchased or otherwise acquired.

Under the INR Holdings LLC Agreement, the members have agreed that any member and/or its affiliates will be permitted to engage in business activities or invest in or acquire businesses which may compete with our business.

INR Holdings will be dissolved only upon the first to occur of (a) approval of its dissolution by the managing member and a vote in favor of dissolution by at least two-thirds of the holders of its INR Units, (b) a change of control transaction that is not approved by at least two-thirds of the holders of its INR Units, (c) such time as there are no remaining members of INR Holdings or (d) entry of a judicial order to dissolve INR Holdings. Upon dissolution, INR Holdings will be liquidated and the proceeds from any liquidation will be applied and distributed in the following manner (subject to establishing cash reserves for contingent liabilities): (i) first, to all expenses incurred in liquidation, (ii) second, to creditors in satisfaction of all debts, liabilities and obligations of INR Holdings and (iii) third, to the members in proportion to the number of INR Units owned by each of them.

Amended Charter

In connection with this offering, our Amended Charter will provide Pearl with the right to nominate a majority of the members of our board of directors so long as it and its affiliates beneficially own more than 50% of the voting power of our common stock entitled to vote generally in the election of directors. When Pearl, together with its affiliates, beneficially owns less than 50% but more than 30% of the voting power of our

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common stock entitled to vote generally in the election of directors, Pearl will have the right to nominate a number of individuals to the board of directors proportionate to Pearl’s beneficial ownership of the voting power of the common stock of the Corporation entitled to vote generally in the election of directors, rounded up to the nearest whole number, which shall not be less than three. When Pearl, together with its affiliates, beneficially owns less than 30% but more than 20% of the voting power of our common stock entitled to vote generally in the election of directors, Pearl will have the right to nominate a number of individuals to the board of directors proportionate to Pearl’s beneficial ownership of the voting power of the common stock of the Corporation entitled to vote generally in the election of directors, rounded up to the nearest whole number, which shall not be less than two. When Pearl, together with its affiliates, beneficially owns less than 20% but at least 10% of the voting power of our common stock entitled to vote generally in the election of directors, Pearl will have the right to nominate one member to the board of directors. Furthermore, in connection with this offering, our Amended Charter will provide NGP with the right to nominate one (1) individual to our board of directors so long as it and its affiliates beneficially own at least 10% of the voting power of our common stock entitled to vote generally in the election of directors.

Registration Rights Agreement

In connection with the closing of this offering, we will enter into a registration rights agreement with certain of the Existing Owners granting them registration rights. Under the registration rights agreement, we will agree to register the sale of shares of our common stock held by the Existing Owners and certain other holders under certain circumstances, and to provide such stockholders with certain customary underwritten offering, block trade and piggyback rights.

Directed Share Program

At our request, the underwriters have reserved up to 5% of the shares of Class A common stock offered by this prospectus for sale, at the initial public offering price to certain individuals through a directed share program, including our directors, officers, employees and other individuals we identify. The number of shares of our Class A common stock available for sale to the general public will be reduced to the extent these individuals purchase such reserved shares. Any reserved shares that are not so purchased will be offered by the underwriters to the general public on the same basis as the other shares offered by this prospectus. Participants in the directed share program will not be subject to the terms of any lock-up agreement with respect to any shares purchased through the directed share program, except in the case of shares purchased by any of our directors, officers or employees and our existing significant stockholders. Raymond James will administer our directed share program. We have agreed to indemnify Raymond James in connection with the directed share program, including for the failure of any participant to pay for its shares. Other than the underwriting discount set forth on the cover page of this prospectus, the underwriters will not be entitled to any commission with respect to shares of our Class A common stock sold pursuant to the directed share program. See “Underwriting (Conflicts of Interest)—Directed Share Program.”

Tax Receivable Agreement

We will enter into a Tax Receivable Agreement with the Existing Owners. This agreement generally provides for the payment by INR to the Existing Owners of 85% of the net cash savings, if any, in U.S. federal, state and local income tax that INR (a) actually realizes with respect to taxable periods ending after this offering or (b) is deemed to realize in the event of a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, asset sales and other forms of business combinations and certain changes to the composition of the INR board of directors) or the Tax Receivable Agreement terminates early (at our election or as a result of our breach) with respect to any taxable periods ending on or after such change of control or early termination event, in each case, as a result of (i) the tax basis increases resulting from the exchange of INR Units and the corresponding surrender of an equivalent number of shares of Class B common stock by the Existing Owners for a number of shares of Class A common stock on 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

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imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the Tax Receivable Agreement. INR will retain the benefit of the remaining 15% of these cash savings, if any. If we experience a change of control or the Tax Receivable Agreement terminates early, we could be required to make substantial, immediate lump-sum payments in the amount of approximately $134.3 million, including approximately $6.8 million to each of the Chief Executive Officer and Chief Financial Officer, approximately $80.9 million to Pearl, approximately $27.0 million to NGP and the remainder to other members of management.

Indemnification Agreements with our Directors and Officers

We intend to enter into indemnification agreements, to be effective upon the completion of this offering, with each of our directors and officers. The indemnification agreements and our governing documents will require us to indemnify our directors and officers to the fullest extent permitted by Delaware law. Subject to certain limitations, the indemnification agreements and our governing documents will also require us to advance expenses incurred by our directors and officers. For more information regarding these agreements, see “Description of Capital Stock—Limitations on Liability and Indemnification of Officers and Directors.”

Procedures for Approval of Related Party Transactions

Prior to the closing of this offering, we have not maintained a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

• any person who is, or at any time during the period was, one of our executive officers or one of our directors;

• any person who is known by us to be the beneficial owner of more than 5% of our common stock;

• any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our common stock; and

• any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

We anticipate that our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, we expect that our audit committee will review all material facts of all Related Party Transactions.

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DESCRIPTION OF CAPITAL STOCK

Upon completion of this offering our authorized capital stock will consist of 400,000,000 shares of Class A common stock, $0.01 par value per share, of which 13,250,000 shares will be issued and outstanding, 150,000,000 shares of Class B common stock, $0.01 par value per share, of which 45,638,889 shares will be issued and outstanding and 50,000,000 shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.

The following summary of the capital stock of Infinity Natural Resources, Amended Charter and Amended Bylaws does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our Amended Charter and Amended Bylaws, which are filed as exhibits to the registration statement of which this prospectus is a part.

Class A Common Stock

Holders of shares of our Class A common stock are entitled to one vote for each share held of record on all matters on which stockholders are entitled to vote generally, including the election or removal of directors elected by our stockholders generally. The holders of our Class A common stock do not have cumulative voting rights in the election of directors.

Holders of shares of our Class A common stock are entitled to receive dividends when, as and if declared by our board of directors out of funds legally available therefor, subject to any statutory or contractual restrictions on the payment of dividends and to any restrictions on the payment of dividends imposed by the terms of any outstanding preferred stock.

Upon our liquidation, dissolution or winding up and after payment in full of all amounts required to be paid to creditors and to the holders of preferred stock having liquidation preferences, if any, the holders of shares of our Class A common stock will be entitled to receive pro rata our remaining assets available for distribution.

All shares of our Class A common stock that will be outstanding at the time of the completion of the offering will be fully paid and non-assessable. The Class A common stock will not be subject to further calls or assessments by us. Holders of shares of our Class A common stock do not have preemptive, subscription, redemption or conversion rights. There will be no redemption or sinking fund provisions applicable to the Class A common stock. The rights powers, preferences and privileges of our Class A common stock will be subject to those of the holders of any shares of our preferred stock or any other series or class of stock we may authorize and issue in the future.

Class B Common Stock

Each share of Class B common stock will entitle its holder to one vote on all matters to be voted on by stockholders generally. If at any time the ratio at which INR Units are exchangeable for shares of our Class A common stock changes from one-for-one, for example, as a result of a conversion rate adjustment for stock splits, stock dividends or reclassifications, the number of votes to which Class B common stockholders are entitled will be adjusted accordingly. The holders of our Class B common stock do not have cumulative voting rights in the election of directors.

Holders of shares of our Class B common stock will vote together with holders of our Class A common stock as a single class on all matters on which stockholders are entitled to vote generally, except as otherwise required by law.

Holders of our Class B common stock do not have any right to receive dividends or to receive a distribution upon a liquidation, dissolution or winding up of Infinity Natural Resources.

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Any holder of Class B common stock that does not also hold INR Units is required to surrender any such shares of Class B common stock (including fractions thereof) to Infinity Natural Resources.

Preferred Stock

No shares of preferred stock will be issued or outstanding immediately after the offering contemplated by this prospectus. Our Amended Charter authorizes our board of directors to establish one or more series of preferred stock (including convertible preferred stock). Unless required by law or any stock exchange, the authorized shares of preferred stock will be available for issuance without further action by the holders of our common stock. Our board of directors is able to determine, with respect to any series of preferred stock, the powers (including voting powers), preferences and relative, participating, optional or other special rights, and the qualifications, limitations or restrictions thereof, including, without limitation:

• the designation of the series;

• the number of shares of the series, which our board of directors may, except where otherwise provided in the preferred stock designation, increase (but not above the total number of authorized shares of the class) or decrease (but not below the number of shares then outstanding);

• whether dividends, if any, will be cumulative or non-cumulative and the dividend rate of the series;

• the dates at which dividends, if any, will be payable;

• the redemption or repurchase rights and price or prices, if any, for shares of the series;

• the terms and amounts of any sinking fund provided for the purchase or redemption of shares of the series;

• the amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs;

• whether the shares of the series will be convertible into shares of any other class or series, or any other security, of us or any other entity, and, if so, the specification of the other class or series or other security, the conversion price or prices or rate or rates, any rate adjustments, the date or dates as of which the shares will be convertible and all other terms and conditions upon which the conversion may be made;

• restrictions on the issuance of shares of the same series or of any other class or series; and

• the voting rights, if any, of the holders of the series.

Anti-Takeover Effects of Our Amended Charter, Amended Bylaws and Certain Provisions of Delaware Law

Our Amended Charter, Amended Bylaws and the DGCL contain provisions, which are summarized in the following paragraphs, that are intended to enhance the likelihood of continuity and stability in the composition of our board of directors. These provisions are intended to avoid costly takeover battles, reduce our vulnerability to a hostile or abusive change of control and enhance the ability of our board of directors to maximize stockholder value in connection with any unsolicited offer to acquire us. However, these provisions may have an anti-takeover effect and may delay, deter or prevent a merger or acquisition of the company by means of a tender offer, a proxy contest or other takeover attempt that a stockholder might consider in its best interest, including those attempts that might result in a premium over the prevailing market price for the shares of Class A common stock held by stockholders.

Authorized but Unissued Capital Stock

Delaware law does not require stockholder approval for any issuance of shares that are authorized and available for issuance. However, the listing requirements of the NYSE, which would apply so long as our Class A common stock remains listed on the NYSE, require stockholder approval of certain issuances equal to or

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exceeding 20% of the then outstanding voting power of our capital stock or then outstanding number of shares of Class A common stock and Class B common stock on a combined basis. These additional shares may be used for a variety of corporate purposes, including future public offerings, to raise additional capital or to facilitate acquisitions.

Our board of directors may generally issue shares of one or more series of preferred stock on terms calculated to discourage, delay or prevent a change of control of the Company or the removal of our management. Moreover, our authorized but unissued shares of preferred stock will be available for future issuances in one or more series without stockholder approval and could be utilized for a variety of corporate purposes, including future offerings to raise additional capital, to facilitate acquisitions and employee benefit plans.

One of the effects of the existence of authorized and unissued and unreserved common stock or preferred stock may be to enable our board of directors to issue shares to persons friendly to current management, which issuance could render more difficult or discourage an attempt to obtain control of our company by means of a merger, tender offer, proxy contest or otherwise, and thereby protect the continuity of our management and possibly deprive our stockholders of opportunities to sell their shares of Class A common stock at prices higher than prevailing market prices.

Removal of Directors; Vacancies and Newly Created Directorships

Our Amended Charter provides that directors may be removed with or without cause upon the affirmative vote of a majority in voting power of all outstanding shares of stock entitled to vote generally in the election of directors, voting together as a single class, except for so long as Pearl or NGP, as applicable, have the right to designate for nomination any individual under our Amended Charter, the shares of common stock held by Pearl or NGP, as applicable, shall be the only shares of common stock entitled to vote on the removal without cause of such individual, and the shares of common stock owned by any other holders as of the record date for determining stockholders entitled to vote thereon shall have no voting rights with respect to such matter. In addition, our Amended Charter also provides that, subject to the rights granted to one or more series of preferred stock then outstanding or the board nomination rights granted to Pearl and NGP, any vacancies on our board of directors, and any newly created directorships, will be filled only by the affirmative vote of a majority of the directors then in office, even if less than a quorum, by a sole remaining director or by the stockholders.

No Cumulative Voting

Under Delaware law, the right to vote cumulatively does not exist unless the certificate of incorporation specifically authorizes cumulative voting. Our Amended Charter does not authorize cumulative voting. Therefore, stockholders holding a majority in voting power of the shares of our stock entitled to vote generally in the election of directors will be able to elect all our directors.

Special Stockholder Meetings

Our Amended Charter provides that special meetings of our stockholders may be called at any time only by or at the direction of the board of directors or the chairman of the board of directors; provided, however, at any time when Pearl, together with its affiliates, beneficially owns, in the aggregate, at least 35% in voting power of the stock entitled to vote generally in the election of directors, special meetings of our stockholders shall also be called by the board of directors or the chairman of the board of directors at the request of Pearl, and its affiliates. Our Amended Bylaws prohibit the conduct of any business at a special meeting other than as specified in the notice for such meeting. These provisions may have the effect of deterring, delaying or discouraging hostile takeovers, or changes in control or management of the company.

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Director Nominations and Stockholder Proposals

Our Amended Bylaws establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors, other than nominations made by or at the direction of the board of directors or a committee of the board of directors. In order for any matter to be “properly brought” before a meeting, a stockholder will have to comply with advance notice requirements and provide us with certain information. Generally, to be timely, a stockholder’s notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary of the date of the proxy statement released to stockholders for the preceding year’s annual meeting. Our Amended Bylaws also specify requirements as to the form and content of a stockholder’s notice. These provisions will not apply to Pearl or NGP and each of their respective affiliates so long as Pearl or NGP has board nomination rights. Our Amended Bylaws allow the chairman of the meeting at a meeting of the stockholders to adopt rules and regulations for the conduct of meetings which may have the effect of precluding the conduct of certain business at a meeting if the rules and regulations are not followed. These provisions may also defer, delay or discourage a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to influence or obtain control of the company.

Stockholder Action by Written Consent

Pursuant to Section 228 of the DGCL, any action required to be taken at any annual or special meeting of the stockholders may be taken without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken, is or are signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares of our stock entitled to vote thereon were present and voted, unless our Amended Charter provides otherwise. Our Amended Charter will preclude stockholder action by written consent at any time when Pearl together with its affiliates owns, in the aggregate, less than 35% in voting power of our stock entitled to vote generally in the election of directors.

Dissenters’ Rights of Appraisal and Payment

Under the DGCL, with certain exceptions, our stockholders will have appraisal rights in connection with a merger or consolidation of our company. Pursuant to the DGCL, stockholders who properly request and perfect appraisal rights in connection with such merger or consolidation will have the right to receive payment of the fair value of their shares as determined by the Delaware Court of Chancery.

Stockholders’ Derivative Actions

Under the DGCL, any of our stockholders may bring an action in our name to procure a judgment in our favor, also known as a derivative action, provided that the stockholder bringing the action is a holder of our shares at the time of the transaction to which the action relates or such stockholder’s stock thereafter devolved by operation of law.

Exclusive Forum

Our Amended Charter provides that unless we consent to the selection of an alternative forum, the Court of Chancery of the State of Delaware shall, to the fullest extent permitted by law, be the sole and exclusive forum for any (a) derivative action or proceeding brought on behalf of our company, (b) action asserting a claim of breach of a duty (including any fiduciary duty), or other wrongdoing, owed by any current or former director, officer, employee, agent or stockholder of our company to our company or our company’s stockholders, (c) action asserting a claim against our company or any current or former director, officer, employee, agent or stockholder of our company arising pursuant to any provision of the DGCL or our Amended Charter or Amended Bylaws, or (d) action asserting a claim against our company governed by the internal affairs doctrine. However,

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Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. As a result, the exclusive forum provisions will not apply to suits brought to enforce any duty or liability created by the Securities Act or any other claim for which the federal and state courts have concurrent jurisdiction, and we will not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder. Notwithstanding the foregoing, the federal district courts of the United States of America shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under U.S. federal securities laws, including the Securities Act and the Exchange Act. Any person or entity purchasing or otherwise acquiring any interest in shares of capital stock of our company shall be deemed to have notice of and consented to the forum provisions in our Amended Charter. Any person or entity purchasing or otherwise acquiring any interest in shares of capital stock of our company shall be deemed to have notice of and consented to the forum provisions in our Amended Charter. However, the enforceability of similar forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that a court could find these types of provisions to be unenforceable.

Conflicts of Interest

Delaware law permits corporations to adopt provisions renouncing any interest or expectancy in certain opportunities that are presented to the corporation or its officers, directors or stockholders. Our Amended Charter, to the maximum extent permitted from time to time by Delaware law, renounces any interest or expectancy that we have in, or right to be offered an opportunity to participate in, specified business opportunities that are from time to time presented to our officers, directors or stockholders or their respective affiliates, other than those officers, directors, stockholders or affiliates who are our or our subsidiaries’ employees. Our Amended Charter provides that, to the fullest extent permitted by law, neither Pearl, NGP or their affiliates or any director who is not employed by us (including any non-employee director who serves as one of our officers in both his director and officer capacities) or his or her affiliates will have any duty to refrain from (a) engaging in a corporate opportunity in the same or similar lines of business in which we or our affiliates now engage or propose to engage or (b) otherwise competing with us or our affiliates. In addition, to the fullest extent permitted by law, in the event that Pearl, NGP or any non-employee director acquires knowledge of a potential transaction or other business opportunity which may be a corporate opportunity for itself, herself or himself or its, her or his affiliates or for us or our affiliates, such person will have no duty to communicate or offer such transaction or business opportunity to us or any of our affiliates and they may take any such opportunity for themselves or offer it to another person or entity. Our Amended Charter does not renounce our interest in any business opportunity that is expressly offered to a non-employee director solely in his or her capacity as a director or officer of the company. To the fullest extent permitted by law, no business opportunity will be deemed to be a potential corporate opportunity for us unless we would be permitted to undertake the opportunity under our Amended Charter, we have sufficient financial resources to undertake the opportunity and the opportunity would be in line with our business.

Business Combination with Interested Stockholders

We will have opted out of Section 203 of the DGCL; however, our Amended Charter will contain similar provisions providing that we may not engage in certain “business combinations” with any “interested stockholder” for a three-year period following the time that the stockholder became an interested stockholder, unless:

• prior to such time, our board of directors approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder;

• upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding certain shares;

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• at or subsequent to that time, the business combination is approved by our board of directors and authorized at an annual special meeting of the stockholders, and not by written consent, by the affirmative vote of holders of at least 66 2/3% of our outstanding voting stock which is not owned by the interested stockholder;

• the stockholder became an interested stockholder inadvertently and (i) as soon as practicable divested itself of sufficient ownership to cease to be an interested stockholder and (ii) had not been an interested stockholder but for the inadvertent acquisition of ownership within three years of the business combination; or

• the business combination is proposed prior to the consummation or abandonment of, and subsequent to the earlier of the public announcement or the notice required under our Amended Charter of a proposed transaction which (i) constitutes one of the transactions described in the proviso of this sentence, (ii) is with or by a person who either was not an interested stockholder during the previous three years or who became an interested stockholder with the approval of our board of directors and (iii) is approved or not opposed by a majority of the directors then in office (but not less than one) who were directors prior to any person becoming an interested stockholder during the previous three years or were recommended for election or elected to succeed such directors by a majority of such directors; provided that the proposed transactions are limited to (x) our merger or consolidation (except for a merger in respect of which, pursuant to Section 251(f) of the DGCL, no vote of our stockholders is required), (y) a sale, lease, exchange, mortgage, pledge, transfer or other disposition (in one transaction or a series of transactions), whether as part of a dissolution or otherwise, of assets of ours or of any of our direct or indirect majority-owned subsidiaries (other than to any of our direct or indirect wholly-owned subsidiaries or to us) having an aggregate market value equal to 50% or more of either that aggregate market value of all of our assets determined on a consolidated basis or the aggregate market value of all our outstanding stock or (z) a proposed tender or exchange offer for 50% or more of our outstanding voting stock; provided further that we will give not less than 20 days’ notice to all interested stockholders prior to the consummation of any of the transactions described in clause (x) or (y) above.

Generally, a “business combination” includes any merger, asset or stock sale, or other transaction resulting in a financial benefit to the interested stockholder. Subject to certain exceptions, an “interested stockholder” is any person who, together with that person’s affiliates and associates, owns, or within the previous three years owned, 15% or more of our outstanding voting stock. For purposes of this section only, “voting stock” shall mean, with respect to any corporation, stock of any class or series entitled to vote generally in the election of directors and, with respect to any entity that is not a corporation, any equity interest entitled to vote generally in the election of the governing body of such entity.

Under certain circumstances, these provisions will make it more difficult for a person who would be an “interested stockholder” to effect various business combinations with us for a three-year period. These provisions may encourage companies interested in acquiring us to negotiate in advance with our board of directors because the stockholder approval requirement would be avoided if our board of directors approves either the business combination or the transaction which results in the stockholder becoming an interested stockholder. These provisions also may have the effect of preventing changes in our board of directors and may make it more difficult to accomplish transactions which stockholders may otherwise deem to be in their best interests.

Our Amended Charter will provide that “interested stockholders” for purposes of these provisions shall not include (x) Pearl or NGP or any of their affiliates, any of their respective direct or indirect transferees or any of their affiliates, or any other person with whom any of the foregoing are acting as a group or in concert for the purpose of acquiring, holding, voting or disposing of our stock or (y) any person whose ownership of shares in excess of 15% is the result of any action taken solely by us; provided, however, that for the purposes of this clause (y) only, such person shall be an interested stockholder if thereafter such person acquires additional shares of our voting stock, except as a result of further corporate action not caused, directly or indirectly, by such person.

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Limitations on Liability and Indemnification of Officers and Directors

The DGCL authorizes corporations to limit or eliminate the personal liability of directors and officers to corporations and their stockholders for monetary damages for breaches of directors’ and officers’ fiduciary duties, subject to certain exceptions. Our Amended Charter includes a provision that eliminates the personal liability of directors and officers for monetary damages to the corporation or its stockholders for any breach of fiduciary duty as a director or an officer, except to the extent such exemption from liability or limitation thereof is not permitted under the DGCL. The effect of these provisions is to eliminate the rights of us and our stockholders, through stockholders’ derivative suits on our behalf, to recover monetary damages from a director or an officer for breach of fiduciary duty as a director or an officer, including breaches resulting from grossly negligent behavior. However, exculpation does not apply to any breaches of the director’s or officer’s duty of loyalty, any acts or omissions not in good faith or that involve intentional misconduct or knowing violation of law, any authorization of dividends or stock redemptions or repurchases paid or made in violation of the DGCL, or for any transaction from which the director derived an improper personal benefit.

Our Amended Bylaws generally provide that we must defend, indemnify and advance expenses to our directors and officers to the fullest extent authorized by the DGCL. We also are expressly authorized to carry directors’ and officers’ liability insurance providing indemnification for our directors, officers and certain employees for some liabilities. We believe that these indemnification and advancement provisions and insurance are useful to attract and retain qualified directors and executive officers.

The limitation of liability, indemnification and advancement provisions in our Amended Charter and Amended Bylaws may discourage stockholders from bringing a lawsuit against directors or officers for breach of their fiduciary duty. These provisions also may have the effect of reducing the likelihood of derivative litigation against directors and officers, even though such an action, if successful, might otherwise benefit us and our stockholders. In addition, your investment may be adversely affected to the extent we pay the costs of settlement and damage awards against directors and officers pursuant to these indemnification provisions.

There is currently no pending material litigation or proceeding involving any of our directors, officers or employees for which indemnification is sought.

Indemnification Agreements

We intend to enter into an indemnification agreement with each of our directors and executive officers as described in “Certain Relationships and Related Person Transactions—Indemnification Agreements.” Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors or executive officers, we have been informed that in the opinion of the SEC such indemnification is against public policy and is therefore unenforceable.

Transfer Agent and Registrar

The transfer agent and registrar for our Class A common stock will be Equiniti Trust Company, LLC.

Listing

We have been approved to list our Class A common stock on the NYSE under the symbol “INR.” There is no established market for our shares of Class A common stock. The development and maintenance of a public market for our Class A common stock, having the desirable characteristics of depth, liquidity and orderliness, depends on the existence of willing buyers and sellers, the presence of which is not within our control or that of any market maker. The number of active buyers and sellers of shares of our Class A common stock at any particular time may be limited, which may have an adverse effect on the price at which shares of our Class A common stock can be sold.

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our Class A common stock. Future sales of our Class A common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our Class A common stock prevailing from time to time. As described below, only a limited number of shares will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our Class A common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price of our Class A common stock at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Sales of Restricted Shares

Upon completion of this offering, we will have outstanding an aggregate of 13,250,000 shares of Class A common stock. Of these shares, all of the 13,250,000 shares of Class A common stock to be sold in this offering (or 15,237,500 shares assuming the underwriters exercise the option to purchase additional shares in full) will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act (“Rule 144”) and other than certain shares sold pursuant to our directed share program that are subject to “lock-up” restrictions as described under “—Lock-up Agreements” below and “Underwriting (Conflicts of Interest).” All remaining shares of Class A common stock will be deemed “restricted securities” as such term is defined under Rule 144, including the Class A common stock issuable upon exchange of INR Units. The restricted securities were, or will be, issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act (“Rule 701”), which rules are summarized below.

In addition, subject to certain limitations and exceptions, pursuant to the terms of the INR Holdings LLC Agreement, the INR Unit Holders will each have the right to exchange all or a portion of their INR Units, along with a corresponding number of shares of Class B common stock, for Class A common stock at an exchange ratio of one share of Class A common stock for each INR Unit (and corresponding share of Class B common stock) exchanged, subject to conversion rate adjustments for stock splits, stock dividends and reclassifications or, at our election, an equivalent amount of cash. Upon consummation of this offering and related Corporate Reorganization, the Existing Owners will hold 45,638,889 INR Units, all of which (together with a corresponding number of shares of our Class B common stock) will be exchangeable for shares of our Class A common stock. “Certain Relationships and Related Party Transactions—INR Holdings LLC Agreement” contains additional information. The shares of Class A common stock we issue upon such exchanges would be “restricted securities” as defined in Rule 144 described below. However, upon the closing of this offering, we intend to enter into a registration rights agreement with certain of the Existing Owners that will require us to register under the Securities Act shares of Class A common stock owned by the Existing Owners. “Certain Relationships and Related Party Transactions—Registration Rights Agreement” contains additional information.

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, the shares of our Class A common stock (excluding the shares to be sold in this offering) that will be available for sale in the public market are as follows:

• no shares will be eligible for sale on the date of this prospectus or prior to 180 days after the date of this prospectus; and

• 45,638,889 shares will be eligible for sale upon the expiration of the lock-up agreements beginning 180 days after the date of this prospectus and when permitted under Rule 144 or Rule 701 (such number of shares includes the Class A common stock that may be issued upon exchange of all or a portion of the INR Units).

Lock-up Agreements

We, the Existing Owners and all of our directors and executive officers have agreed not to sell any Class A common stock or securities convertible into or exchangeable for shares of Class A common stock (including any

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shares purchased by them pursuant to the directed share program) for a period of 180 days from the date of this prospectus, subject to certain exceptions. “Underwriting (Conflicts of Interest)” contains a description of these lock-up agreements.

Rule 144

In general, under Rule 144 as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for a least six months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our Class A common stock or the average weekly trading volume of our Class A common stock reported through the NYSE, as applicable, during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Rule 701

In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering is entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

Stock Issued Under Employee Plans

We intend to file a registration statement on Form S-8 under the Securities Act to register shares of Class A common stock issuable under our omnibus incentive plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above.

Registration Rights

We expect to enter into a registration rights agreement with certain of the Existing Owners, which will require us to file and effect the registration of our Class A common stock held thereby (and by certain of their affiliates) in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. “Certain Relationships and Related Party Transactions—Registration Rights Agreement” contains additional information regarding the registration rights agreement.

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

The following is a summary of the material U.S. federal income tax considerations related to the purchase, ownership and disposition of our Class A common stock by a non-U.S. holder (as defined below) that acquired such Class A common stock pursuant to this offering and holds our Class A common stock as a “capital asset” within the meaning of Section 1221 of the Code (generally property held for investment). This summary is based on the provisions of the Code, U.S. Treasury regulations, administrative rulings and pronouncements and judicial decisions, all as in effect on the date hereof, and all of which are subject to change and differing interpretations, possibly with retroactive effect. A change in law may alter the tax considerations that we describe in this summary. We have not sought and do not intend to seek any ruling from the IRS with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.

This summary does not address all aspects of U.S. federal income taxation that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal estate or gift tax laws, any state, local or non-U.S. tax laws or any tax treaties. This summary also does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as:

• existing equityholders and creditors of the Company;

• banks, insurance companies or other financial institutions;

• tax-exempt or governmental organizations;

• “qualified foreign pension funds” as defined in Section 897(l)(2) of the Code (or any entities, all of the interests of which are held by a qualified foreign pension fund);

• dealers in securities or foreign currencies;

• persons whose functional currency is not the U.S. dollar;

• “controlled foreign corporations,” “passive foreign investment companies” and corporations that accumulate earnings to avoid U.S. federal income tax;

• traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes;

• persons subject to the alternative minimum tax;

• entities or other arrangements treated as a partnership or pass-through entity for U.S. federal income tax purposes or holders of interests therein;

• persons deemed to sell our Class A common stock under the constructive sale provisions of the Code;

• persons that acquired our Class A common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

• certain former citizens or long-term residents of the United States; and

• persons that hold our Class A common stock as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction, wash sale, or other integrated investment or risk reduction transaction.

PROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS (INCLUDING ANY POTENTIAL CHANGES THERETO) TO THEIR PARTICULAR SITUATION, AS

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WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL, NON-U.S. OR OTHER TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

Non-U.S. Holder Defined

For purposes of this discussion, a “non-U.S. holder” is a beneficial owner of our Class A common stock that is not for U.S. federal income tax purposes:

• an individual who is a citizen or resident of the United States;

• a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

• an estate the income of which is subject to U.S. federal income tax regardless of its source; or

• a trust (a) the administration of which is subject to the primary supervision of a U.S. court and which has one or more United States persons (within the meaning of Section 7701(a)(30) of the Code, a “United States person”) who have the authority to control all substantial decisions of the trust or (b) which has made a valid election under applicable U.S. Treasury regulations to be treated as a United States person.

If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our Class A common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner, upon the activities of the partnership and upon certain determinations made at the partner level. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) considering the purchase of our Class A common stock to consult their tax advisors regarding the U.S. federal income tax considerations of the purchase, ownership and disposition of our Class A common stock by such partnership.

Distributions

As described in the section entitled “Dividend Policy,” depending on factors deemed relevant by our board of directors, following completion of this offering, our board of directors may elect to declare dividends on our Class A common stock. If we do make distributions of cash or other property (other than certain stock distributions) on our Class A common stock, those distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will instead be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our Class A common stock (and will reduce such tax basis, until such basis equals zero) and thereafter as capital gain from the sale or exchange of such Class A common stock. See “—Gain on Disposition of Class A Common Stock.”

Subject to the withholding requirements under FATCA (as defined below) and with respect to effectively connected dividends, each of which is discussed below, any dividend made to a non-U.S. holder on our Class A common stock generally will be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividend unless an applicable income tax treaty provides for a lower rate. To receive the benefit of a reduced treaty rate, a non-U.S. holder must timely provide the applicable withholding agent with a properly executed IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate. A non-U.S. holder that does not timely furnish the required documentation, but that qualifies for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. holders are urged to consult their tax advisors regarding their entitlement to benefits under any applicable income tax treaty.

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Dividends paid to a non-U.S. holder that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons. Such effectively connected dividends will not be subject to U.S. federal withholding tax (including backup withholding discussed below) if the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent with a properly executed IRS Form W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a corporation for U.S. federal income tax purposes, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include effectively connected dividends.

Gain on Disposition of Class A Common Stock

Subject to the discussions below under “—Backup Withholding and Information Reporting” and “—Additional Withholding Requirements under FATCA,” a non-U.S. holder generally will not be subject to U.S. federal income or withholding tax on any gain realized upon the sale or other disposition of our Class A common stock unless:

• the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met;

• the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or

• our Class A common stock constitutes a United States real property interest by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes and as a result such gain is treated as effectively connected with a trade or business conducted by the non-U.S. holder in the United States.

A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.

A non-U.S. holder whose gain is described in the second bullet point above or, subject to the exception for the third bullet point above and described further in next paragraph, generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons unless an applicable income tax treaty provides otherwise. If the non-U.S. holder is a corporation for U.S. federal income tax purposes whose gain is described in the second bullet point above, then such gain would also be included in its effectively connected earnings and profits (as adjusted for certain items), which may be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty).

With regard to the third bullet point above, generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, as long as our Class A common stock is and continues to be “regularly traded on an established securities market” (within the meaning of the U.S. Treasury regulations), only a non-U.S. holder that actually or constructively owns, or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period for the Class A common stock, more than 5% of our Class A common stock, will be treated as disposing of a U.S. real property interest and will be taxable on gain realized on

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the disposition of our Class A common stock as a result of our status as a USRPHC. If our Class A common stock were not considered to be regularly traded on an established securities market, such non-U.S. holder (regardless of the percentage of stock owned) would be treated as disposing of a U.S. real property interest and would be subject to U.S. federal income tax on a taxable disposition of our Class A common stock (as described in the preceding paragraph), and a 15% withholding tax would apply to the gross proceeds from such disposition (and to any distributions treated as a non-taxable return of capital or capital gain from the sale or exchange of such Class A common stock as described above under “—Distributions”).

NON-U.S. HOLDERS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE FOREGOING RULES TO THEIR PURCHASE, OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON STOCK.

Backup Withholding and Information Reporting

Any dividends paid to a non-U.S. holder must be reported annually to the IRS and to the non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-U.S. holder resides or is established. Payments of dividends to a non-U.S. holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form).

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our Class A common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate, which is currently 24%) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our Class A common stock effected outside the United States by a non-U.S. office of a broker. However, unless such broker has documentary evidence in its records that the non-U.S. holder is not a United States person and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our Class A common stock effected outside the United States by such a broker if it has certain relationships within the United States.

Backup withholding is not an additional tax. Rather, the U.S. federal income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Additional Withholding Requirements under FATCA

Sections 1471 through 1474 of the Code, and the U.S. Treasury regulations and administrative guidance issued thereunder (“FATCA”), impose a 30% withholding tax on any dividends paid on our Class A common stock if paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (a) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are non-U.S. entities with U.S. owners), (b) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or timely provides the applicable withholding agent with a certification identifying the direct and indirect substantial United States owners of the entity (in either case, generally on an IRS Form W-8BEN-E), or (c) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS Form W-8BEN-E).

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Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a non-U.S. holder might be eligible for refunds or credits of such taxes. Non-U.S. holders are encouraged to consult their own tax advisors regarding the effects of FATCA on an investment in our Class A common stock.

Although FATCA withholding could apply to gross proceeds on the disposition of our Class A common stock, the U.S. Treasury released proposed U.S. Treasury regulations (the “Proposed Regulations”) the preamble to which specifies that taxpayers may rely on them pending finalization. The Proposed Regulations eliminate FATCA withholding on the gross proceeds from a sale or other disposition of our Class A common stock. There can be no assurance that the Proposed Regulations will be finalized in their present form.

INVESTORS CONSIDERING THE PURCHASE OF OUR CLASS A COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS (INCLUDING ANY POTENTIAL CHANGES THERETO) TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF U.S. FEDERAL ESTATE AND GIFT TAX LAWS AND ANY STATE, LOCAL OR NON-U.S. TAX LAWS AND TAX TREATIES.

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UNDERWRITING (CONFLICTS OF INTEREST)

Citigroup, Raymond James and RBC are acting as joint book-running managers of the offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of shares set forth opposite the underwriter’s name.

Underwriter	Number of Shares
Citigroup Global Markets Inc.		4,637,500
Raymond James & Associates, Inc.		2,650,000
RBC Capital Markets, LLC		2,650,000
BofA Securities, Inc.		596,250
Capital One Securities, Inc.		596,250
Truist Securities, Inc.		596,250
KeyBanc Capital Markets Inc.		430,625
Stephens Inc.		430,625
Comerica Securities, Inc.		132,500
Fifth Third Securities, Inc.		132,500
First Citizens Capital Securities, LLC		132,500
BTIG, LLC		132,500
BOK Financial Securities, Inc.		66,250
Zions Direct, Inc.		66,250
Total		13,250,000

The underwriting agreement provides that the obligations of the underwriters to purchase the shares included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the shares (other than those covered by the underwriters’ option to purchase additional shares described below) if they purchase any of the shares.

Shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $0.72 per share. If all the shares are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representatives have advised us that the underwriters do not intend to make sales to discretionary accounts.

If the underwriters sell more shares than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 1,987,500 additional shares at the public offering price less the underwriting discount. To the extent the option is exercised, each underwriter must purchase a number of additional shares approximately proportionate to that underwriter’s initial purchase commitment. Any shares issued or sold under the option will be issued and sold on the same terms and conditions as the other shares that are the subject of this offering.

We, our officers and directors and certain of our stockholders have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citigroup, Raymond James and RBC, dispose of or hedge any shares or any securities convertible into or exchangeable for our common stock. Citigroup, Raymond James and RBC in their sole discretion may release any of the securities subject to these lock-up agreements at any time, which, in the case of officers and directors, shall be with notice.

Prior to this offering, there has been no public market for our shares. Consequently, the initial public offering price for the shares was determined by negotiations between us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current

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financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the shares will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our shares will develop and continue after this offering.

We have been approved to list our Class A common stock on the New York Stock Exchange under the symbol “INR.”

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares.

	No Exercise		Full Exercise
Per share	$	1.20	$	1.20
Total	$	15,900,000	$	18,285,000

We estimate that our portion of the total expenses of this offering will be $10.5 million. We have also agreed to reimburse the underwriters for certain of their expenses in an amount up to $50,000.

In connection with the offering, the underwriters may purchase and sell shares in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the underwriters’ option to purchase additional shares and stabilizing purchases.

• Short sales involve secondary market sales by the underwriters of a greater number of shares than they are required to purchase in the offering.

• “Covered” short sales are sales of shares in an amount up to the number of shares represented by the underwriters’ option to purchase additional shares.

• “Naked” short sales are sales of shares in an amount in excess of the number of shares represented by the underwriters’ option to purchase additional shares.

• Covering transactions involve purchases of shares either pursuant to the underwriters’ option to purchase additional shares or in the open market in order to cover short positions.

• To close a naked short position, the underwriters must purchase shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

• To close a covered short position, the underwriters must purchase shares in the open market or must exercise the option to purchase additional shares. In determining the source of shares to close the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the underwriters’ option to purchase additional shares.

• Stabilizing transactions involve bids to purchase shares so long as the stabilizing bids do not exceed a specified maximum.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the shares. They may also cause the price of the shares to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the NYSE, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

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Conflicts of Interest

Affiliates of Citigroup, RBC, BofA, BOK, Capital One, Truist, Comerica, First Citizens, KeyBanc and Zions Direct, Inc. are lenders under our Credit Facility. As described in “Use of Proceeds,” net proceeds from this offering will be used to repay outstanding borrowings under our Credit Facility, and affiliates of Citigroup, RBC, BofA, BOK, Capital One, Truist, Comerica, First Citizens and KeyBanc will receive 5% or more of the net proceeds of this offering due to the repayment of borrowings under the Credit Facility. Therefore, such underwriters are deemed to have a “conflict of interest” under Rule 5121. Accordingly, this offering is being conducted in compliance with the requirements of Rule 5121, which requires, among other things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus. Raymond James has agreed to act as a qualified independent underwriter for this offering and to undertake the legal responsibilities and liabilities of an underwriter under the Securities Act, specifically including those inherent in Section 11 thereof. Raymond James will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify Raymond James against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act. Citigroup, RBC, BofA, BOK, Capital One, Truist, Comerica, First Citizens and KeyBanc will not confirm any sales to any account over which it exercises discretionary authority without the specific written approval of the account holder. See “Use of Proceeds” for additional information.

Directed Share Program

At our request, the underwriters have reserved up to 5% of the shares offered by this prospectus for sale, at the initial public offering price, to certain individuals through a directed share program, including our directors, officers, employees and certain other individuals identified by us. The sales will be made at our direction by Raymond James and its affiliates. The number of shares of our Class A common stock available for sale to the general public in this offering will be reduced to the extent that such persons purchase such reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares of Class A common stock offered by this prospectus. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the shares reserved for the directed share program.

Shares purchased through the directed share program will not be subject to a lock-up restriction, except in the case of shares purchased by any of our directors, officers or employees, which shares will be subject to a 180-day lock-up restriction (as described above).

Other Relationships

The underwriters are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. The underwriters and their respective affiliates have in the past performed commercial banking, investment banking and advisory services for us from time to time for which they have received customary fees and reimbursement of expenses and may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. In addition, affiliates of some of the underwriters are lenders, and in some cases agents or managers for the lenders, under our Credit Facility. Certain of the underwriters or their affiliates that have a lending relationship with us routinely hedge their credit exposure to us consistent with their customary risk management policies. A typical such hedging strategy would include these

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underwriters or their affiliates hedging such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of shares described in this prospectus may not be made to the public in that relevant member state other than:

• to any legal entity which is a qualified investor as defined in the Prospectus Directive;

• to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150 natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by us for any such offer; or

• in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of shares shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe for the shares, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state) and includes any relevant implementing measure in the relevant member state. The expression 2010 PD Amending Directive means Directive 2010/73/EU.

The sellers of the shares have not authorized and do not authorize the making of any offer of shares through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the shares as contemplated in this prospectus. Accordingly, no purchaser of the shares, other than the underwriters, is authorized to make any further offer of the shares on behalf of the sellers or the underwriters.

Notice to Prospective Investors in the United Kingdom

This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive that are also (a) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (b) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (each such person being referred to as a “relevant person”). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.

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Notice to Prospective Investors in France

Neither this prospectus nor any other offering material relating to the shares described in this prospectus has been submitted to the clearance procedures of the Autorité des Marchés Financiers or of the competent authority of another member state of the European Economic Area and notified to the Autorité des Marchés Financiers. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the shares has been or will be:

• released, issued, distributed or caused to be released, issued or distributed to the public in France; or

• used in connection with any offer for subscription or sale of the shares to the public in France.

Such offers, sales and distributions will be made in France only:

• to qualified investors (investisseurs qualifiés) and/or to a restricted circle of investors (cercle restreint d’investisseurs), in each case investing for their own account, all as defined in, and in accordance with articles L.411-2, D.411-1, D.411-2, D.734-1, D.744-1, D.754-1 and D.764-1 of the French Code monétaire et financier;

• to investment services providers authorized to engage in portfolio management on behalf of third parties; or

• in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the French Code monétaire et financier and article 211-2 of the General Regulations (Règlement Général) of the Autorité des Marchés Financiers, does not constitute a public offer (appel public à l’épargne).

The shares may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monétaire et financier.

Notice to Prospective Investors in Hong Kong

The shares may not be offered or sold in Hong Kong by means of any document other than (a) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (b) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (c) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong) and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Notice to Prospective Investors in Japan

The shares offered in this prospectus have not been and will not be registered under the Financial Instruments and Exchange Law of Japan. The shares have not been offered or sold and will not be offered or sold, directly or indirectly, in Japan or to or for the account of any resident of Japan (including any corporation or other entity organized under the laws of Japan), except (a) pursuant to an exemption from the registration requirements of the Financial Instruments and Exchange Law and (b) in compliance with any other applicable requirements of Japanese law.

Notice to Prospective Investors in Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or

175

invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (a) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (b) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), and in accordance with the conditions specified in Section 275 of the SFA or (c) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to compliance with conditions set forth in the SFA.

Where the shares are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

• a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or

• a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual who is an accredited investor,

shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferred within six months after that corporation or that trust has acquired the shares pursuant to an offer made under Section 275 of the SFA except:

• to an institutional investor (for corporations, under Section 274 of the SFA) or to a relevant person defined in Section 275(2) of the SFA, or to any person pursuant to an offer that is made on terms that such shares, debentures and units of shares and debentures of that corporation or such rights and interest in that trust are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets, and further for corporations, in accordance with the conditions specified in Section 275 of the SFA;

• where no consideration is or will be given for the transfer; or

• where the transfer is by operation of law.

Notice to Prospective Investors in Canada

The Class A common stock may be sold only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 – Prospectus Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations. Any resale of the Class A common stock must be made in accordance with an exemption from, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory for particulars of these rights or consult with a legal advisor.

Pursuant to section 3A.3 of National Instrument 33-105 – Underwriting Conflicts (“NI 33-105”), the dealers are not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

176

LEGAL MATTERS

The validity of our Class A common stock offered by this prospectus will be passed upon for us by Kirkland & Ellis LLP, Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Austin, Texas.

177

EXPERTS

The consolidated financial statements of Infinity Natural Resources, LLC as of December 31, 2023 and 2022, and for each of the two years in the period ended December 31, 2023 included in this prospectus, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report. Such financial statements are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheet of Infinity Natural Resources, Inc. as of May 15, 2024, included in this prospectus, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report. Such balance sheet has been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements of Utica Resource Ventures, LLC, as of and for the years ended December 31, 2022 and 2021 included in this prospectus, have been audited by Huselton, Morgan and Maultsby P.C., an independent accounting firm, as stated in their report appearing herein and elsewhere in the registration statement. Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The statements of revenue and direct operating expenses of PEO Ohio, LLC - Ohio Appalachian Basin Working and Revenue Interests for the years ended December 31, 2022 and 2021, have been included herein in reliance upon the report of KPMG LLP, independent auditors, appearing elsewhere herein and upon the authority of said firm as experts in accounting and auditing. The audit report covering the December 31, 2022 and 2021 statements included an other information paragraph regarding the nature of procedures applied to the required supplemental information consisting of the unaudited supplemental oil and gas reserve information included in the financial statements.

Estimates of our oil and natural gas reserves, related future net cash flows and the present values thereof related to our properties as of December 31, 2023 and December 31, 2022 included elsewhere in this prospectus were based upon reserve reports prepared by independent petroleum engineers Wright & Company, Inc. We have included these estimates in reliance on the authority of such firm as experts in such matters.

178

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our Class A common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto and we refer potential investors to the registration statement and the exhibits and schedules filed therewith for further information. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of our registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Further information on the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.

As a result of the offering, we will become subject to full information requirements of the Exchange Act. We will fulfill our obligations with respect to such requirements by filing periodic reports and other information with the SEC. We intend to furnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm.

179

INDEX TO FINANCIAL STATEMENTS

Infinity Natural Resources, Inc.
Unaudited Pro Forma Condensed Consolidated Financial Statements
Unaudited Pro Forma Condensed Consolidated Balance Sheet as of September 30, 2024	F-4
Unaudited Pro Forma Condensed Consolidated Statement of Operations for the Nine Months Ended September 30, 2024	F-5
Unaudited Pro Forma Condensed Consolidated Statement of Operations for the Year Ended December 31, 2023	F-6
Notes to Unaudited Pro Forma Condensed  Consolidated Financial Statements	F-7
Audited Balance Sheet
Report of Independent Registered Public Accounting Firm (PCAOB ID No.  34)	F-20
Balance Sheet as of May 15, 2024	F-21
Notes to Balance Sheet (Audited)	F-22
Unaudited Balance Sheets
Balance Sheets as of September 30, 2024 and May 15, 2024	F-23
Notes to Balance Sheets (Unaudited)	F-24
Infinity Natural Resources, LLC (Predecessor)
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm (PCAOB ID No.  34)	F-25
Consolidated Balance Sheets as of December  31, 2023 and 2022	F-26
Consolidated Statements of Operations for the Years Ended December  31, 2023 and 2022	F-27
Consolidated Statements of Members’ Equity for the Years Ended December 31, 2023 and 2022	F-28
Consolidated Statements of Cash Flows for the Years Ended December  31, 2023 and 2022	F-29
Notes to Consolidated Financial Statements	F-30
Condensed Consolidated Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets (Unaudited) as of September  30, 2024 and December 31, 2023	F-54
Condensed Consolidated Statements of Operations (Unaudited) for the Nine Months Ended September 30, 2024 and 2023	F-55
Condensed Consolidated Statements of Members’ Equity (Unaudited) for the Nine Months Ended September 30, 2024 and 2023	F-56
Condensed Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 30, 2024 and 2023	F-57
Notes to Condensed Consolidated Financial  Statements (Unaudited)	F-58
Utica Resource Ventures, LLC
Audited Consolidated Financial Statements	F-73
Unaudited Consolidated Financial Statements	F-79
PEO Ohio, LLC
Audited Statements of Revenues and Direct  Operating Expenses	F-107
Unaudited Statements of Revenues and  Direct Operating Expenses	F-113

F-1

UNAUDITED PRO FORMA CONSOLIDATED COMBINED FINANCIAL STATEMENTS

Infinity Natural Resources, Inc. (“Infinity Natural Resources” or the “Company”), the issuer in this offering, is a Delaware corporation formed to own an interest in Infinity Natural Resources, LLC (“INR Holdings”). Following this offering and the related transactions described herein, Infinity Natural Resources will be a holding company whose sole material asset will consist of membership interests in INR Holdings, which will continue to own all of our operating subsidiaries. After the consummation of the transactions contemplated by this prospectus, Infinity Natural Resources will be the managing member of INR Holdings and will control and be responsible for all operational, management, and administrative decisions relating to INR Holdings’ business and will report non-controlling interests in its consolidated financial statements related to the INR Units that the Existing Owners will own in INR Holdings.

The unaudited pro forma condensed consolidated financial statements and the corresponding notes thereto (the “pro forma financial statements”) of Infinity Natural Resources reflect the historical results of our predecessor, INR Holdings, on a pro forma basis after giving effect to the following transactions, which are described in further detail below, as if they had occurred on the dates indicated herein with respect to each transaction:

• the Acquisition as defined below, including the issuance of the Class B interests and borrowings under INR Holdings’ revolving credit facility;

• the corporate reorganization transactions as described under “Corporate Reorganization” included elsewhere in this prospectus; and

• the sale by Infinity Natural Resources of shares of its Class A common stock pursuant to this offering and the application of the net proceeds as described under “Use of Proceeds” included elsewhere in this prospectus after deducting estimated underwriting discounts and commissions and other offering related expenses payable by Infinity Natural Resources in connection with the offering (for purposes of the pro forma financial statements, the “Offering Transactions,” together with the Corporate Reorganization, the ”IPO Transactions,” and collectively with the Acquisition, the “Transactions”).

On August 7, 2023, Wolf Run Operating, LLC (“Wolf Run”), a wholly-owned subsidiary of INR Holdings, entered into a definitive purchase and sale agreement to acquire working interests in certain oil and gas assets from Utica Resource Ventures, LLC and Utica Resource Operating, LLC (collectively for purposes of the pro forma financial statements, “URV”) and PEO Ohio, LLC (“PEO Ohio” and together with URV for purposes of the pro forma financial statements, the “Sellers”) (the “Acquisition”).

The Acquisition closed on October 4, 2023, for $279.0 million (including transaction costs that were capitalized as part of the asset acquisition) and was financed through a combination of $222.3 million that was raised from the issuance by INR Holdings of new Class B interests as well as borrowings of $56.7 million under its amended and restated credit agreement.

As part of the corporate reorganization transactions described under “Corporate Reorganization” included elsewhere in this prospectus (a) the Existing Owners (as defined elsewhere in this prospectus) will exchange their LLC Interests for newly issued INR Units and subscribe for newly issued Class B common stock of Infinity Natural Resources with no economic rights or value and (b) Infinity Natural Resources will contribute the net proceeds of this offering to INR Holdings in exchange for newly issued INR Units and a managing membership interest in INR Holdings.

The pro forma financial statements have been prepared in accordance with Article 11 of Regulation S-X as amended by the final rule, Release No. 33-10786, “Amendments to Financial Disclosures about Acquired and Disposed Businesses,” using the assumptions set forth in the notes to the pro forma financial statements.

The unaudited pro forma condensed consolidated balance sheet (the “pro forma balance sheet”) as of September 30, 2024, is based on the historical unaudited consolidated balance sheet of INR Holdings as of September 30, 2024, adjusted to give effect to the IPO Transactions as if they had occurred on September 30, 2024.

F-2

The unaudited pro forma condensed consolidated statement of operations (the “pro forma statement of operations”) for the nine months ended September 30, 2024, is based on the historical unaudited consolidated statement of operations of INR Holdings for the nine months ended September 30, 2024, adjusted to give effect to the IPO Transactions as if they had occurred on January 1, 2023. The historical unaudited consolidated financial statements of INR Holdings as of and for the nine months ended September 30, 2024, are included elsewhere in this prospectus. As the Acquisition closed on October 4, 2023, the historical unaudited consolidated financial statements of INR Holdings as of and for the nine months ended September 30, 2024, include the assets acquired, such that transaction accounting adjustments related to the Acquisition are not presented herein for purposes of the pro forma balance sheet as of September 30, 2024, and the pro forma statement of operations for the nine months ended September 30, 2024.

The pro forma statement of operations for the year ended December 31, 2023, is based on the historical audited consolidated statement of operations of INR Holdings for the year ended December 31, 2023, the historical unaudited consolidated statement of operations of URV for the nine months ended September 30, 2023, and the historical unaudited statement of revenues and direct operating expenses of PEO Ohio for the nine months ended September 30, 2023, adjusted to give pro forma effect to the Transactions as if they had been consummated on January 1, 2023. The historical audited consolidated financial statements of INR Holdings as of and for the year ended December 31, 2023, the historical unaudited consolidated financial statements of URV for the nine months ended September 30, 2023, and the historical unaudited statement of revenues and direct operating expenses of PEO Ohio for the nine months ended September 30, 2023, are included elsewhere in this prospectus.

The pro forma financial statements are presented for informational purposes to reflect the Transactions and do not purport to represent what Infinity Natural Resources’ financial position or results of operations would have been had the Transactions occurred on the dates noted above, nor does it project the financial position or results of operations of Infinity Natural Resources following such Transactions. The transaction accounting adjustments are based on available information and certain assumptions that management believes are factually supportable and are expected to have a continuing impact on Infinity Natural Resources’ results of operations, with the exception of certain non-recurring charges to be incurred in connection with the IPO Transactions, as further described below. In the opinion of management, all adjustments necessary to present fairly the pro forma financial statements have been made.

Infinity Natural Resources anticipates that certain non-recurring charges will be incurred in connection with the IPO Transactions. Any such charge could affect the future results of Infinity Natural Resources in the period in which such charges are incurred; however, these costs are not expected to be incurred in any period beyond 12 months from the effective date of the IPO Transactions. The pro forma balance sheet as of September 30, 2024, reflects the effects of offering costs expected to be incurred by Infinity Natural Resources in conjunction with the IPO Transactions, $7.7 million of which is included in the historical unaudited consolidated balance sheet of INR Holdings as of September 30, 2024, within Prepaid expenses and other current assets, such that $2.8 million is included as a transaction accounting adjustment within the pro forma balance sheet as of September 30, 2024. This amount is offset by a transaction accounting adjustment of $10.5 million to reclass the total deferred costs to Additional paid-in capital upon completion of the IPO Transactions.

As a result of the foregoing, the transaction accounting adjustments related to the IPO Transactions are preliminary and subject to change as additional information becomes available and additional analysis is performed. The transaction accounting adjustments related to the IPO Transactions have been made solely for the purpose of providing the pro forma financial statements presented herein. Any increases or decreases in the IPO price per share of the Company’s Class A common stock may result in adjustments to the pro forma financial statements. The final IPO price per share and the transaction accounting adjustments described herein may be materially different than the preliminary amounts reflected in the pro forma financial statements herein.

The pro forma financial statements should be read together with “Corporate Reorganization,” “Selected Historical and Unaudited Pro Forma Financial Information,” “Use of Proceeds,” “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the historical financial statements and related notes thereto of INR Holdings, URV and PEO Ohio included elsewhere in this prospectus.

F-3

INFINITY NATURAL RESOURCES INC.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

AS OF SEPTEMBER 30, 2024

	INR Holdings Historical			Transaction Accounting Adjustments – IPO Transactions				Infinity Natural Resources Pro Forma
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	1,565		$	246,277 (224,746	)	(a) (d)	$	23,096
Accounts receivable:
Oil and natural gas sales, net		21,559			—				21,559
Joint interest billing and other, net		28,203			—				28,203
Prepaid expenses and other current assets		9,767			(7,677	)	(e)		2,090
Commodity derivative assets, short term		8,329			—				8,329
Total current assets		69,423			13,854				83,277
Oil and natural gas properties, full cost method		841,066			—				841,066
Other property and equipment		38,694			—				38,694
Less: Accumulated depreciation, depletion, and amortization		(135,887	)		—				(135,887	)
Property and equipment, net		743,873			—				743,873
Operating lease right-of-use assets, net		944			—				944
Other assets		8,971			—				8,971
Commodity derivative assets, long-term		2,164			—				2,164
Deferred tax assets, net		—			11,813		(f)		11,813
Total assets		825,375			25,667				851,042
Liabilities and Equity
Current liabilities:
Accounts payable		31,152			—				31,152
Royalties payable		24,721			—				24,721
Accrued liabilities		24,399			—				24,399
Notes payable		114			—				114
Operating lease liabilities		206			—				206
Commodity derivative liabilities, short-term		2,536			—				2,536
Total current liabilities		83,128			—				83,128
Line-of-credit		224,746			(224,746	)	(d)		—
Notes payable, long-term		70			—				70
Operating lease liabilities, net of current portion		738			—				738
Asset retirement obligations		1,088			—				1,088
Commodity derivative liabilities, long-term		1,846			—				1,846
Tax receivable agreement liability		—			—				—
Total liabilities		311,616			(224,746	)			86,870
Members’ equity / stockholders’ equity:
Members’ equity		513,759			(513,759	)	(b)		—
Class A common stock		—			133		(b)		133
Class B common stock		—			456		(b)		456
Additional paid-in capital		—			171,350		(b)		171,350
Retained earnings		—			—				—
Total members’ equity / stockholders’ equity		513,759			(341,820	)			171,939
Non-controlling interests		—			592,233		(b)(l)		592,233
Total equity		513,759			250,413				764,172
Total liabilities and equity	$	825,375		$	25,667			$	851,042

See accompanying “Notes to the Unaudited Pro Forma Condensed Consolidated Financial Statements”

F-4

INFINITY NATURAL RESOURCES INC.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2024

	INR Holdings Historical			Transaction Accounting Adjustments – IPO Transactions			Infinity Natural Resources Pro Forma
	(in thousands, except share and per share amounts)
Revenues:
Oil, natural gas, and natural gas liquids sales	$	188,877		$	—		$	188,877
Midstream activities		1,032			—			1,032
Total revenues		189,909			—			189,909
Operating expenses:
Gathering, processing, and transportation		37,852			—			37,852
Lease operating		20,715			—			20,715
Production and ad valorem taxes		1,264			—			1,264
Depreciation, depletion, and amortization		56,344			—			56,344
General and administrative		8,268			—			8,268
Total operating expenses		124,443			—			124,443
Operating income		65,466			—			65,466
Other income (expense):
Interest expense		(16,263	)		16,041	(d)		(222	)
Loss on derivative instruments		6,397			—			6,397
Other loss		(797	)		—			(797	)
Income before income taxes		54,803			16,041			70,844
Income tax provision		—			3,558	(f)		3,558
Net income	$	54,803		$	12,483		$	67,286
Net income attributable to non-controlling interests								52,147		(l)
Net income attributable to Infinity Natural Resources							$	15,139
Net income per share of Class A common stock—basic and diluted							$	1.14		(g)
Weighted-average shares of Class A common stock outstanding—basic								13,250,000		(g)
Incremental shares of Class A common stock attributable to dilutive instruments								45,801,389
Weighted average shares of Class A common stock outstanding—diluted								59,051,389

See accompanying “Notes to the Unaudited Pro Forma Condensed Consolidated Financial Statements”

F-5

INFINITY NATURAL RESOURCES INC.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2023

	INR Holdings Historical			URV Historical			PEO Ohio Historical		Transaction Accounting Adjustments									Infinity Natural Resources Pro Forma
									Acquisition (Note 2)				IPO Transactions
	(in thousands, except share and per share amounts)
Revenues:
Oil, natural gas, and natural gas liquids sales	$	159,532		$	—		$	—	$	100,823		(h)	$	—				$	260,355
Crude oil		—			65,162			16,327		(81,489	)	(h)		—					—
Natural gas		—			7,690			1,897		(9,587	)	(h)		—					—
Natural gas liquids		—			7,794			1,953		(9,747	)	(h)		—					—
Midstream activities		2,198			—			—		—				—					2,198
Gain on derivative instruments		—			683			—		(683	)	(k)		—					—
Total revenues		161,730			81,329			20,177		(683	)			—					262,553
Operating expenses:
Gathering, processing, and transportation		31,097			9,226			—		2,305		(j)		—					42,628
Lease operating		18,371			5,232			—		1,336		(j)		—					24,939
Production and ad valorem taxes		886			795			—		199		(j)		—					1,880
Depreciation, depletion, and amortization		53,796			35,193			—		910		(h)(i)		—					89,899
General and administrative		4,885			3,164			—		—				129,390		(c	)		137,439
Accretion of asset retirement obligations		—			22			—		(22	)	(h)		—					—
Direct operating expenses		—			—			3,840		(3,840	)	(j)		—					—
Total operating expenses		109,035			53,632			3,840		888				129,390					296,785
Operating income (loss)		52,695			27,697			16,337		(1,571	)			(129,390	)				(34,232	)
Other income (expense):
Interest expense		(11,910	)		(2,082	)		—		2,082		(d)		11,598		(d)			(312	)
Gain on derivative instruments		45,322			—			—		1,155		(k)		—					46,477
Other income		565			200			—		244		(k)		—					1,009
Operating overhead income		—			444			—		(444	)	(h)		—					—
Income (loss) before income taxes		86,672			26,259			16,337		1,466				(117,792	)				12,942
Income provision		—			—			—		6,567		(f)		(5,917	)	(f)			650
Net income (loss)	$	86,672		$	26,259		$	16,337	$	(5,101	)		$	(111,875	)			$	12,292
Net income attributable to non-controlling interests																			9,526		(l	)
Net income attributable to Infinity Natural Resources																		$	2,766
Net income per share of Class A common stock—basic and diluted																		$	0.21		(g	)
Weighted-average shares of Class A common stock outstanding—basic																			13,250,000		(g	)
Incremental shares of Class A common stock attributable to dilutive instruments																			45,720,139
Weighted average shares of Class A common stock outstanding—diluted																			58,970,139

See accompanying “Notes to the Unaudited Pro Forma Condensed Consolidated Financial Statements”

F-6

NOTES TO THE UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—BASIS OF PRESENTATION AND DESCRIPTION OF TRANSACTIONS

The Transactions, and the related transaction accounting adjustments, are described in the notes to the pro forma financial statements herein. In the opinion of management, all material adjustments have been made that are necessary to present fairly the pro forma financial statements in accordance with Article 11 of Regulation S-X as amended by the final rule, Release No. 33-10786.

Infinity Natural Resources is a newly organized holding company with nominal assets and no liabilities, contingencies or commitments, and will not have conducted any operations prior to the consummation of the IPO Transaction. As described under “Corporate Reorganization” included elsewhere in this prospectus, in connection with the IPO Transactions, (a) the Existing Owners’ LLC Interests in INR Holdings will be recapitalized into a single class of units, the newly issued INR Units, with the INR Units to be allocated to the Existing Owners in accordance with the terms of the INR Holdings LLC Agreement and calculated using an implied valuation for INR Holdings based on the initial public offering price of the Class A common stock of Infinity Natural Resources, and (b) Infinity Natural Resources will contribute the net proceeds of this offering to INR Holdings in exchange for the newly issued INR Units and a managing member interest in INR Holdings. After the consummation of the Transactions, Infinity Natural Resources will be the managing member of INR Holdings and will control and be responsible for all operational, management and administrative decisions relating to INR Holdings’ business and will consolidate the financial results of INR Holdings and will report non-controlling interests in its consolidated financial statements related to the INR Units that the Existing Owners will own in INR Holdings.

Pursuant to the terms of the INR Holdings LLC Agreement, the INR Units to be issued to the Existing Owners in connection with the corporate reorganization will be calculated using an implied equity value of INR Holdings immediately prior to this offering, and the current relative levels of ownership in INR Holdings with the allocation of such units among the Existing Owners to be determined based on the initial public offering price. After giving effect to the IPO Transactions, (a) Infinity Natural Resources will own 13,250,000 INR Units, or an approximate 22.5% interest in INR Holdings (or 15,237,500 INR Units, or 25.0%, if the underwriters’ option to purchase additional shares is fully exercised), and (b) the Existing Owners will own 45,638,889 INR Units, or an approximate 77.5% interest in INR Holdings (or 45,638,889 INR Units, or 75.0% if the underwriters’ option to purchase additional shares is fully exercised).

Based on its ownership in INR Holdings subsequent to the Transactions, Infinity Natural Resources assessed whether it will have a variable interest in INR Holdings and whether INR Holdings will be a variable interest entity (“VIE”) to determine whether it will be required to consolidate INR Holdings. In order to perform this assessment, Infinity Natural Resources determined that INR Holdings will be more akin to a partnership than a corporation for purposes of applying the consolidation guidance.

Subsequent to the Transactions, Infinity Natural Resources will have an approximate 22.5% interest in INR Holdings (or 25.0% if the underwriters’ option to purchase additional shares is fully exercised) through which it will absorb the risks created and distributed by the entity. As the managing member of INR Holdings based on the terms of the INR Holdings LLC Agreement, Infinity Natural Resources will have the sole power to direct the activities that most significantly impact the entity’s economic performance, with the remaining INR Unit Holders having no substantive kick-out or participating rights. As such, Infinity Natural Resources determined that INR Holdings will be a VIE.

Infinity Natural Resources then assessed whether it will be the primary beneficiary of INR Holdings. To make this determination, Infinity Natural Resources evaluated its economic interest in the entity to determine if such economic interest will give it both the power to direct the activities of INR Holdings that most significantly impact

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INR Holdings’ economic performance, as well as whether it will have the obligation to absorb losses or the right to receive benefits that could potentially be significant to INR Holdings. In making this determination, Infinity Natural Resources considered the total economics of INR Holdings and analyzed whether its share of the economics through its ownership of INR Units will be significant, using qualitative and quantitative factors, where applicable.

Based on its assessment of the impact of the Transactions described herein, Infinity Natural Resources will be the primary beneficiary of INR Holdings, and thus will include INR Holdings in its consolidated financial statements. Infinity Natural Resources is not required to provide financial support to INR Holdings pursuant to any arrangements, and the creditors of INR Holdings will have no recourse against Infinity Natural Resources, including under INR Holdings’ credit facility. Infinity Natural Resources’ other economic interests in the VIE would not absorb more than an insignificant amount of the entity’s losses or receive more than an insignificant amount of the entity’s benefits. The portion of the consolidated INR Holdings that is owned by the INR Unit Holders and any related activity will be reclassified as non-controlling interests in the consolidated balance sheets and income attributable to non-controlling interests in the consolidated statements of operations of Infinity Natural Resources.

Accordingly, INR Holdings is considered our accounting predecessor and its consolidated financial statements will be the historical financial statements of Infinity Natural Resources following this offering; thus, the pro forma financial statements are presented herein to reflect the consolidation by Infinity Natural Resources of the financial results of INR Holdings, with non-controlling interests reflected in the pro forma financial statements related to the INR Units that the Existing Owners will hold in INR Holdings subsequent to this offering.

Additionally, on October 4, 2023, INR Holdings closed its acquisition of working interests in certain oil and gas assets from URV and PEO Ohio for $279.0 million (including transaction costs that were capitalized as part of the asset acquisition, as discussed further in Note 3 herein) which was financed through a combination of $222.3 million that was raised from the issuance by INR Holdings of new Class B interests as well as borrowings of $56.7 million under its amended and restated credit agreement. Certain of URV and PEO Ohio’s historical amounts have been reclassified to conform to INR Holdings’ financial statement presentation, which are reflected as transaction accounting adjustments related to the Acquisition within the unaudited pro forma statement of operations for the year ended December 31, 2023.

The pro forma balance sheet as of September 30, 2024, is based on the historical unaudited consolidated balance sheet of INR Holdings as of September 30, 2024, adjusted to give effect to the IPO Transactions as if they had occurred on September 30, 2024. The pro forma statement of operations for the nine months ended September 30, 2024, is based on the historical unaudited consolidated statement of operations of INR Holdings for the nine months ended September 30, 2024, adjusted to give effect to the IPO Transactions as if they had occurred on January 1, 2023. The historical unaudited consolidated financial statements of INR Holdings as of and for the nine months ended September 30, 2024, are included elsewhere in this prospectus. As the Acquisition closed on October 4, 2023, the historical unaudited consolidated financial statements of INR Holdings as of and for the nine months ended September 30, 2024, include the assets acquired, such that transaction accounting adjustments related to the Acquisition are not presented herein for purposes of the pro forma balance sheet as of September 30, 2024, and the pro forma statement of operations for the nine months ended September 30, 2024.

The unaudited pro forma statement of operations for the year ended December 31, 2023, is based on the historical audited consolidated statement of operations of INR Holdings for the year ended December 31, 2023, the historical unaudited consolidated statement of operations of URV for the nine months ended September 30, 2023, and the historical unaudited statement of revenues and direct operating expenses of PEO Ohio for the nine months ended September 30, 2023, adjusted to give pro forma effect to the Transactions as if they had been consummated on January 1, 2023. The historical audited consolidated financial statements of INR Holdings as of and for the year ended December 31, 2023, the historical unaudited consolidated financial statements of URV for the nine months ended September 30, 2023, and the historical unaudited statement of revenues and direct operating expenses of PEO Ohio for the nine months ended September 30, 2023, are included elsewhere in this prospectus.

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The pro forma financial statements assume no exercise by the underwriters of their option to purchase additional shares of Class A common stock. In addition, the pro forma financial statements do not reflect any cost savings, operating synergies, or revenue enhancements that Infinity Natural Resources may achieve as a result of the Transactions.

The pro forma financial statements should be read in conjunction with INR Holdings’, URV’s, and PEO Ohio’s historical financial statements and the notes thereto which have been included elsewhere in this prospectus. The pro forma financial statements do not purport to be indicative of what Infinity Natural Resources’ financial position or results of operations would have been had the Transactions taken place on the dates indicated, nor are they indicative of Infinity Natural Resources’ future financial position or results of operations following the Transactions. In addition, future results may vary significantly from those reflected in such statements due to factors discussed in “Risk Factors” included elsewhere in this prospectus.

NOTE 2—RESULTS OF OPERATIONS OF ASSETS ACQUIRED NOT INCLUDED IN HISTORICAL AMOUNTS

As the historical results of operations of URV and PEO Ohio included in the pro forma statement of operations for the year ended December 31, 2023, only include the results of operations for the nine months ended September 30, 2023, there are four days of operations between October 1, 2023, and the closing date of October 4, 2023, that are not included in the historical results of operations of URV or PEO Ohio. Management assessed the amounts for the four-day period and determined that the amounts were immaterial for purposes of the pro forma statement of operations for the year ended December 31, 2023. As such, there are no transaction accounting adjustments for these amounts, such that the results of operations of URV and PEO Ohio for the nine months ended September 30, 2023, have been added to the historical results of operations of INR Holdings for the year ended December 31, 2023 to give pro forma effect to the Acquisition, subject to the additional transaction accounting adjustments discussed in the notes to the pro forma financial statements herein.

NOTE 3—PURCHASE CONSIDERATION AND PURCHASE PRICE ALLOCATION

INR Holdings closed the Acquisition on October 4, 2023, and performed a valuation analysis of the fair value of the oil and natural gas properties acquired. In accordance with ASC 805, Business Combinations (“ASC 805”), INR Holdings performed an initial screen test as of the transaction close date in order to determine whether the acquired set should be accounted for as an asset acquisition or business combination. Given that URV had a contractual dragalong right with respect to the interests of PEO Ohio in the oil and natural gas assets acquired, INR Holdings performed the screen test on an aggregate basis for all assets acquired in the Acquisition from URV and PEO Ohio. Based on INR Holdings’ assessment of the fair values of the gross assets acquired, it determined that the Acquisition did not meet the definition of a business combination in accordance with ASC 805, and as such, it accounted for the Acquisition as an asset acquisition.

Using the purchase consideration for the Acquisition, consisting of the proceeds from the issuance of the Class B interests, borrowings under INR Holdings’ amended and restated credit agreement, and including capitalized transaction costs, INR Holdings determined the allocation to the assets acquired and liabilities assumed based on their relative fair values. The transaction accounting adjustments discussed herein are based on the amounts reflected as purchase consideration and the allocation of the purchase price to the net assets acquired.

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The following tables summarize the total purchase consideration and the allocation of the purchase price as of the closing date of the Acquisition:

	Purchase Consideration
(in thousands)
Cash proceeds from issuance of Class B interests	$	222,278
Borrowings under revolving credit facility		56,689
Total cash purchase consideration	$	278,967
	Purchase Price Allocation
(in thousands)
Oil and natural gas properties (including $1,402 of capitalized transaction costs)	$	280,658
Severance taxes and suspense revenues payable		(1,691	)
Net assets acquired	$	278,967

NOTE 4—TRANSACTION ACCOUNTING ADJUSTMENTS

The pro forma balance sheet as of September 30, 2024, and the pro forma statement of operations for the nine months ended September 30, 2024, have been adjusted to reflect the IPO Transactions, and the pro forma statement of operations for the year ended December 31, 2023, has been adjusted to reflect the Transactions as follows:

(a) The pro forma adjustment reflects the net effect on cash of the receipt of offering proceeds to us of $246.3 million, based on the sale of 13,250,000 shares of Class A common stock at the initial public offering of $20.00 after deducting the underwriting discounts and commissions, the contribution of such proceeds to INR Holdings in exchange for INR Units, estimated offering expenses payable by us and the application of the net proceeds as described under “Use of Proceeds,” included elsewhere in this prospectus.

Gross proceeds	$	265.0
Underwriting discounts and commissions		(15.9	)
Net proceeds before offering expenses (1)		249.1
Payment of other offering expenses(2)		(2.8	)
Net proceeds	$	246.3

(1) The net proceeds will be contributed to INR Holdings in exchange for 13,250,000 newly issued INR Units.

(2) The payment of approximately $2.8 million of estimated other offering expenses excludes $7.7 million of estimated other offering expenses that have been previously capitalized.

(b) As part of the Corporate Reorganization and upon closing of the offering, Infinity Natural Resources will contribute the net proceeds of the public offering to INR Holdings in exchange for newly issued INR Units. Additionally, the Existing Owners prior to the Offering Transactions will exchange their LLC Interests for INR Units and receive an equal number of newly issued Class B common stock of Infinity Natural Resources.

The pro forma adjustment reflects (1) the elimination of INR Holdings’ historical Member’s equity, (2) the issuance of 13,250,000 shares of our Class A common stock in this offering, (3) the issuance of 45,638,889 shares of Class B common stock to the Existing Owners (reflected in the line item titled “Elimination of INR Holdings’ historical Member’s equity due to the exchange of LLC interests for INR Units” in the table below), and (4) the impact on additional paid in capital.

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The following table is a reconciliation of the adjustments impacting additional paid-in-capital (in millions):

Elimination of INR Holdings’ historical Member’s equity due to the exchange of LLC interests for INR Units	$	513.3
Recognition of deferred tax asset		11.8
Offering expenses (excluding underwriting discounts and commissions)		(10.5	)
Underwriting discounts and commissions associated with this offering		(15.9	)
Adjustment for non-controlling interest		(592.2	)
Issuance of Class A common stock (less par value)		264.9
Net additional paid-in capital pro forma adjustment	$	171.4

(c) Reflects an aggregate of 162,500 restricted stock units (“RSUs”) granted under the Infinity Natural Resources Omnibus Incentive Plan in connection with the offering. The RSUs cliff vest on the one-year anniversary of the date of grant, subject to such employee’s continued service through such vesting date. As a result, it is expected that a non-recurring compensation expense of $3.3 million for the RSUs will be recognized in the quarter in which this offering occurs.

Following the IPO Transactions, it is anticipated that all outstanding (i) unvested Incentive Units will automatically vest and (ii) vested Incentive Units, including those that will have been unvested immediately prior to the closing as contemplated by the foregoing clause (i), will be recapitalized into INR Units. Executives and other employees of INR Holdings will receive approximately 6,489,362 INR Units as a result of the recapitalization of their Incentive Units. As a result, it is expected that a non-recurring compensation expense of $126.1 million for the accelerated vesting of the Incentive Units will be recognized in the quarter in which this offering occurs.

(d) Following the IPO Transactions, to the extent of net proceeds available, Infinity Natural Resources intends to direct the net cash proceeds from this offering to repay $224.7 million of outstanding borrowings under the credit facility entered into on September 25, 2024, which is reflected as a transaction accounting adjustment related to the IPO Transactions for purposes of the pro forma balance sheet as of September 30, 2024. For purposes of the pro forma financial statements, the payoff and extinguishment of the prior credit facility of INR Holdings and the contemporaneous execution of the new credit facility entered into on September 25, 2024, have not been reflected herein.

The pro forma statements of operations for the nine months ended September 30, 2024, and for the year ended December 31, 2023, reflect the net impact to Interest, net which has been estimated for purposes herein based on the terms of the credit agreement entered into by INR Holdings on September 25, 2024. Accordingly, for the nine months ended September 30, 2024, the adjustments consist of: (1) the elimination of INR Holdings’ historical interest expense of $16.3 million and (2) estimated pro forma interest expense of $0.9 million, which includes an immaterial amount of unused commitment fees, and (3) estimated pro forma interest income of $0.7 million assuming Infinity Natural Resources invested the excess pro forma cash proceeds pursuant to this offering. For the year ended December 31, 2023, the adjustments consist of: (1) the elimination of INR Holdings’ historical interest expense of $11.9 million, (2) the elimination of URV’s historical interest expense of $2.1 million, as INR Holdings did not assume any debt in the Acquisition, (3) estimated pro forma interest expense of $1.2 million, which includes an immaterial amount of unused commitment fees, and (4) estimated pro forma interest income of $0.9 million assuming Infinity Natural Resources invested the excess pro forma cash proceeds pursuant to this offering. The pro forma interest expense amounts estimated for the pro forma statements of operations were based on reduced borrowings outstanding of $0.0 million subsequent to the IPO Transactions as reflected on the pro forma balance sheet as of September 30, 2024.

(e) Reflects approximately $7.7 million of non-recurring costs related to the IPO Transactions, which primarily represent legal, accounting and other direct costs and are included in Prepaid expenses and other current assets within the historical unaudited consolidated balance sheet of INR Holdings as of September 30, 2024. The $7.7 million will be reclassed from Prepaid expenses and other current assets upon the effective date of the IPO Transactions with a corresponding reduction to Additional paid-in capital.

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(f) Subsequent to the IPO Transactions, Infinity Natural Resources will have no material assets other than its interest in INR Holdings, which holds, directly or indirectly, all of the operating assets of Infinity Natural Resources. INR Holdings generally will not be subject to U.S. federal income tax, but may be subject to certain U.S. state and local taxes. Infinity Natural Resources is a domestic corporation that will be subject to U.S. corporate income tax on its earnings, including its allocable share of the income of INR Holdings.

The unaudited pro forma consolidated statement of operations includes an adjustment to our income tax expense to reflect an effective income tax rate of 5.0%, which includes a provision for United States federal income taxes and assumes the highest statutory rates apportioned to each state and local jurisdiction. The effective income tax rate of 5.0% was calculated by applying the blended statutory rate of 22.3% to the portion of pre-tax income attributable to Infinity Natural Resources (22.5%) as the pre-tax income attributable to the non-controlling interest holders (77.5%) is not subject to federal and state income taxes.

Accordingly, for purposes of the pro forma statement of operations for the year ended December 31, 2023, Infinity Natural Resources’ estimated blended statutory U.S. federal and state tax rate was calculated as 5.0%, which has been used herein to determine the tax provision of $6.6 million related to the Acquisition based on pro forma income before income taxes of $130.7 million for the year ended December 31, 2023. As the Acquisition closed on October 4, 2023, there is no impact to pro forma net income related to the Acquisition for the nine months ended September 30, 2024.

Additionally, with respect to the IPO Transactions, for purposes of the pro forma statement of operations for the nine months ended September 30, 2024, Infinity Natural Resources’ estimated blended statutory U.S. federal and state tax rate was calculated as 5.0%, which has been used herein to determine the tax provision of $3.6 million based on pro forma income before income taxes of $70.8 million for the nine months ended September 30, 2024. For purposes of the pro forma statement of operations for the year ended December 31, 2023, Infinity Natural Resources’ estimated blended statutory U.S. federal and state tax rate was calculated as 5.0%, which has been used herein to determine the tax provision of $(5.9) million based on pro forma income (loss) before income taxes of $(117.8) million for the year ended December 31, 2023.

Upon completion of the IPO Transactions, Infinity Natural Resources will recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the historical cost basis and tax basis of its assets and liabilities in accordance with ASC 740, Income Taxes (“ASC 740”). With respect to the Acquisition, given that it was accounted for as an asset acquisition, there were no tax impacts to reflect within the pro forma balance sheet as of September 30, 2024; however, amounts have been estimated for the deferred tax assets and liabilities to be recorded as it relates to the IPO Transactions. The impacts of changes in any of these estimates after the date of purchase will be included in net income. Similarly, the effect of subsequent changes in the enacted tax rates will be included in net income.

On the pro forma balance sheet, the pro forma adjustment reflects the recognition of deferred taxes in connection with the organizational transactions of Infinity Natural Resources, assuming a pro forma blended statutory tax rate of 22.3% which includes a provision for U.S. federal, state and local taxes. A pro forma deferred tax asset adjustment of $11.8 million related to temporary differences in the book basis as compared to the tax basis of our investment in INR Holdings.

(g) Reflects the basic and diluted pro forma net income per share for the nine months ended September 30, 2024, and for the year ended December 31, 2023, assuming the shares of Class A common stock in this offering were issued, and other Transactions as described herein were consummated, on January 1, 2023. Pro forma diluted earnings per share is computed by adjusting pro forma net income attributable to Infinity Natural Resources and the weighted average shares of Class A common stock outstanding to give effect to potentially dilutive securities that qualify as participating securities.

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	Infinity Natural Resources Pro Forma(1)(2)
	For the Nine Months Ended September 30, 2024		For the Year Ended December 31, 2023
(in thousands, except share and per share amounts)
Numerator
Net income	$	67,286	$	12,292
Net income attributable to non-controlling interests		52,147		9,526
Net income attributable to Infinity Natural Resources	$	15,139	$	2,766
Denominator
Weighted average shares of Class A common stock outstanding—basic		13,250,000		13,250,000
Incremental shares of Class A common stock attributable to dilutive instruments(1)		45,801,389		45,720,139
Weighted average shares of Class A common stock outstanding—diluted		59,051,389		58,970,139
Pro forma net income per share of Class A common stock—basic and diluted	$	1.14	$	0.21

(1) The incremental shares of Class A common stock attributable to dilutive instruments includes 45,801,389 shares of Class B common stock assumed to be exchanged by non-controlling interest holders and RSU awards issued and outstanding as of January 1, 2023.

(2) Shares of our Class B common stock do not share in the earnings or losses of the Company and are therefore not participating securities. Shares of our Class B common stock are, however, considered potentially dilutive shares of Class A common stock. In the calculation of pro forma diluted earnings per share, the Company applied the if-converted method to the Class B common stock. Potential common shares were calculated by assuming the Class B common stock were exchanged for Class A common stock as well as the RSU awards issued and outstanding as of January 1, 2023. A numerator adjustment was also calculated to re-allocate net income attributable to non-controlling interests to Infinity Natural Resources, assuming there is no non-controlling interest subsequent to the conversion of the Class B common stock for the Class A common stock. For the nine months ended September 30, 2024, and for the year ended December 31, 2023, the combined effect of the numerator adjustments with respect to non-controlling interests and the denominator adjustments with respect to the number of shares of common stock outstanding were antidilutive to pro forma net income per share. As such, separate presentation of basic and diluted pro forma net income per share of Class B common stock under the two-class method has not been presented.

(h) Reflects the reclassification and elimination of URV historical and PEO historical amounts for the nine months ended September 30, 2023, to conform to INR Holdings’ financial statement presentation and accounting policies, including reclasses for: (i) oil, natural gas, and natural gas liquids revenues, (ii) accretion of asset retirement obligations of URV, and (iii) the elimination of operating overhead income of PEO that would not have been recognized by INR Holdings under the full cost method of accounting.

(i) Reflects the pro forma adjustment to depreciation, depletion, and amortization expense, which is comprised of: (1) the elimination of the URV historical depreciation, depletion, and amortization expense of $35.2 million, and (2) the incremental depreciation, depletion, and amortization expense of $36.1 million, calculated based on the units-of-production method under the full cost method of accounting assuming the Acquisition was consummated on January 1, 2023, based on a fair value of $279.0 million that was recorded to proved oil and gas properties.

(j) Reflects the reclass of direct operating expenses of PEO Ohio to align with INR Holdings’ presentation. Given that the assets acquired from PEO Ohio were not historically accounted for as a separate segment, subsidiary, or division of PEO Ohio, certain indirect expenses not directly associated with the acquired assets were not included in the historical financial statements of PEO Ohio used as the basis for the pro forma financial statements herein. As such, the combined pro forma statement of

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operations for the year ended December 31, 2023, is not intended to be a complete presentation of the revenues and expenses of the assets acquired from PEO Ohio and is not indicative of the results of operations of the assets going forward due to the omission of various expenses, including general and administrative expenses, depreciation, depletion, and amortization expense, interest expense, and income tax expense.

(k) Reflects the addition of $0.5 million of unrealized gain on derivative instruments to Gain on derivative instruments that was previously included in URV’s other comprehensive income given its designation of derivative instruments as cash flow hedges. Additionally, we have reclassed $0.7 million of realized derivative gains as included in Total revenues to Gain on derivative instruments within Other income (expense) to align with our financial statement presentation and accounting policy. We have also eliminated $0.2 million of historical URV income on interest rate swaps given that we did not assume the outstanding debt of URV as part of the URV Acquisition.

(l) Subsequent to the Transactions, Infinity Natural Resources will be the primary beneficiary of INR Holdings, and thus will include INR Holdings in its consolidated financial statements. The portion of the consolidated INR Holdings that is owned by the INR Unit Holders and any related activity will be reclassified as non-controlling interests in the consolidated balance sheets and income attributable to non-controlling interests in the consolidated statements of operations of Infinity Natural Resources. Subsequent to the Transactions, Infinity Natural Resources will have an approximate 22.5% interest in INR Holdings through which it will absorb the risks created and distributed by the entity. Existing owners will own the remaining 77.5% of the economic interest in INR Holdings, which will be accounted for as a noncontrolling interest in the future consolidated financial results.

NOTE 5—SUPPLEMENTAL PRO FORMA OIL AND NATURAL GAS RESERVES INFORMATION

The following tables present the estimated pro forma combined net proved developed and undeveloped oil and natural gas reserves information as of December 31, 2023 and 2022, along with a summary of changes in quantities of net remaining proved reserves during the year ended December 31, 2023, assuming the Acquisition had been consummated on January 1, 2023. Amounts for the Acquisition reflect activity for the period from January 1, 2023 through September 30, 2023, given the Acquisition closing date of October 4, 2023 and the determination by management that activity for the period from October 1, 2023, through October 4, 2023, was immaterial.

The pro forma oil and natural gas reserves information is not necessarily indicative of the results that might have occurred had the Acquisition been completed on the dates herein, and is not intended to be a projection of future results. Future results may vary significantly from the results reflected because of various factors, including those discussed in the section entitled “Risk Factors” contained elsewhere in this prospectus.

The following reserves information sets forth the estimated pro forma summary of changes in quantities of net remaining proved reserves during the year ended December 31, 2023, as well as the estimated pro forma quantities of proved developed and proved undeveloped oil, natural gas, and NGL reserves of the Company as of December 31, 2023 and 2022. Given the Acquisition close date of October 4, 2023, the historical quantities of proved developed and proved undeveloped reserves for oil, natural gas, and NGLs for URV and PEO Ohio as of December 31, 2023, are included within the historical quantities of proved developed and proved undeveloped

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reserves for oil, natural gas, and NGLs for INR Holdings as of December 31, 2023. As such, these quantities are not presented separately for URV and PEO Ohio as of December 31, 2023.

	INR Holdings Historical			January 1, 2023 through September 30, 2023						Transaction Accounting Adjustments – Acquisition			Infinity Natural Resources Pro Forma Combined
				URV			PEO Ohio
Crude oil (MBbls)
Proved reserves:
December 31, 2022		5,913			9,234			2,145			—			17,292
Extensions		7,443			2,670			667			—			10,780
Revisions to previous estimates		252			4,034			1,062			—			5,348
Purchases of reserves in place		18,636			—			—			(18,636	)		—
Production		(1,205	)		(941	)		(235	)		—			(2,381	)
December 31, 2023		31,039			14,997			3,639			(18,636	)		31,039
Natural gas (MMcf)
Proved reserves:
December 31, 2022		358,338			58,824			12,889			—			430,051
Extensions		168,704			23,334			5,834			—			197,873
Revisions to previous estimates		(118,920	)		25,171			7,084			—			(86,665	)
Purchases of reserves in place		128,110			—			—			(128,110	)		—
Production		(27,506	)		(4,021	)		(1,005	)		—			(32,532	)
December 31, 2023		508,727			103,308			24,802			(128,110	)		508,727
Natural gas liquids (MBbls)
Proved reserves:
December 31, 2022		14,152			3,874			1,056			—			19,082
Extensions		9,015			1,009			252			—			10,276
Revisions to previous estimates		(4,501	)		1,877			442			—			(2,182	)
Purchases of reserves in place		8,207			—			—			(8,207	)		—
Production		(1,112	)		(242	)		(61	)		—			(1,415	)
December 31, 2023		25,761			6,518			1,689			(8,207	)		25,671
Total (MBoe)
Total proved reserves:
December 31, 2022		79,788			22,912			5,349			—			108,049
Extensions		44,575			7,568			1,892			—			54,036
Revisions to previous estimates		(24,069	)		10,106			2,684			—			(11,279	)
Purchases of reserves in place		48,195			—			—			(48,195	)		—
Production		(6,901	)		(1,853	)		(464	)		—			(9,218	)
December 31, 2023		141,588			38,733			9,461			(48,195	)		141,588

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As of December 31, 2022	INR Holdings Historical		URV Historical		PEO Ohio Historical		Infinity Natural Resources Pro Forma Combined
Proved developed reserves:
Crude oil (MBbls)		2,995		2,633		973		6,601
Natural gas (MMcf)		143,632		21,775		7,024		172,431
NGLs (MBbls)		6,132		1,501		579		8,212
Total (MBoe)		33,066		7,763		2,723		43,552
Proved undeveloped reserves:
Crude oil (MBbls)		2,918		6,601		1,172		10,691
Natural gas (MMcf)		214,706		37,049		5,865		257,620
NGLs (MBbls)		8,020		2,373		477		10,870
Total (MBoe)		46,722		15,149		2,626		64,497
Total proved reserves:
Crude oil (MBbls)		5,913		9,234		2,145		17,292
Natural gas (MMcf)		358,338		58,824		12,889		430,051
NGLs (MBbls)		14,152		3,874		1,056		19,082
Total (MBoe)		79,788		22,912		5,349		108,049
As of December 31, 2023
Proved developed reserves:
Crude oil (MBbls)		13,172		—		—		13,172
Natural gas (MMcf)		252,832		—		—		252,832
NGLs (MBbls)		12,644		—		—		12,644
Total (MBoe)		67,954		—		—		67,954
Proved undeveloped reserves:
Crude oil (MBbls)		17,866		—		—		17,866
Natural gas (MMcf)		255,893		—		—		255,893
NGLs (MBbls)		13,118		—		—		13,118
Total (MBoe)		73,633		—		—		73,633
Total proved reserves:
Crude oil (MBbls)		31,038		—		—		31,038
Natural gas (MMcf)		508,725		—		—		508,725
NGLs (MBbls)		25,762		—		—		25,762
Total (MBoe)		141,587		—		—		141,587

Notable changes in proved reserves for the year ended December 31, 2023 for INR Holdings included the following:

• Extensions. In 2023, total extensions to previous estimates increased proved reserves by 44.6 MMBoe. These extensions primarily related to the addition of 21 proved undeveloped (“PUD”) locations to be developed by 2028 (as that year entered the 5-year development window) which added 32.5 MMBoe of proved reserves. Other extensions included converting 12.0 MMBoe of unproved reserves to proved developed reserves by drilling six wells during 2023, two of which were producing as of December 31, 2023. During 2023, our drilling program was focused on adding locations primarily in the various Utica and Point Pleasant formations in Ohio and the Marcellus shale formation in Pennsylvania.

• Revisions to previous estimates. In 2023, total revisions to previous estimates reduced proved reserves by 24.1 MMBoe. These downward revisions primarily consisted of 20.8 MMBoe of revisions to PUD

F-16

reserves, comprised of downward revisions of 0.9 MMBoe in PUDs from 2022 to 2023 due to decreases in prices during the year ended December 31, 2023, as well as downward revisions of 21.1 MMBoe due to changes to our development plan that resulted in 17 PUD locations being reclassified as they were outside the 5-year development window while the Company performs further technical refinements and analysis to evaluate well spacing assumptions. Downward revisions in PUDs were slightly offset by positive revisions of 1.2 MMBoe due to upward revisions in type curves and increased lateral lengths. Additionally, our proved developed producing properties had downward revisions of 3.3 MMBoe related to decreases in commodity prices which impacted the estimated timing and performance of these wells.

• Purchases of reserves in place. In 2023, 48.2 MMBoe of proved reserves were added primarily from properties acquired in the Ohio Utica Acquisition on October 4, 2023, including 20.4 MMBoe of proved developed reserves and 27.8 of proved undeveloped locations.

Notable changes in proved reserves for the nine months ended September 30, 2023 for URV included the following:

• Extensions. In the nine months ended September 30, 2023, total extensions to previous estimates increased proved reserves by 7.6 MMBoe. These extensions primarily related to development activity in the booking of additional PUDs through 2028 (as that year entered the 5-year development window) and converting unproved reserves to proved developed reserves.

• Revisions to previous estimates. In the nine months ended September 30, 2023, total revisions to previous estimates increased proved reserves by 10.1 MMBoe. These upward revisions primarily consisted of 14.4 MMBoe of positive revisions primarily related to well forecasting, offset by downward revisions of 4.3 MMBoe primarily related to decreases in pricing.

Notable changes in proved reserves for the nine months ended September 30, 2023 for PEO included the following:

• Extensions. In the nine months ended September 30, 2023, total extensions to previous estimates increased proved reserves by 1.9 MMBoe. These extensions primarily related to development activity in the booking of additional PUDs through 2028 (as that year entered the 5-year development window) and converting unproved reserves to proved developed reserves.

• Revisions of previous estimates. In the nine months ended September 30, 2023, total revisions to previous estimates increased proved reserves by 2.7 MMBoe. These upward revisions primarily consisted of 3.4 MMBoe of positive revisions primarily related to well forecasting, offset by downward revisions of 0.7 MMBoe primarily related to decreases in pricing.

Pro Forma Standardized Measure of Discounted Future Net Cash Flows

The following tables present the estimated pro forma discounted future net cash flows as of December 31, 2023. As the Acquisition is included in INR Holdings historical standardized measure as of December 31, 2023, the pro forma standardized measure information set forth below only gives effect to the IPO Transactions as if they had been consummated on December 31, 2023. The pro forma changes in the standardized measure information set forth below gives effect to the Transactions as if they had been consummated on January 1, 2023.

The disclosures below were determined based on INR Holdings historical discounted future net cash flows as of and for the year ended December 31, 2023, as included in the audited consolidated financial statements for the year ended December 31, 2023, included elsewhere in this prospectus. An explanation of the underlying methodology applied, as required by SEC regulations, can also be found therein. The calculations assume the continuation of existing economic, operating and contractual conditions at December 31, 2023.

Therefore, the following estimated pro forma standardized measure and the pro forma changes in the standardized measure are not necessarily indicative of the results that might have occurred had the IPO Transactions been completed on December 31, 2023, or had the Transactions been completed on January 1, 2023, respectively, and are not intended to be a projection of future results. Future results may vary significantly

F-17

from the results reflected because of various factors, including those discussed in the section entitled “Risk Factors” included elsewhere in this prospectus.

Pro Forma Consolidated Discounted Future Net Cash Flows

The following table sets forth the pro formaConsolidated standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of December 31, 2023:

	December 31, 2023
	INR Holdings Historical			Transaction Accounting Adjustments					Infinity Natural Resources Pro Forma Combined
				Acquisition(1)		IPO Transactions(2)
	(in thousands)
Future cash inflows	$	3,865,302		$	—	$	—		$	3,865,302
Future development costs(3)		(545,803	)		—		—			(545,803	)
Future production costs		(1,281,802	)		—		—			(1,281,802	)
Future income tax expenses(4)		—			—		(102,292	)		(454,905	)
Future net cash flows		2,037,697			—		(102,292	)		1,481,061
10% discount to reflect timing of cash flows		(1,099,313	)		—		(163,347	)		(910,048	)
Standardized measure of discounted future net cash flows	$	938,384		$	—	$	(265,639	)	$	672,745

(1) There are no transaction accounting adjustments related to the Acquisition for the pro forma standardized measure as of December 31, 2023, as all assets acquired are included within the INR Holdings historical standardized measure as of such date.

(2) The transaction accounting adjustments for the IPO Transactions reflect the impact of the entity-level income taxation that would have been applicable to the Company as of December 31, 2023, on an undiscounted and discounted basis, based on an estimated 5.0% blended statutory U.S. federal and state tax rate.

(3) Future development costs include costs associated with the future abandonment of proved properties, including proved undeveloped locations.

(4) INR Holdings’ historical future net cash flows do not include the effects of income taxes on future revenues because it was a limited partnership not subject to entity-level income taxation as of December 31, 2023. Accordingly, no provision for federal or state corporate income taxes has been provided historically because taxable income was passed through to the Existing Owners.

F-18

Sources of Change in Pro Forma Consolidated Discounted Future Net Cash Flows

The principal changes in the pro formaConsolidated standardized measure of discounted future net cash flows relating to proved reserves for the year ended December 31, 2023, are as follows:

	INR Holdings Historical			January 1, 2023 through September 30, 2023(1)						Transaction Accounting Adjustments(1)(2)			Infinity Natural Resources Pro Forma Combined
				URV Historical			PEO Ohio Historical
	(in thousands)
Standardized measure of discounted future net cash flows as of December 31, 2022	$	1,017,608		$	570,742		$	129,030		$	—		$	1,717,380
Sales of oil, natural gas, NGLs, net of production costs		(109,179	)		(65,393	)		(16,337	)		—			(190,909	)
Purchases of minerals in place		534,927			—			—			(534,927	)		—
Extensions, net of future development costs		199,378			83,055			20,764			—			303,197
Net change in price and production costs		(643,905	)		(243,437	)		(60,869	)		—			(948,211	)
Previously estimated development costs incurred		68,412			19,639			4,910			—			92,961
Change in estimated future development costs		4,734			(1	)		—			—			4,733
Revisions of previous quantity estimates		(224,318	)		19,806			15,210			—			(189,302	)
Accretion of discount		101,761			42,806			10,701			—			155,268
Net change in income taxes(2)		—			—			—			(265,639	)		(265,639	)
Net change in timing of production and other		(11,034	)		3,442			859			—			(6,733	)
Standardized measure of discounted future net cash flows as of December 31, 2023	$	938,384		$	430,659		$	104,268		$	(800,566	)	$	672,745

(1) The changes in the pro forma standardized measure for the year ended December 31, 2023, include the effects of the activity related to the assets acquired from URV and PEO Ohio for the period from January 1, 2023, through September 30, 2023. As such, for purposes of the pro forma changes in the standardized measure, the transaction accounting adjustment for purchases of reserves in place reflects the impact of the Acquisition assuming it had been consummated on January 1, 2023.

(2) INR Holdings’ historical future net cash flows do not include the effects of income taxes on future revenues because it was a limited partnership not subject to entity-level income taxation for the year ended December 31, 2023. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Existing Owners. The transaction accounting adjustment for the net change in income taxes reflects the impact of the IPO Transactions and the entity-level income taxation that would have been applicable to the Company for the year ended December 31, 2023, based on an estimated 5.0% blended statutory U.S. federal and state tax rate.

F-19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and the Board of Directors of Infinity Natural Resources, Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheet of Infinity Natural Resources, Inc. (the “Company”) as of May 15, 2024 and the related notes (collectively referred to as the “financial statement”). In our opinion, the financial statement presents fairly, in all material respects, the financial position of the Company as of May 15, 2024, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statement based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the financial statement, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statement. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement. We believe that our audit provides a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Pittsburgh, PA

July 22, 2024

We have served as the Company’s auditor since 2024.

F-20

INFINITY NATURAL RESOURCES, INC.

BALANCE SHEET

	May 15, 2024
Assets
Total assets	$	—
Liabilities and Stockholder’s Equity
Total liabilities		—
Subscription receivable from INR Holdings		(100	)
Common stock, $0.001 par value; 1,000 shares authorized, issued and outstanding		100
Total stockholder’s equity		—
Total liabilities and stockholder’s equity	$	—

The accompanying notes are an integral part of this balance sheet.

F-21

INFINITY NATURAL RESOURCES, INC.

NOTES TO BALANCE SHEET

1—Nature of Operations

Infinity Natural Resources, Inc. (“Infinity”) was incorporated in the state of Delaware on May 15, 2024 in anticipation of a potential initial public offering (“IPO”) and related reorganization transactions. Following the IPO and the transactions related thereto, Infinity will be a holding company whose sole material asset will consist of membership interests in Infinity Natural Resources, LLC (“INR Holdings”). After the consummation of the IPO and related reorganization transactions, Infinity will be the managing member of INR Holdings and will control and be responsible for all operational, management and administrative decisions relating to INR Holdings’ business and will consolidate the financial results of INR Holdings and its subsidiaries.

2—Summary of Significant Accounting Policies

Basis of Accounting and Presentation

The accounts are maintained and the balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America. Separate statements of operations, changes in stockholders’ equity and cash flows have not been presented because Infinity has had no operations to date.

3—Stockholder’s Equity

Infinity is authorized to issue 1,000 shares of common stock with a par value of $0.001 per share. INR Holdings had yet to fund its $100 initial capitalization as of May 15, 2024, and thus, Infinity has presented this amount as a subscription receivable within stockholders’ equity.

4—Subsequent Events

Infinity has evaluated subsequent events through July 22, 2024, the date on which the balance sheet was available for issuance, and determined that there are no significant subsequent events requiring adjustment or disclosure.

F-22

INFINITY NATURAL RESOURCES, INC.

Balance Sheets

(Unaudited)

	September 30, 2024			May 15, 2024
Assets
Total assets	$	—		$	—
Liabilities and Stockholder’s Equity
Total liabilities		—			—
Subscription receivable from INR Holdings		(100	)		(100	)
Common stock, $0.001 par value; 1,000 shares authorized, issued and outstanding		100			100
Total stockholder’s equity		—			—
Total liabilities and stockholder’s equity	$	—		$	—

The accompanying notes are an integral part of these unaudited balance sheets.

F-23

INFINITY NATURAL RESOURCES, INC.

Notes to Balance Sheets (Unaudited)

Note 1—Nature of Operations

Infinity Natural Resources, Inc. (“Infinity”) was incorporated in the state of Delaware on May 15, 2024 in anticipation of a potential initial public offering (“IPO”) and related reorganization transactions. Following the IPO and the transactions related thereto, Infinity will be a holding company whose sole material asset will consist of membership interests in Infinity Natural Resources, LLC (“INR Holdings”). After the consummation of the IPO and related reorganization transactions, Infinity will be the managing member of INR Holdings and will control and be responsible for all operational, management and administrative decisions relating to INR Holdings’ business and will consolidate the financial results of INR Holdings and its subsidiaries. As of September 30, 2024, Infinity has not commenced operations and has nominal assets and no liabilities.

Note 2—Summary of Significant Accounting Policies

Basis of Accounting and Presentation

The accounts are maintained and the unaudited balance sheets have been prepared in accordance with accounting principles generally accepted in the United States of America. Separate statements of operations, changes in stockholder’s equity and cash flows have not been presented because Infinity has had no operations to date.

Note 3—Stockholder’s Equity

Infinity is authorized to issue 1,000 shares of common stock with a par value of $0.001 per share. INR Holdings had yet to fund its $100 initial capitalization as of September 30, 2024, and thus, Infinity has presented this amount as a subscription receivable within stockholder’s equity.

Note 4—Subsequent Events

Infinity has evaluated subsequent events through November 26, 2024, the date on which the unaudited balance sheets were available for issuance, and determined that there are no significant subsequent events requiring adjustment or disclosure.

F-24

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members and the Board of Directors of Infinity Natural Resources, LLC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Infinity Natural Resources LLC and subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations, members’ equity and cash flows for each of the two years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Pittsburgh, PA

July 22, 2024

We have served as the Company’s auditor since 2023.

F-25

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Consolidated Balance Sheets

(amounts in thousands)

	December 31, 2023			December 31, 2022
Assets
Current assets:
Cash and cash equivalents	$	1,504		$	739
Accounts receivable:
Oil and natural gas sales, net		23,491			19,747
Joint interest and other, net		20,605			2,574
Prepaid expenses and other current assets		2,354			584
Commodity derivative assets, short term		22,054			5,434
Total current assets		70,008			29,078
Oil and natural gas properties, full cost method (including $37.2 million and $40.7 million as of December 31, 2023 and 2022, respectively excluded from amortization)		652,645			232,605
Other property and equipment		33,542			26,144
Less: Accumulated depreciation, depletion, and amortization		(79,561	)		(25,835	)
Property and equipment, net		606,626			232,914
Operating lease right-of-use assets, net		758			838
Other assets		4,944			1,466
Commodity derivative assets, long-term		6,173			2,409
Total assets	$	688,509		$	266,705
Liabilities and Members’ Equity
Current liabilities:
Accounts payable	$	37,737		$	41,390
Royalties payable		17,575			9,565
Accrued liabilities		1,015			241
Notes payable		124			93
Operating lease liabilities		105			90
Commodity derivative liabilities, short-term		6			5,980
Total current liabilities		56,562			57,359
Line-of-credit		170,964			57,900
Notes payable, long-term		153			155
Operating lease liabilities, net of current portion		652			747
Asset retirement obligations		970			760
Commodity derivative liabilities, long-term		752			278
Total liabilities		230,053			117,199
Commitments and contingencies (Note 13)
Members’ equity		458,456			149,506
Total liabilities and members’ equity	$	688,509		$	266,705

The accompanying notes are an integral part of these consolidated financial statements.

F-26

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Consolidated Statements of Operations

(amounts in thousands)

	For the Year Ended December 31,
	2023			2022
Revenues:
Oil, natural gas, and natural gas liquids sales	$	159,532		$	142,600
Midstream activities		2,198			555
Total revenues		161,730			143,155
Operating expenses:
Gathering, processing, and transportation		31,097			15,673
Lease operating		18,371			8,256
Production and ad valorem taxes		886			719
Depreciation, depletion, and amortization		53,796			18,336
General and administrative		4,885			4,712
Total operating expenses		109,035			47,696
Operating income		52,695			95,459
Other income (expense):
Interest, net		(11,910	)		(2,574	)
Gain (loss) on derivative instruments		45,322			(24,820	)
Other income		565			64
Net income	$	86,672		$	68,129

The accompanying notes are an integral part of these consolidated financial statements.

F-27

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Consolidated Statements of Members’ Equity

(amounts in thousands)

	Class A		Class B		Total
Balance as of December 31, 2021	$	81,377		—	$	81,377
Net income		68,129		—		68,129
Balance as of December 31, 2022		149,506		—		149,506
Contributions		—		222,278		222,278
Net income		41,100		45,572		86,672
Balance as of December 31, 2023	$	190,606	$	267,850	$	458,456

The accompanying notes are an integral part of these consolidated financial statements.

F-28

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(amounts in thousands)

	For the Year Ended December 31,
	2023			2022
Cash flows from operating activities:
Net income	$	86,672		$	68,129
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		53,796			18,336
Amortization of debt issuance costs		778			194
(Gain) loss on derivative instruments		(45,322	)		24,820
Cash received (paid) on settlement of derivative instruments		19,438			(37,888	)
Non-cash lease expense		98			63
Changes in operating assets and liabilities:
Accounts receivable		(21,775	)		(9,068	)
Prepaid expenses and other assets		(1,770	)		(214	)
Accounts payable		7,565			(2,156	)
Royalties payable		6,390			3,119
Accrued and other expenses		703			687
Other assets and liabilities		(98	)		(1,046	)
Net cash provided by operating activities		106,475			64,976
Cash flows from investing activities:
Additions to oil and gas properties		(145,979	)		(84,092	)
Acquisitions of oil and gas properties		(278,967	)		—
Additions to property and equipment		(11,740	)		(11,569	)
Net cash used in investing activities		(436,686	)		(95,661	)
Cash flows from financing activities:
Borrowings under revolving credit facility		203,864			127,636
Payments on revolving credit facility		(90,800	)		(97,686	)
Proceeds from contributions from issuance of Class B interests		222,278			—
Payments of debt issuance costs		(4,256	)		(908	)
Payments on notes payable		(110	)		(45	)
Net cash provided by financing activities		330,976			28,997
Net increase (decrease) in cash and cash equivalents		765			(1,688	)
Cash and cash equivalents at beginning of period		739			2,427
Cash and cash equivalents at end of period	$	1,504		$	739

The accompanying notes are an integral part of these consolidated financial statements

F-29

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

Note 1—Description of the Business and Basis of Presentation

Description of Business

Infinity Natural Resources, LLC, together with its subsidiaries (collectively referred to as “INR Holdings”) is an oil and natural gas exploration and production company engaged in the acquisition, exploration, and development of properties for the production of oil, natural gas, and natural gas liquids (“NGLs”) from underground reservoirs. INR Holdings was organized as a Delaware limited liability company (“LLC”) on June 6, 2017. Our operations are located in the Appalachian Basin in the northeastern United States.

Basis of Accounting and Presentation

The consolidated financial statements present the financial position, results of operations, and cash flows of INR Holdings in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). All intercompany balances and transactions are eliminated upon consolidation.

Note 2—Summary of Significant Accounting Policies

Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported revenues and expenses during the reporting periods, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates. Estimates of reserves are used to determine depletion and to conduct impairment analysis. Estimating reserves is inherently uncertain, including the projection of future rates of production and the timing of development expenditures.

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry, given the challenges resulting from volatility in oil and natural gas prices. For instance, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, recent measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of these events and changing market conditions. Such circumstances generally increase the uncertainty in INR Holdings’ accounting estimates, particularly those involving financial forecasts.

INR Holdings evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from INR Holdings’ estimates. Any effects on INR Holdings’ business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Cash and Cash Equivalents

We consider all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short-term maturity of these investments. Interest earned on cash equivalents is included as a reduction of interest expense, net. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits; however, we have not experienced any significant losses from such investments.

F-30

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

Accounts Receivable and Allowance for Expected Credit Losses

Accounts receivable consist of receivables from the sales of oil, natural gas, and NGL production delivered to purchasers and from joint interest owners on properties INR Holdings operates. Accounts receivable are stated at the amount due, net of an allowance for expected losses as estimated by INR Holdings when applicable. Most payments for accounts receivable are received within 30 to 60 days. INR Holdings typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest accounts receivable from joint interest owners outstanding longer than the contractual payment terms are considered past due.

As of December 31, 2023 and 2022, INR Holdings’ allowances for credit losses were not material and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of our counterparties.

Concentrations of Credit Risk

We are exposed to credit risk in the event of nonpayment by counterparties. We sell production to a relatively small number of customers, as is customary in our business. The table below summarizes the purchasers that accounted for 10% or more of INR Holdings’ total revenues from the sale of commodities for the periods presented:

	December 31, 2023			December 31, 2022
Marathon Oil Company		49	%		38	%
BP America		28	%		46	%
Blue Racer Midstream		13	%		15	%

During these periods, no other purchaser accounted for 10% or more of INR Holdings’ total commodity sales revenues. As of December 31, 2023, INR Holdings’ accounts receivable balance related to oil and gas sales was comprised of amounts due from various purchasers, including amounts due from Marathon Oil Company, BP America, and Ergon comprising 56%, 24%, and 11%, respectively, of the total balance. As of December 31, 2022, INR Holding’ accounts receivable balance related to oil and gas sales was comprised of amounts due from Marathon Oil Company and BP America, which accounted for 56% and 39%, respectively, of the total balance.

The loss of any one or more of INR Holdings’ major purchasers could materially and adversely affect our revenues in the short-term. However, based on the demand for oil and natural gas and the availability of other purchasers, INR Holdings believes that the loss of any major purchaser would not have a material adverse effect on its financial condition and results of operations as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

By using derivative instruments to economically hedge exposures to changes in commodity prices, INR Holdings also exposes itself to credit risk. When the fair value of a derivative contract is positive, the counterparty owes INR Holdings, which creates credit risk. We minimize the credit risk in derivative instruments by: (i) limiting our exposure to any single counterparty; and (ii) only entering into hedging arrangements with counterparties that are also participants in our credit agreement, all of which have investment-grade credit ratings.

Oil and Gas Properties

INR Holdings uses the full cost method of accounting for its oil and natural gas properties. Accordingly, all costs directly associated with the acquisition, exploration, and development of oil, natural gas, and NGL reserves for both productive and nonproductive properties are capitalized into a full cost pool. Capitalized costs also include the costs of unproved properties and internal costs directly related to the Company’s acquisition, exploration, and development activities. All general and administrative corporate costs unrelated to drilling

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

activities are expensed as incurred. Capitalized costs of proved properties is 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 average depletion rate of our oil and natural gas properties was $7.54 per Boe and $5.41 per Boe for the years ended December 31, 2023 and 2022, respectively.

Under the full cost method of accounting, total net capitalized costs of proved oil and natural gas properties may not exceed the ceiling limitation determined based on the estimated future net revenues of our proved reserves discounted at 10%. The future net revenues are estimated using the average of the first day of the month trailing 12-month price as of the period end date in accordance with guidance provided by the Securities and Exchange Commission (“SEC”), adjusted for basis or location differentials, held constant over the life of the proved reserves. A ceiling limitation calculation is performed at the end of each quarter. If the ceiling limitation is exceeded, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts members’ equity and typically results in lower depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.

The costs associated with unproved properties are primarily the costs to acquire unproved acreage. We also may capitalize interest on expenditures made in connection with bringing unproved properties to their intended use. INR Holdings determines capitalized interest, when applicable, by multiplying our weighted-average borrowing cost on our revolving credit facility by the average amount of qualifying costs incurred that were excluded from the full cost pool; however, capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The Company did not capitalize any interest on unproved properties during the years ended December 31, 2023 and 2022.

Costs associated with unproved properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We review our unproved properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. All costs classified as unproved properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, and the assignment of proved reserves and whether the proved reserves can be developed economically. During any period in which these factors indicate an impairment, all or a portion of the associated capitalized costs are transferred to the full cost pool and become subject to amortization and the full cost ceiling limitation.

Other Property and Equipment

Other property and equipment includes midstream assets, vehicles, furniture, fixtures, office equipment, and leasehold improvements, all of which are recorded at cost. These assets are depreciated using the straight-line method over their estimated useful lives which range between three and 25 years. Equipment upgrades and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts and a gain or loss is recorded in the consolidated statements of operations as needed.

Leases

At contract inception, INR Holdings determines whether or not an arrangement contains a lease in accordance with the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification Topic 842, Leases (“ASC 842”). A contract is or contains a lease if it conveys the right to control the use of an

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

identified asset for a period of time in exchange for consideration. Upon determination that a contract meets the definition of a lease subject to ASC 842, a right-of-use asset and related lease liability are recorded based on the present value of the future lease payments over the lease term. Right-of-use assets represent INR Holdings’ right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make future lease payments arising from the lease. Since the implicit rate in the lease is generally not available, INR Holdings utilizes its incremental borrowing rate as the discount rate for determining the present value of lease payments.

Asset Retirement Obligations

We accrue a liability for the estimated future costs associated with the plugging and abandonment of our oil and natural gas properties. For oil and natural gas wells, the fair value of our plugging and abandonment obligations is recorded at the time the obligation is incurred, which is typically at the time the well is spud. The fair value of the liability recognized is based on the present value of the estimated future cash outflows associated with our plugging and abandonment obligations. Revisions typically occur due to changes in estimated abandonment costs or the remaining lives of our wells, or if federal or state regulators enact new requirements regarding the abandonment of wells. We deplete the amount added to the costs of proved oil and natural gas properties and recognize an expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties. Accretion expense is included within depreciation, depletion, and amortization in the consolidated statements of operations.

Revenue Recognition

INR Holdings derives revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when a performance obligation is satisfied by transferring control of the produced oil, natural gas, or NGLs to the customer. For all commodity products, we record revenue in the month production is delivered to the customer based on the amount of production delivered to the customer and the price we will receive. Payments are generally received between 30 and 60 days after the date of production.

Reportable Segment

INR Holdings operates in only one reportable segment that is the exploration and production segment. All of our operations are conducted in one geographic area within the Appalachian Basin, primarily in Pennsylvania and Ohio, in the United States.

Income Taxes

As a limited partnership, we are not a taxpaying entity for federal income tax purposes. As such, we have not recorded federal income tax expense. Our limited partners are responsible for federal income taxes on their respective share of taxable income. We file federal income tax returns in the United States. In certain circumstances, we are subject to state taxes on income arising in or derived from the state tax jurisdictions in which we operate.

Adoption of New Accounting Standards

In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires all leases with terms greater than 12 months to be recognized by the lessee as assets and liabilities on the consolidated balance sheet. When measuring lease assets and liabilities, payments to be made for optional extension periods are included if we as the lessee are reasonably certain to exercise the option. Leases are classified as either operating or financing, with classification affecting the pattern

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

of expense recognition in the consolidated statement of operations. This ASU also expanded the required quantitative and qualitative disclosures surrounding leases. Mineral leases are excluded from the scope of ASU 2016-02. We elected the package of practical expedients permitted under the new standard, which among other things, allows for lease and non-lease components in a contract to be accounted for as a single lease component for all asset classes and the carry forward of historical lease classifications. INR Holdings adopted this ASU on January 1, 2022, by recording an operating lease liability (inclusive of the short-term and long-term amounts) and corresponding operating lease right-of-use asset of $0.9 million.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”), which replaces the incurred loss impairment methodology to reflect expected credit losses. The amendment requires the measurement of all expected credit losses for financial assets held at the reporting date to be performed based on historical experience, current conditions, and reasonable and supportable forecasts. We consider a number of factors, including the length of time accounts receivable are past due, our previous loss history, the debtor’s current ability to pay its obligation to INR Holdings, the condition of the general economy and the industry as a whole. We write-off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. ASU 2016-13 is effective for annual and interim periods beginning after December 15, 2022. INR Holdings adopted this standard on January 1, 2023. This adoption did not have a material impact on our consolidated financial statements.

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), which was subsequently amended by ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848. This guidance provides optional practical expedients and exceptions for applying U.S. GAAP provisions to contracts, hedging relationships, and other transactions that reference LIBOR, or other reference rates expected to be discontinued because of reference rate reform, if certain criteria are met. The guidance in this update was effective upon its issuance. As of December 31, 2023, INR Holdings did not have any contracts, hedging relationships, or other transactions referenced to LIBOR.

Accounting Standards Not Yet Adopted

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280)—Improvements to Reportable Segment Disclosures (“ASU 2023-07”), which updates reportable segment disclosure requirements primarily by enhancing disclosures about significant segment expenses and information used to assess segment performance. Additionally, ASU 2023-07 enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss and provides new segment disclosure requirements for entities with a single reportable segment. The amendments are effective for annual periods beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. Management is currently evaluating this ASU to determine its impact on INR Holdings’ disclosures. Adoption of the update is not expected to have a material impact to INR Holdings’ financial position, results of operations or liquidity.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740)—Improvements to Income Tax Disclosures (“ASU 2023-09”), which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated and provides additional requirements regarding income taxes paid. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted, and should be applied either prospectively or retrospectively. Management is currently evaluating this ASU to determine its impact on INR Holdings’ disclosures. Adoption of the update is not expected to have a material impact to INR Holdings’ financial position, results of operations or liquidity.

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

We considered the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or not material upon adoption.

Note 3—Revenues

Crude oil, natural gas, and NGL sales are recognized at the point that control of the product is transferred to the customer. Virtually all of INR Holdings’ contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials.

Commodity sales revenues presented within the consolidated statements of operations relate to the sale of oil, natural gas, and NGLs as shown below:

	For the Year Ended December 31,
	2023		2022
(in thousands)
Oil revenues	$	85,276	$	54,631
Natural gas revenues		49,617		66,048
NGL revenues		24,639		21,921
Oil, natural gas, and natural gas liquids sales	$	159,532	$	142,600

Oil Sales

Our crude oil sales contracts are generally structured whereby oil is delivered to the customer at a contractually agreed-upon delivery point. This delivery point is usually at the wellhead or at the inlet of a transportation pipeline. Revenue is recognized when control transfers to the customer at the delivery point based on the net price received from the customer. Any downstream transportation or marketing costs incurred by purchasers of our crude oil are reflected in the price we receive and are presented as a net reduction to oil sales revenues.

Natural Gas and NGL Sales

Under INR Holdings’ 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 INR Holdings. For these contracts, INR Holdings evaluates when control of the residue gas and NGLs is transferred in order to determine whether revenues should be recognized on a gross or net basis. Where INR Holdings elects to take its residue gas and/or NGL production “in-kind” at the plant tailgate, fees incurred prior to transfer of control at the outlet of the plant are presented as gathering, processing, and transportation expense within the consolidated statements of operations. Where INR Holdings does not take its residue gas and/or NGL production “in-kind”, transfer of control typically occurs at the inlet of the midstream entity’s gas gathering system such that any fees incurred subsequent to the delivery point are reflected as a net reduction to natural gas and NGL revenues presented in the table above and as included within oil, natural gas, and natural gas liquids sales within the consolidated statements of operations.

Performance Obligations

INR Holdings commodity sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of its commodity sales contracts. Under our revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

For all commodity products, we record revenue in the month production is delivered to the purchaser. Settlement statements for crude oil are generally received within 30 days following the date that production volumes are delivered, but for natural gas and NGL sales, statements may not be received for 30 to 60 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At such time, the volumes delivered and sales prices can be reasonably estimated and amounts due from customers are accrued in Accounts receivable – oil and natural gas sales, net in the consolidated balance sheets. As of December 31, 2023 and 2022, such receivable balances were $23.5 million and $19.7 million, respectively.

Note 4—Acquisitions

Ohio Utica Acquisition

On August 7, 2023, Wolf Run Operating, LLC (“Wolf Run”), a wholly-owned subsidiary of INR Holdings, entered into a definitive purchase and sale agreement to acquire working interests in certain oil and gas assets from Utica Resource Ventures, LLC and Utica Resource Operating, LLC (collectively, “URV”), and Providence Energy Operating Ohio, LLC (“PEO,” and together with URV, the “Sellers”) for $306.4 million, subject to customary purchase price adjustments (the “Ohio Utica Acquisition”).

The transaction closed on October 4, 2023, for $279.0 million (including transaction costs that were capitalized as part of the asset acquisition) and was financed through a combination of $222.3 million that was raised from the issuance by INR Holdings of new Class B interests as well as borrowings of $56.7 million under our amended and restated credit agreement.

As part of the Ohio Utica Acquisition, we assumed control of approximately 36,783 net acres across Washington, Morgan, Noble, and Guernsey counties in Ohio along with 54 producing horizontal laterals, related surface equipment located on various pad locations and a deep inventory of premium drilling locations located within the volatile oil window of the Utica and Point Pleasant plays in eastern Ohio. The $280.7 million was recorded to proved properties with no value attributed to unproved leasehold acreage acquired.

In accordance with ASC 805, Business Combinations (“ASC 805”), we performed an initial screen test as of the transaction close date in order to determine whether the acquired set should be accounted for as an asset acquisition or business combination. Based on our assessment of the fair values of the gross assets acquired, we determined that the Ohio Utica Acquisition did not meet the definition of a business combination in accordance with ASC 805, and as such, have accounted for the transaction as an asset acquisition.

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 December 31, 2023 and 2022 are as follows:

	December 31, 2023			December 31, 2022
(in thousands)
Oil and natural gas properties:
Proved properties	$	615,456		$	191,887
Unproved properties		37,189			40,718
Gross oil and natural gas properties		652,645			232,605
Less: accumulated depreciation, depletion, and amortization		(77,085	)		(25,010	)
Oil and natural gas properties, net	$	575,560		$	207,595

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

Under the full cost method of accounting, all such costs of productive and nonproductive wells, including salaries, benefits, and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production $52.1 million and $17.5 million of amortization expense on oil and gas properties within the full cost pool for the years ended December 31, 2023 and 2022, respectively. We capitalized internal costs of approximately $2.2 million and $1.6 million for the years ended December 31, 2023 and 2022, respectively.

Capitalized costs of oil and natural gas properties are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved oil, natural gas, and NGL reserves discounted at 10%. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, despite commodity price increases which subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of reserves. Historically, we have not designated any of our derivative contracts as cash flow hedges. Prices used to calculate the ceiling value of reserves were as follows:

	For the Year Ended December 31,
	2023		2022
Oil (per barrel)	$	78.22	$	93.67
Natural gas (per MMBtu)	$	2.64	$	6.36
NGLs (per barrel)	$	26.87	$	41.21

Using the average quoted prices above, adjusted for market differentials, the net book value of INR Holdings’ oil and natural gas properties did not exceed the ceiling amount at December 31, 2023 or 2022. We had no derivative positions that were designated for hedge accounting as of and for the years ended December 31, 2023 and 2022. Future decreases in market prices, as well as changes in production rates, levels of reserves, evaluation costs excluded from amortization, future development costs and production costs may result in future non-cash impairments to INR Holdings’ oil and natural gas properties.

Costs associated with unproved properties are excluded from the amortization base until the properties are evaluated or impairment is indicated. The costs associated with unproved leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from the amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value.

Our decision to exclude costs from amortization and the timing of the transfer of those costs into the amortization base involves judgment and may be subject to changes over time based on numerous factors, including drilling plans, availability of capital, project economics, and drilling results from adjacent acreage.

Costs of unproved properties excluded from amortization consist of leasehold acreage and relate to properties which are not individually significant for which the evaluation process has not been completed. The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells, results of drilling, and other assessments. Therefore, we are unable to estimate when these costs will be included in the amortization computation.

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

Other Property and Equipment

Our other property and equipment consists of the following assets that are recorded at cost and depreciated on a straight-line basis over the respective estimated useful lives.

	December 31,
	2023			2022
(in thousands)
Midstream assets	$	31,338		$	25,052
Vehicles		1,392			328
Furniture, fixtures, and office equipment		260			212
Leasehold improvements		552			552
Less: Accumulated depreciation		(2,476	)		(825	)
Total other property and equipment, net	$	31,066		$	25,319

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 INR Holdings’ full cost pool are evaluated for recoverability whenever events or changes in circumstances indicate that such carrying values may not be recoverable. Should an impairment exist, the impairment loss would be measured as the amount that the asset’s carrying value exceeds its fair value. We did not recognize any impairment during the years ended December 31, 2023 and 2022. Total depreciation expense for the years ended December 31, 2023 and 2022 totaled approximately $1.7 million and $0.8 million, respectively.

Note 6—Leases

At contract inception, INR Holdings determines whether or not an arrangement contains a lease in accordance with ASC 842. A contract is or contains a lease if it conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Upon determination that a contract meets the definition of a lease subject to ASC 842, a right-of-use asset and related lease liability are recorded based on the present value of the future lease payments over the lease term. Right-of-use assets represent INR Holdings’ right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make future lease payments arising from the lease. Since the implicit rate in the lease is generally not available, INR Holdings utilizes its incremental borrowing rate as the discount rate for determining the present value of lease payments. Right-of-use assets also include any lease payments made prior to commencement, excluding any lease incentives received.

We may enter into lease agreements for various purposes including drilling rig contracts, wellhead and surface equipment, rights-of-way and easements, and office space and equipment. For agreements that contain both lease and non-lease components, we have elected to combine and account for these as a single lease component. As of December 31, 2023, our lease agreements have remaining lease terms ranging from one month to 15 years; some of our agreements include options to extend the lease term and some of our agreements include options to early terminate at our sole discretion. These options are considered in determining the lease term and

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

are included in the present value of future payments that are recorded for leases when INR Holdings is reasonably certain to exercise the option. None of our lease agreements contain any material residual value guarantees or material restrictive covenants.

Leases with an initial term of 12 months or less are not recorded on the consolidated balance sheets. Lease expense for operating leases recorded on our consolidated balance sheets is recognized on a straight-line basis over the lease term. Variable lease payments for leases that are not recorded on our consolidated balance sheets are recognized in the period in which they are incurred, which primarily relate to our office space and equipment leases.

The following table provides additional information related to INR Holdings’ lease right-of-use assets and liabilities:

	December 31,
	2023			2022
Weighted-average discount rate		9.1	%		5.8	%
Weighted-average remaining lease term (years)		13.0			13.1

For the years ended December 31, 2023 and 2022, lease expense, including operating leases related to our office space, of $0.2 million and $0.1 million, respectively, was included within general and administrative expenses within our consolidated statements of operations.

Payments due under INR Holdings’ long-term operating lease liabilities by fiscal year as of December 31, 2023, are as follows:

	Operating Leases
(in thousands)
2024	$	105
2025		130
2026		87
2027		87
2028		87
Thereafter		797
Total lease payments		1,293
Less: imputed interest		(536	)
Present value of lease liabilities	$	757

Note 7—Asset Retirement Obligations

	December 31,
	2023			2022
(in thousands)
Asset retirement obligations, beginning of period	$	760		$	581
Liabilities assumed in mergers and acquisitions		150			—
Liabilities incurred		34			69
Accretion expense		70			92
Revision to estimated cash flows		(44	)		18
Asset retirement obligations, end of period	$	970		$	760

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

An asset retirement obligation represents a legal obligation associated with the retirement of a tangible long-lived asset in which the timing and/or method of settlement may or may not be conditional on a future event that may or may not be within INR Holdings’ control. The liability is initially measured as the present value of the estimated future costs associated with plugging and abandonment of oil and natural gas wells and other equipment removal, and land restoration activities. Upon initially recognizing the liability, INR Holdings capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period through accretion expense and the capitalized cost is depleted over the units-of-production method as part of the full cost pool. Accretion expense is included as part of depreciation, depletion, and amortization in the consolidated statements of operations.

Inherent in the fair value calculation of asset retirement obligations are numerous estimates and assumptions including plugging and abandonment settlement amounts, inflation rates, credit-adjusted risk-free rates, and the timing of settlement. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable.

Note 8—Debt

Amended and Restated Credit Facility

On October 4, 2023, INR Holdings entered into an Amended and Restated Credit Facility with a syndicate of financial institutions. Borrowings under the credit facility are subject to borrowing base limitations based upon the discounted net present value of our oil and gas properties and are subject to semi-annual redeterminations. The credit facility is guaranteed by our subsidiaries and is secured by first priority security interests on substantially all of our consolidated assets, including a mortgage on at least 90% of the total value of the proved properties evaluated in the most recently delivered reserve report, including any engineering report relating to the crude oil and natural gas properties of our restricted domestic subsidiaries, subject to customary exceptions.

Borrowings under the Amended and Restated Credit Facility may be base rate loans or Secured Overnight Financing Rate (“SOFR”) loans. Base rate loans bear interest at a rate per annum equal to the greater of: (i) the administrative agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted Term SOFR rate (as defined in the Amended and Restated Credit Facility agreement) for a one-month interest period plus 100 basis points, plus an applicable margin, depending on the percentage of the borrowing base utilized, plus an additional basis point credit spread. SOFR loans bear interest at SOFR plus an applicable margin, depending on the percentage of the borrowing base utilized, plus an additional basis point credit spread. We also pay a commitment fee on unused elected commitment amounts under our credit facility, which is also dependent on the percentage of the borrowing base utilized. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. The Amended and Restated Credit Facility matures in April 2026. As of December 31, 2023, INR Holdings’ reserves supported a $275.0 million credit facility of which $171.0 million was outstanding leaving $104.0 million of unused capacity.

For the years ended December 31, 2023 and 2022, total interest expense on our credit facility was approximately $10.1 million and $2.2 million, respectively. We did not capitalize any interest expense for the years ended December 31, 2023 and 2022. For the years ended December 31, 2023 and 2022, INR Holdings’ weighted-average interest rate was 9.1% and 5.8%, respectively.

Debt issuance costs associated with our credit facility are capitalized and presented as other assets within the consolidated balance sheets. Because debt issuance costs are related to a line of credit, they are presented as an asset, rather than an offset to the corresponding liability. Debt issuance costs are amortized using the straight-line method over the term of the related agreement. Capitalized debt issuance costs were approximately $4.7 million and $1.1 million as of December 31, 2023, and December 31, 2022, respectively. Amortization of debt issuance

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

costs, which is included within interest expense in the consolidated statements of operations, was approximately $0.8 million and $0.2 million for the years ended December 31, 2023 and 2022, respectively.

The Amended and Restated Credit Facility also requires INR Holdings to maintain compliance with financial ratios including a current ratio of not less than 1.0 to 1.0 and a leverage ratio no greater than 3.0 to 1.0, each of which is defined within the terms of the Amended and Restated Credit Agreement. INR Holdings is in compliance with the covenants and financial ratios under the Amended and Restated Credit Facility described above through the date this annual report was available to be issued.

Other Long-Term Debt

Other long-term debt principally relates to car loans associated with INR Holdings’ car fleet to support service and maintenance of our operated wells.

Payments due by fiscal year related to other long-term debt as of December 31, 2023 are as follows:

	Notes Payable
(in thousands)
2024	$	124
2025		99
2026		43
2027		11
2028		—
Total payments	$	277

Note 9—Derivatives and Risk Management

INR Holdings is exposed to volatility in market prices and basis differentials for oil, natural gas, and NGLs, which impacts the predictability of our cash flows related to the sale of those commodities. The overall objective of INR Holdings’ hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices, which we do by using various derivative instruments including fixed price swaps, basis swaps, and collars. As a result of our hedging activities, we may realize prices that are greater or less than the market prices that we would have otherwise received.

We typically enter into over the counter (OTC) derivative contracts with financial institutions and regularly monitor the creditworthiness of all counterparties. Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our revolving credit facility. As of December 31, 2023, we did not have any cash or letters of credit posted as collateral for our derivative financial instruments.

INR Holdings does not designate any of its derivative instruments as cash flow hedges; therefore, all changes in fair value of our derivative instruments are recognized in other income within the consolidated statements of operations. We recognize all derivative instruments as either assets or liabilities at fair value within the consolidated balance sheets, subject to netting arrangements with our counterparties that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities.

Contracts that result in physical delivery of a commodity expected to be sold by INR Holdings 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.

F-41

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

The following tables provide information about INR Holdings’ derivative financial instruments. The tables present the notional amount, the weighted average contract prices and the fair values by expected maturity dates as of December 31, 2023.

	Volume		Weighted Average Price		Fair Value as of December 31, 2023
Oil	(in MBbls)		($ per Bbl)		(in thousands)
Fixed price swaps
2024		1,603	$	74.54	$	4,804
2025		776	$	70.53		1,583
2026		211	$	68.24		577
2027		13	$	66.49		31
Total		2,603			$	6,995

	Volume		Weighted Average Price		Fair Value as of December 31, 2023
Natural gas	(in MMBtu)		($ per MMBtu)		(in thousands)
Fixed price swaps
2024		20,249	$	3.49	$	18,580
2025		17,372	$	3.65		3,531
2026		2,713	$	4.07		303
2027		119	$	4.45		2
Total		40,453			$	22,416

	Volume		Basis Differential			Fair Value as of December 31, 2023
Natural gas	(in MMBtu)		($ per MMBtu)			(in thousands)
Basis swaps
2024		22,736	$	(0.97	)	$	(2,255	)
2025		17,372	$	(1.07	)		(444	)
2026		2,713	$	(1.10	)		(129	)
2027		119	$	(0.99	)		(8	)
Total		42,940				$	(2,836	)

	Volume		Weighted Average Price		Fair Value as of December 31, 2023
Ethane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		8,888,600	$	0.25	$	399
2025		4,932,000	$	0.25		41
2026		419,500	$	0.29		3
2027		8,000	$	0.35		—
Total		14,248,100			$	443

F-42

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

	Volume		Weighted Average Price		Fair Value as of December 31, 2023
Propane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		15,737,800	$	0.73	$	819
2025		9,792,200	$	0.69		126
2026		2,685,500	$	0.70		112
2027		168,000	$	0.73		10
Total		28,383,500			$	1,067

	Volume		Weighted Average Price		Fair Value as of December 31, 2023
Isobutane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		3,058,200	$	0.87	$	(216	)
2025		1,891,600	$	0.81		(121	)
2026		512,500	$	0.77		(31	)
2027		32,000	$	0.78		(2	)
Total		5,494,300			$	(370	)

	Volume		Weighted Average Price		Fair Value as of December 31, 2023
Normal butane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		5,169,600	$	0.85	$	(185	)
2025		3,206,500	$	0.79		(155	)
2026		872,000	$	0.78		(31	)
2027		54,000	$	0.79		(1	)
Total		9,302,100			$	(372	)

	Volume		Weighted Average Price		Fair Value as of December 31, 2023
Pentane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		3,816,000	$	1.44	$	102
2025		2,313,600	$	1.35		(3	)
2026		579,500	$	1.32		25
2027		35,000	$	1.30		2
Total		6,744,100			$	126

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.

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

The following table summarizes the gross fair value of our derivative assets and liabilities and the effect of netting as of December 31, 2023 and 2022:

	December 31, 2023
Balance Sheet Classification	Gross Amounts		Netting Adjustment			Net Amounts Presented on Balance Sheet
(in thousands)
Assets
Commodity derivative assets, short-term	$	26,176	$	(4,122	)	$	22,054
Commodity derivative assets, long-term		8,046		(1,873	)		6,173
Total assets	$	34,222	$	(5,995	)	$	28,227
Liabilities
Commodity derivative liabilities, short-term	$	4,128	$	(4,122	)	$	6
Commodity derivative liabilities, long-term		2,625		(1,873	)		752
Total liabilities	$	6,753	$	(5,995	)	$	758

	December 31, 2022
Balance Sheet Classification	Gross Amounts		Netting Adjustment			Net Amounts Presented on Balance Sheet
(in thousands)
Assets
Commodity derivative assets, short-term	$	7,213	$	(1,779	)	$	5,434
Commodity derivative assets, long-term		2,852		(443	)		2,409
Total assets	$	10,065	$	(2,222	)	$	7,843
Liabilities
Commodity derivative liabilities, short-term	$	7,759	$	(1,779	)	$	5,980
Commodity derivative liabilities, long-term		721		(443	)		278
Total liabilities	$	8,480	$	(2,222	)	$	6,258

Our total derivative gains and losses for the years ended December 31, 2023 and 2022 were as follows:

	For the Year Ended December 31,
	2023		2022
(in thousands)
Realized gain (loss) on derivative instruments	$	19,438	$	(37,888)
Unrealized gain on derivative instruments		25,884		13,068
Total gain (loss) on derivative instruments	$	45,322	$	(24,820)

Note 10—Fair Value Measurements

Certain of INR Holdings’ 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

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

The carrying values of cash and cash equivalents, including accounts receivable, other current assets, accounts payable and other current liabilities on the consolidated balance sheets approximate fair value because of their short-term nature. Additionally, the carrying value of outstanding borrowings under our revolving credit facility approximates fair value because the interest rates are variable and reflective of market rates. We consider the fair value of our revolving credit facility to be a Level 2 measurement on the fair value hierarchy, as discussed further below. The carrying value of borrowings under our revolving credit facility approximate fair value as interest rates applicable to our borrowings outstanding are based on prevailing market rates.

We follow ASC Topic 820, Fair Value Measurement which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

• Level 1: Quoted Prices in Active Markets for Identical Assets—inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

• Level 2: Significant Other Observable Inputs—inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets (other than quoted prices included within Level 1), and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

• Level 3: Significant Unobservable Inputs—inputs to the valuation methodology are unobservable but should reflect the assumptions that market participants would use when pricing the asset or liability, including assumptions about risk (consistent with the fair value measurement objective).

Recurring Fair Value Measurements

The following table presents, for each applicable level within the fair value hierarchy, INR Holdings’ net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis.

	December 31, 2023
	Level 1		Level 2			Level 3		Fair Value
(in thousands)
Assets
Fixed price swaps	$	—	$	31,047		$	—	$	31,047
Basis swaps		—		—			—		—
Liabilities
Fixed price swaps		—		(742	)		—		(742	)
Basis swaps		—		(2,836	)		—		(2,836	)
Total	$	—	$	27,469		$	—	$	27,469

F-45

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

	December 31, 2022
	Level 1		Level 2			Level 3		Fair Value
(in thousands)
Assets
Fixed price swaps	$	—	$	2,833		$	—	$	2,833
Basis swaps		—		375			—		375
Collars		—		2,805			—		2,805
Liabilities
Fixed price swaps		—		(4,306	)		—		(4,306	)
Basis swaps		—		(121	)		—		(121	)
Collars		—		—			—		—
Total	$	—	$	1,586		$	—	$	1,586

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. INR Holdings 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.

Nonrecurring Fair Value Measurements

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include asset retirement obligations when incurred and other long-lived assets that are written down to fair value when they are impaired. INR Holdings did not record any impairment charge related to these assets and liabilities for the years ended December 31, 2023 and December 31, 2022.

Note 11—Members’ Equity

On June 6, 2017, holders of INR Holdings’ equity interests approved the LLC Agreement to, among other things, authorize the issuance of approximately $102.7 million of Class A interests. Subsequently, INR Holdings received $90.3 million of contributions in exchange for Class A interests, with additional contributions received through 2021 up to the total commitment amount of $102.7 million.

On August 4, 2023, holders of INR Holdings’ Class A interests approved the Amended and Restated LLC Agreement to, among other things, authorize the issuance of approximately $23.0 million of Class B interests upon the signing of the purchase and sale agreement for the Ohio Utica Acquisition. The Amended and Restated LLC Agreement became effective on October 4, 2023. Upon the closing of the Ohio Utica Acquisition, INR Holdings issued an additional $199.3 million of Class B interests, the proceeds of which were used to fund a portion of the purchase consideration for the Ohio Utica Acquisition.

INR Holdings is managed by a board of managers comprised of seven managers including two managers that are executives of INR Holdings, four managers that are representatives of Pearl Energy Investment Management, LLC, and one manager that is a representative of NGP Energy Capital Management, L.L.C. Each manager has one vote on any company matter decided by vote and each matter requires a majority vote, with the

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

exception of the removal of any manager which requires a super majority. As of December 31, 2023, affiliates of Pearl Energy Investment Management, LLC and NGP XI US Holdings, L.P., an affiliate of NGP Energy Capital Management, L.L.C., owned 73.0% and 25.0%, respectively, of our Class A and Class B interests.

Profits and losses for both Class A and Class B interests are determined and allocated among each equity interest holder in a manner such that the adjusted capital account of each equity interest holder is as nearly as possible equal to the distributions that would be made to such equity interest holder if certain transactions occur based on each equity interest holders proportionate ownership interest in INR Holdings.

In connection with the issuance of the Class A and Class B interests, pursuant to the LLC Agreement, INR Holdings also issued non-voting, performance-based incentive units to certain members of management. The incentive units contain one or more performance-based vesting conditions. INR Holdings determined that the grant date fair value was not material as it relates to the incentive units issued in conjunction with the issuance of the Class A interests in 2017. Further, while the Class B interests were issued in October 2023, the corresponding incentive units were not considered issued until January 1, 2024 given that the awards had not been granted from an accounting perspective prior to such date. Accordingly, no compensation expense was recorded related to the incentive units for the years ended December 31, 2023 and 2022.

Distributions to Class A interests, Class B interests and incentive units are made in accordance with the Amended LLC Agreement, which are provided first to holders of Class A Units and then to Class B Units. Distributions to holders of incentive units are made upon the occurrence of each respective Incentive Unit Tier’s Payout as defined in the Amended and Restated LLC Agreement per each respective Incentive Unit Tier.

Once an Incentive Unit Tier’s Payout is achieved, the holders of that Incentive Unit Tier’s units receive a pro rata percentage of the distribution according to their ownership percentage. The overall amount of distribution allocated to each Incentive Unit Tier is subject to a predetermined percentage, as outlined in the Amended and Restated LLC Agreement. For the years ended December 31, 2023 and 2022, INR Holdings has not paid any distributions to holders of the Class A interests, the Class B interests, or the Incentive Units.

Dividends

INR Holdings did not declare or pay any dividends during the years ended December 31, 2023 and 2022.

Note 12—Supplemental Cash Flow Information

The following table provides additional information concerning non-cash activities and cash paid for interest, net of amounts capitalized, for the years ended December 31, 2023 and 2022:

	For the Year Ended December 31,
	2023			2022
(in thousands)
Supplemental disclosure of non-cash transactions:
Adjustment required upon adoption of ASC 842	$	—		$	652
Right-of-use assets and lease liabilities incurred		18			249
Additions of asset retirement obligations		34			27
Assumed asset retirement obligations in acquisitions		150			—
Revisions of asset retirement obligations		(44	)		18
Property and equipment financed through notes payable		139			251
Additions to oil and natural gas properties included in accounts payable		25,453			32,190
Additions to other property and equipment included in accounts payable		831			5,312
Supplemental disclosure of cash flow information:
Interest paid	$	10,136		$	2,181

F-47

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

Note 13—Commitments and Contingencies

South Bend Utica Farmout Agreement

On March 2, 2018, INR Holdings entered into an Exploration and Development Agreement and Farm Out Agreement (collectively, the “South Bend Utica Development Agreements”) with Dominion Energy Transmission, Inc. (“Dominion”) covering approximately 11,000 acres in Armstrong and Indiana Counties, Pennsylvania targeting the Utica Shale horizon.

Pursuant to the Utica Development Agreements, INR Holdings obtained approximately 90% participating interest in the acreage with South Bend Investments, LP owning the remaining 10%. Subsequent to the execution of the agreement, INR Holdings exchanged 10% of its interest to Chase Oil Company (“Chase”) in exchange for 100% of Chase’s interest in INR Holdings’ West Summit field in southern Fayette County, Pennsylvania.

In April 2022, INR Holdings and Chase collectively acquired South Bend Investments’ interest in the Marcellus and Utica horizons at the South Bend Field for $0.5 million, increasing our working interest on those parcels to 85%.

The Utica Development Agreements had an initial term of 15 years and require the drilling of one (1) seven thousand foot lateral into the Utica formation. As of December 31, 2023, INR Holdings had yet to satisfy that obligation and has approximately 10 years remaining to meet its obligation.

Firm Transportation

INR Holdings has commitments for firm transportation under existing contracts with Eastern Gas Transmission Services (“EGTS”) to move volumes at South Bend. The terms of the agreement supported 27,500 decatherm per day through March 2024. Future payments under these contracts as of December 31, 2023 totaled $0.3 million.

Drilling Rig Service Commitments

We entered into a drilling contract with Patterson-UTI Energy, Inc. (“Patterson”) in September 2023 to drill seven (7) horizontal laterals. Future payments under this contract totaled $3.2 million, which represent the gross amounts that INR Holdings is committed to pay without regard to our proportionate share based on our working interest in each of the wells to be drilled.

As of December 31, 2023, INR Holdings had drilled three (3) wells associated with this drilling contract.

Lease Commitments

Refer to Note 6 – Leases for details on INR Holdings’ operating lease agreements. We do not have any finance lease obligations.

Litigation

From time to time, INR Holdings is party to various legal and/or regulatory proceedings arising in the ordinary course of business. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that all such matters are without merit and involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material effect on our financial condition, results of operations or cash flows.

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

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. INR Holdings discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.

Note 14—Subsequent Events

INR Holdings has evaluated subsequent events through July 22, 2024, the date on which the consolidated financial statements were available to be issued, noting the following relevant transactions.

Additional Class B Interests Issuance

In March 2024, we issued an additional $0.5 million of Class B interests upon the hiring of our Vice President of Corporate Development and Strategy.

Acquisition of Leasehold within Salt Fork State Park

On February 26, 2024, INR Holdings was awarded approximately 5,705 net acres within Salt Fork State Park by the Ohio Oil and Gas Management Commission for $58.5 million or approximately $10,250 per acre. We closed on the acquisition of the parcels during July 2024.

Note 15—Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)

Capitalized Costs

The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion, and amortization are shown below:

	December 31,
	2023			2022
(in thousands)
Proved properties(1)	$	615,456		$	191,887
Unproved properties		37,189			40,718
Total proved and unproved properties		652,645			232,605
Accumulated depreciation, depletion, and amortization		(77,085	)		(25,010	)
Net capitalized costs	$	575,560		$	207,595

¹  Includes asset retirement costs of $0.8 million and $0.6 million as of December 31, 2023 and 2022, respectively.

F-49

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

Costs Incurred for Oil and Natural Gas Producing Activities

Our capital costs incurred for acquisition and development activities are shown below:

	December 31,
	2023		2022
(in thousands)
Acquisition costs:
Proved properties	$	274,732	$	2,066
Unproved properties		1,047		—
Development costs		144,121		108,544
Exploration costs		—		—
	$	419,900	$	110,610

Estimated Quantities of Proved Oil and Gas Reserves

The reserve estimates presented below and included herein conform to the definitions prescribed by the SEC. INR Holdings retained Wright & Co, Inc., an independent petroleum engineering firm, to prepare the estimates of all of its proved reserves as of December 31, 2023, 2022, and 2021 and their related pre-tax future net cash flows. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Reserve estimates are based on an unweighted arithmetic average of commodity prices during the 12-month period, using the closing prices on the first day of each month, as defined by the SEC.

F-50

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

As of December 31, 2023, all of INR Holdings’ oil and gas reserves are attributable to properties within the United States. The table below presents a summary of changes in quantities of proved oil and gas reserves in INR Holdings’ estimated proved reserves:

	Crude Oil (MBbls)			Natural Gas (MMcf)			Natural Gas Liquids (MBbls)			Total (MBoe)
Total proved reserves:
December 31, 2021		5,846			237,646			10,450			55,904
Extensions		1,574			160,098			3,999			32,256
Revisions to previous estimates		(867	)		(27,821	)		359			(5,145	)
Purchases of reserves in place		—			—			—			—
Production		(640	)		(11,585	)		(656	)		(3,227	)
December 31, 2022		5,913			358,338			14,152			79,788
Extensions		7,443			168,705			9,015			44,576
Revisions to previous estimates		252			(118,920	)		(4,501	)		(24,069	)
Purchases of reserves in place		18,636			128,110			8,207			48,194
Production		(1,205	)		(27,506	)		(1,112	)		(6,901	)
December 31, 2023		31,038			508,725			25,762			141,587
Proved developed reserves:
December 31, 2021		2,076			96,480			4,159			22,315
December 31, 2022		2,995			143,632			6,132			33,066
December 31, 2023		13,172			252,832			12,644			67,954
Proved undeveloped reserves:
December 31, 2021		3,770			141,166			6,291			33,589
December 31, 2022		2,918			214,706			8,020			46,723
December 31, 2023		17,866			255,893			13,118			73,633

Notable changes in proved reserves for the year ended December 31, 2022 for INR Holdings included the following:

• Extensions. In 2022, total extensions to previous estimates increased proved reserves by 32.3 MMBoe. These extensions primarily related to the addition of 13 PUD locations to be developed by 2027 (as that year entered the 5-year development window) which added 21.2 MMBoe of proved reserves. Other extensions included converting 11.0 MMBoe of unproved reserves to proved developed reserves by drilling five (5) wells during 2022, two of which were producing as of December 31, 2022. During 2022, our drilling program was focused on adding locations primarily in the various Utica / Point Pleasant formation in Ohio and the Marcellus shale formation in Pennsylvania.

• Revisions to previous estimates. In 2022, total revisions to previous estimates reduced proved reserves by 5.1 MMBoe. These downward revisions primarily consisted of 5.5 MMBoe of downward revisions to PUD reserves, which were comprised of downward revisions of 10.9 MMBoe in PUDs from 2021 to 2022 due to changes to our development plan that resulted in 11 PUD locations being reclassified as they were outside the 5 year development window while we perform further technical refinements and analysis to evaluate well spacing assumptions. These downward revisions were partially offset by upward revisions of 5.4 MMBoe due to well performance. Our proved developed producing properties had upward revisions of 0.4 MMBoe related to increases in commodity prices which impacted the estimated timing and performance of these wells.

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

Notable changes in proved reserves for the year ended December 31, 2023 included the following:

• Extensions. In 2023, total extensions to previous estimates increased proved reserves by 44.6 MMBoe. These extensions primarily related to the addition of 21 proved undeveloped (“PUD”) locations to be developed by 2028 (as that year entered the 5-year development window) which added 32.5 MMBoe of proved reserves. Other extensions included converting 12.0 MMBoe of unproved reserves to proved developed reserves by drilling six wells during 2023, two of which were producing as of December 31, 2023. During 2023, our drilling program was focused on adding locations primarily in the various Utica and Point Pleasant formations in Ohio and the Marcellus shale formation in Pennsylvania.

• Revisions to previous estimates. In 2023, total revisions to previous estimates reduced proved reserves by 24.1 MMBoe. These downward revisions primarily consisted of 20.8 MMBoe of revisions to PUD reserves, which were comprised of 1.2 MMBoe of positive revisions related to increases in working interest, increased lateral length, and improvement in type curve, offset by downward revisions of 0.9 MMBoe in PUDs from 2022 to 2023 due to decreases in prices during the year ended December 31, 2023, as well as downward revisions of 21.1 MMBoe due to changes to our development plan that resulted in 18 PUD locations being reclassified as they were outside the 5 year development window while the Company performs further technical refinements and analysis to evaluate well spacing assumptions. Additionally, our proved developed producing properties had downward revisions of 3.3 MMBoe related to decreases in commodity prices which impacted the estimated timing and performance of these wells.

• Purchases of reserves in place. In 2023, 48.2 MMBoe of proved reserves were added primarily from properties acquired in the Ohio Utica Acquisition on October 4, 2023, including 20.4 MMBoe of proved developed reserves and 27.8 of proved undeveloped locations.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows (the “Standardized Measure”) relating to proved oil and gas reserves has been prepared in accordance with FASB ASC Topic 932, Extractive Activities — Oil and Gas (“ASC 932”). Future cash inflows as of December 31, 2023 and 2022 have been computed by applying average fiscal year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month periods ended December 31, 2023 and 2022, respectively) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves, based on year-end costs and assuming the continuation of existing economic conditions. The Standardized Measure also includes costs for future dismantlement, abandonment, and rehabilitation obligations.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves.

Future net cash flows are discounted at a rate of 10% annually to derive the Standardized Measure. This calculation does not necessarily result in an estimate of the fair value of INR Holdings’ oil and gas properties.

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Consolidated Financial Statements

The following table presents INR Holdings’ Standardized Measure of discounted future net cash flows:

	December 31,
	2023			2022
(in thousands)
Future cash inflows	$	3,865,302		$	3,116,373
Future development costs(1)		(545,803	)		(273,522	)
Future production costs		(1,281,802	)		(535,779	)
Future net cash flows		2,037,697			2,307,072
Discounted future income tax expense		—			—
10% discount to reflect timing of cash flows		(1,099,313	)		(1,289,464	)
Standardized measure of discounted future net cash flows	$	938,384		$	1,017,607

(1) Future development costs include costs associated with the future abandonment of proved properties, including proved undeveloped locations.

The following summarizes the principal sources of change in the Standardized Measure of discounted future net cash flows and such changes have been computed in accordance with ASC 932:

	For the Year Ended December 31,
	2023			2022
(in thousands)
Standardized measure of discounted future net cash flows, beginning of period	$	1,017,607		$	327,139
Sales of oil, natural gas, NGLs, net of production costs		(109,179	)		(117,952	)
Purchases of minerals in place		534,927			—
Extensions, net of future development costs		199,378			422,418
Net change in price and production costs		(643,905	)		420,633
Previously estimated development costs incurred		68,412			15,659
Change in estimated future development costs		4,734			(13,664	)
Revisions of previous quantity estimates		(224,318	)		(40,869	)
Accretion of discount		101,761			32,714
Net change in income taxes		—			—
Net change in timing of production and other		(11,034	)		(28,470	)
Standardized measure of discounted future net cash flows, end of period	$	938,384		$	1,017,607

Future net revenues included in the Standardized Measure relating to proved oil and natural gas reserves incorporate weighted average sales prices (inclusive of adjustments for transportation, quality, and basis differentials) for each of the periods indicated below as follows:

	December 31,
	2023		2022
Oil (per Bbl)	$	73.73	$	88.67
Natural gas (per MMBtu)	$	1.739	$	5.606
NGL (per Bbl)	$	26.87	$	41.21

F-53

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(Unaudited)

(amounts in thousands)

	September 30, 2024			December 31, 2023
Assets
Current assets:
Cash and cash equivalents	$	1,565		$	1,504
Accounts receivable:
Oil and natural gas sales, net		21,559			23,491
Joint interest and other, net		28,203			20,605
Prepaid expenses and other current assets		9,767			2,354
Commodity derivative assets, short-term		8,329			22,054
Total current assets		69,423			70,008
Oil and natural gas properties, full cost method (including $96.7 million and 37.2 million excluded from amortization as of September 30, 2024 and December 31, 2023)		841,066			652,645
Other property and equipment		38,694			33,542
Less: Accumulated depreciation, depletion, and amortization		(135,887	)		(79,561	)
Property and equipment, net		743,873			606,626
Operating lease right-of-use assets, net		944			758
Other assets		8,971			4,944
Commodity derivative assets, long-term		2,164			6,173
Total assets	$	825,375		$	688,509
Liabilities and Members’ Equity
Current liabilities:
Accounts payable	$	31,152		$	37,737
Royalties payable		24,721			17,575
Accrued liabilities		24,399			1,015
Notes payable		114			124
Operating lease liabilities		206			105
Commodity derivative liabilities, short-term		2,536			6
Total current liabilities		83,128			56,562
Line-of-credit		224,746			170,964
Notes payable, long-term		70			153
Operating lease liabilities, net of current portion		738			652
Asset retirement obligations		1,088			970
Commodity derivative liabilities, long-term		1,846			752
Total liabilities		311,616			230,053
Commitments and contingencies (Note 11)
Members’ equity		513,759			458,456
Total liabilities and members’ equity	$	825,375		$	688,509

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

F-54

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(Unaudited)

(amounts in thousands)

	For the Nine Months Ended September 30,
	2024			2023
Revenues:
Oil, natural gas, and natural gas liquids sales	$	188,877		$	88,301
Midstream activities		1,032			1,672
Total revenues		189,909			89,973
Operating expenses:
Gathering, processing, and transportation		37,852			18,378
Lease operating		20,715			10,808
Production and ad valorem taxes		1,264			396
Depreciation, depletion, and amortization		56,344			29,289
General and administrative		8,268			3,472
Total operating expenses		124,443			62,343
Operating income		65,466			27,630
Other income (expense):
Interest, net		(16,263	)		(6,968	)
Gain on derivative instruments		6,397			5,220
Other (expense) income		(797	)		562
Net income	$	54,803		$	26,444

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

F-55

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Members’ Equity

(Unaudited)

(amounts in thousands)

	Class A		Class B			Total
Balance as of December 31, 2022	$	149,506	$	—		$	149,506
Contributions		—		22,969			22,969
Net income		29,636		(3,192	)		26,444
Balance as of September 30, 2023	$	179,142	$	19,777		$	198,919
Balance as of December 31, 2023	$	190,606	$	267,850		$	458,456
Contributions		—		500			500
Net income		15,801		39,002			54,803
Balance as of September 30, 2024	$	206,407	$	307,352		$	513,759

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

F-56

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(amounts in thousands)

	For the Nine Months Ended September 30,
	2024			2023
Cash flows from operating activities:
Net income	$	54,803		$	26,444
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		56,344			29,289
Amortization of debt issuance costs		1,430			279
Loss (gain) on derivative instruments		(6,397	)		(5,220	)
Cash received on settlement of derivative instruments		27,755			13,477
Non-cash lease expense		136			66
Changes in operating assets and liabilities:
Accounts receivable		(5,666	)		9,505
Prepaid expenses and other assets		264			22
Accounts payable		6,638			(3,075	)
Royalties payable		7,146			(2,153	)
Accrued and other expenses		4,860			4,716
Other assets and liabilities		253			(57	)
Net cash provided by operating activities		147,566			73,293
Cash flows from investing activities:
Additions to oil and gas properties		(189,569	)		(133,132	)
Additions to property and equipment		(5,186	)		(9,623	)
Net cash used in investing activities		(194,755	)		(142,755	)
Cash flows from financing activities:
Borrowings under revolving credit facility		366,855			121,364
Payments on revolving credit facility		(313,073	)		(51,300	)
Proceeds from contributions from issuance of Class B interests		500			22,969
Payments of debt issuance costs		(5,200	)		(483	)
Proceeds from notes payable		—			139
Payments of deferred offering costs		(1,739	)		—
Payments on notes payable		(93	)		(74	)
Net cash provided by financing activities		47,250			92,615
Net increase in cash and cash equivalents		61			23,153
Cash and cash equivalents at beginning of period		1,504			739
Cash and cash equivalents and restricted cash at end of period	$	1,565		$	23,892

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

F-57

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

Note 1 – Description of the Business and Basis of Presentation

Description of Business

Infinity Natural Resources, LLC, together with its subsidiaries (collectively referred to as “INR Holdings”) is an oil and natural gas exploration and production company engaged in the acquisition, exploration, and development of properties for the production of oil, natural gas, and natural gas liquids (“NGLs”) from underground reservoirs. INR Holdings was organized as a Delaware limited liability company (“LLC”) on June 6, 2017. Our operations are located in the Appalachian Basin in the northeastern United States.

Basis of Accounting and Presentation

The unaudited condensed consolidated financial statements present the financial position, results of operations, and cash flows of INR Holdings in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). All intercompany balances and transactions are eliminated upon consolidation.

The accompanying unaudited condensed consolidated financial statements and notes should be read in conjunction with the audited financial statements and notes contained in INR Holdings’ 2023 audited consolidated financial statements, which contain a summary of INR Holdings’ significant accounting policies and other disclosures. Certain information and disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted, although INR Holdings believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, the financial statements include all adjustments, which consist of normal recurring adjustments unless otherwise disclosed, necessary to fairly state the unaudited condensed consolidated financial statements.

Note 2 – Summary of Significant Accounting Policies

Use of Estimates

The preparation of unaudited condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported revenues and expenses during the reporting periods, and the disclosure of contingent assets and liabilities at the date of the unaudited condensed consolidated financial statements. Actual results could differ from those estimates. Estimates of reserves are used to determine depletion and to conduct impairment analysis. Estimating reserves is inherently uncertain, including the projection of future rates of production and the timing of development expenditures.

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry, given the challenges resulting from volatility in oil and natural gas prices. For instance, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, recent measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of these events and changing market conditions. Such circumstances generally increase the uncertainty in INR Holdings’ accounting estimates, particularly those involving financial forecasts.

INR Holdings evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from INR Holdings’ estimates. Any effects on INR Holdings’ business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

F-58

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

Accounts Receivable and Allowance for Expected Credit Losses

As of September 30, 2024 and December 31, 2023, INR Holdings’ allowances for credit losses were not material and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of our counterparties.

Deferred Offering Costs

On May 15, 2024, INR Holdings formed Infinity Natural Resources, Inc. (“Infinity”), a Delaware corporation, in anticipation of a potential initial public offering (“IPO”) and related reorganization transactions. Following the IPO and the transactions related thereto, Infinity will be a holding company whose sole material asset will consist of membership interests in INR Holdings.

Accordingly, INR Holdings has incurred direct incremental costs during the nine months ended September 30, 2024, related to the IPO which primarily consist of legal, accounting, and other fees and expenses. These costs are capitalized as of September 30, 2024, and will be offset against the IPO proceeds received. In the event the potential IPO is not consummated, any deferred offering costs that are capitalized as of that date will be immediately expensed. Deferred offering costs of $7.7 million were included within prepaid expenses and other current assets on the unaudited balance sheet as of September 30, 2024. INR Holdings did not have any deferred offering costs recorded as of December 31, 2023.

Concentrations of Credit Risk

We are exposed to credit risk in the event of nonpayment by counterparties. We sell production to a relatively small number of customers, as is customary in our business. The table below summarizes the purchasers that accounted for 10% or more of INR Holdings’ total revenues from the sale of commodities for the periods presented:

	For the Nine Months Ended September 30,
	2024			2023
Marathon Oil Company		56	%		47	%
BP America		16	%		37	%
Blue Racer Midstream		10	%		16	%

During these periods, no other purchaser accounted for 10% or more of INR Holdings’ total commodity sales revenues. As of September 30, 2024, INR Holdings’ accounts receivable balance related to oil and gas sales was comprised of amounts due from various purchasers, including amounts due from Marathon Oil Company and BP America comprising 47%, and 14%, respectively, of the total balance. As of December 31, 2023, INR Holding’ accounts receivable balance related to oil and gas sales was comprised of amounts due from Marathon Oil Company and BP America, which accounted for 56% and 24%, respectively, of the total balance.

The loss of any one or more of INR Holdings’ major purchasers could materially and adversely affect our revenues in the short-term. However, based on the demand for oil and natural gas and the availability of other purchasers, INR Holdings believes that the loss of any major purchaser would not have a material adverse effect on its financial condition and results of operations as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

By using derivative instruments to economically hedge exposures to changes in commodity prices, INR Holdings also exposes itself to credit risk. When the fair value of a derivative contract is positive, the counterparty owes INR Holdings, which creates credit risk. We minimize the credit risk in derivative instruments

F-59

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

by: (i) limiting our exposure to any single counterparty; and (ii) only entering into hedging arrangements with counterparties that are also participants in our credit agreement, all of which have investment-grade credit ratings.

Oil and Gas Properties

INR Holdings uses the full cost method of accounting for its oil and natural gas properties. Accordingly, all costs directly associated with the acquisition, exploration, and development of oil, natural gas, and NGL reserves for both productive and nonproductive properties are capitalized into a full cost pool. Capitalized costs also include the costs of unproved properties and internal costs directly related to INR Holdings’ acquisition, exploration, and development activities. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Capitalized costs of proved properties is 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.

Reportable Segment

INR Holdings operates in only one reportable segment that is the exploration and production segment. All of our operations are conducted in one geographic area within the Appalachian Basin, primarily in Pennsylvania and Ohio, in the United States.

Accounting Standards Not Yet Adopted

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures (“ASU 2023-07”), which updates reportable segment disclosure requirements primarily by enhancing disclosures about significant segment expenses and information used to assess segment performance. Additionally, ASU 2023-07 enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss and provides new segment disclosure requirements for entities with a single reportable segment. The amendments are effective for annual periods beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. Management is currently evaluating this ASU to determine its impact on INR Holdings’ disclosures. Adoption of the update is not expected to have a material impact to INR Holdings’ financial position, results of operations or liquidity.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740) – Improvements to Income Tax Disclosures (“ASU 2023-09”), which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated and provides additional requirements regarding income taxes paid. The amendments are effective for public business entities for annual periods beginning after December 15, 2024, and for entities other than public business entities for annual periods beginning after December 15, 2025. Early adoption is permitted. The amendments may be applied either prospectively or retrospectively. As an emerging growth company, we are choosing to take advantage of the extended transition period pursuant to Section 107 of the Jumpstart Our Business Startups (“JOBS”) Act, such that we expect to adopt the amendments for our annual period ending December 31, 2026, based on the adoption date for entities other than public business entities. Management is currently evaluating this ASU to determine its impact on INR Holdings’ disclosures. Adoption of the update is not expected to have a material impact to INR Holdings’ financial position, results of operations or liquidity.

F-60

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

We considered the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or not material upon adoption.

Note 3 – Revenues

Crude oil, natural gas and NGL sales are recognized at the point that control of the product is transferred to the customer. Virtually all of INR Holdings’ contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials.

Commodity sales revenues presented within the unaudited condensed consolidated statements of operations relate to the sale of oil, natural gas, and NGLs as shown below:

	For the Nine Months Ended September 30,
	2024		2023
(in thousands)
Oil revenues	$	121,570	$	41,188
Natural gas revenues		35,874		33,061
Natural gas liquids revenues		31,433		14,052
Oil, natural gas, and natural gas liquids sales	$	188,877	$	88,301

Oil Sales

Our crude oil sales contracts are generally structured whereby oil is delivered to the customer at a contractually agreed-upon delivery point. This delivery point is usually at the wellhead or at the inlet of a transportation pipeline. Revenue is recognized when control transfers to the customer at the delivery point based on the net price received from the customer. Any downstream transportation or marketing costs incurred by purchasers of our crude oil are reflected in the price we receive and are presented as a net reduction to oil sales revenues.

Natural Gas and NGL Sales

Under INR Holdings’ 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 INR Holdings. For these contracts, INR Holdings evaluates when control of the residue gas and NGLs is transferred in order to determine whether revenues should be recognized on a gross or net basis. Where INR Holdings elects to take its residue gas and/or NGL production “in-kind” at the plant tailgate, fees incurred prior to transfer of control at the outlet of the plant are presented as gathering, processing, and transportation expense within the unaudited condensed consolidated statements of operations. Where INR Holdings does not take its residue gas and/or NGL production “in-kind”, transfer of control typically occurs at the inlet of the midstream entity’s gas gathering system such that any fees incurred subsequent to the delivery point are reflected as a net reduction to natural gas and NGL revenues presented in the table above and as included within oil, natural gas, and natural gas liquids sales within the unaudited condensed consolidated statements of operations.

Performance Obligations

INR Holdings’ commodity sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations

F-61

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

under any of its commodity sales contracts. Under our revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

For all commodity products, we record revenue in the month production is delivered to the purchaser. Settlement statements for crude oil are generally received within 30 days following the date that production volumes are delivered, but for natural gas and NGL sales, statements may not be received for 30 to 60 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At such time, the volumes delivered and sales prices can be reasonably estimated and amounts due from customers are accrued in Accounts receivable – oil and natural gas sales, net in the unaudited condensed consolidated balance sheets. As of September 30, 2024 and December 31, 2023, such receivable balances were $21.6 million and $23.5 million, respectively.

Note 4 – Property, Plant, and Equipment

Oil and Natural Gas Properties

We utilize the full cost method of accounting for costs related to the exploration, development, and acquisition of oil and natural gas properties. Our capitalized costs of oil and natural gas properties and the related accumulated depreciation, depletion, and amortization as of September 30, 2024 and December 31, 2023 are as follows:

	September 30, 2024			December 31, 2023
(in thousands)
Oil and natural gas properties:
Proved properties	$	744,365		$	615,456
Unproved properties		96,701			37,189
Gross oil and natural gas properties		841,066			652,645
Less: accumulated depreciation, depletion, and amortization		(131,746	)		(77,085	)
Oil and natural gas properties, net	$	709,320		$	575,560

In July 2024 we closed on an acquisition of parcels within Salt Fork State Park for $58.5 million currently represented in our unproved properties balance as of September 30, 2024.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the Company’s oil and natural gas properties. At September 30, 2024 and 2023, the net book value of the Company’s oil and gas properties was below the calculated ceiling. As a result, the Company did not record an impairment of its oil and natural gas properties for the nine months ended September 30, 2024 or 2023. We recorded $54.7 million and $28.0 million of amortization expense on our oil and gas properties for the nine months ended September 30, 2024, and 2023, respectively. The average depletion rate of our oil and natural gas properties was $8.12 per Boe and $6.40 per Boe for the nine months ended September 30, 2024 and 2023, respectively.

Certain general and administrative costs are capitalized to the full cost pool and represent management’s estimate of costs incurred directly related to exploration and development activities. All general and administrative costs not capitalized are charged to expense as they are incurred. We capitalized internal costs of approximately $4.4 million and $1.9 million for the nine months ended September 30, 2024 and 2023, respectively.

F-62

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

We evaluate costs excluded from its amortization calculation at least annually. Individually insignificant unevaluated properties are grouped for evaluation and periodically transferred to evaluated properties over a timeframe consistent with their expected development schedule.

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.

	September 30, 2024			December 31, 2023
(in thousands)
Midstream assets	$	35,923		$	31,338
Vehicles		1,660			1,392
Furniture, fixtures, and office equipment		515			260
Leasehold improvements		596			552
Less: Accumulated depreciation		(4,141	)		(2,476	)
Total other property and equipment, net	$	34,553		$	31,066

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 INR Holdings’ 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 nine months ended September 30, 2024 and 2023. Total depreciation expense for the nine months ended September 30, 2024 and 2023 totaled approximately $1.7 million and $1.2 million, respectively.

Note 5 – Accrued Liabilities

INR Holdings’ accrued liabilities as of September 30, 2024 and December 31, 2023 consisted of the following amounts:

	September 30, 2024		December 31, 2023
(in thousands)
Accrued interest expense	$	$337	$	396
Accrued capital expenditures		13,449		—
Accrued lease operating expenses		935		—
Accrued offering costs		5,168		—
Accrued general and administrative expenses		771		—
Accrued severance and ad valorem taxes		998		619
Other accrued liabilities		2,538		—
Other accrued liabilities		203		—
Total accrued liabilities	$	24,399	$	1,015

F-63

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

Note 6 - Debt

Amended and Restated Credit Facility

On September 25, 2024, INR Holdings entered into an Amended and Restated Credit Facility with a syndicate of financial institutions. Borrowings under the credit facility are subject to borrowing base limitations based upon the discounted net present value of our oil and gas properties and are subject to semi-annual redeterminations. The credit facility is guaranteed by our subsidiaries and is secured by first priority security interests on substantially all of our consolidated assets, including a mortgage on at least 85% of the total value of the proved properties evaluated in the most recently delivered reserve report, including any engineering report relating to the crude oil and natural gas properties of our restricted domestic subsidiaries, subject to customary exceptions.

Borrowings under the Amended and Restated Credit Facility may be base rate loans or Secured Overnight Financing Rate (“SOFR”) loans. Base rate loans bear interest at a rate per annum equal to the greater of: (i) the administrative agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted Term SOFR rate (as defined in the Amended and Restated Credit Facility agreement) for a one-month interest period plus 100 basis points, plus an applicable margin, depending on the percentage of the borrowing base utilized, plus an additional basis point credit spread. SOFR loans bear interest at SOFR plus an applicable margin, depending on the percentage of the borrowing base utilized, plus an additional basis point credit spread. We also pay a commitment fee on unused elected commitment amounts under our credit facility, which is also dependent on the percentage of the borrowing base utilized. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. The Amended and Restated Credit Facility matures in September 2028. As of September 30, 2024, INR Holdings’ reserves supported a $325.0 million credit facility of which $224.7 million was outstanding leaving $100.3 million of unused capacity.

For the nine months ended September 30, 2024 and 2023, total interest expense on our credit facility was $14.8 million and $6.7 million, respectively. We did not capitalize any interest expense for the nine months ended September 30, 2024 and 2023. For the nine months ended September 30, 2024 and 2023, INR Holdings’ weighted-average interest rate was 9.1% and 9.1%, respectively.

Debt issuance costs associated with our credit facility are capitalized and presented as other assets within the unaudited condensed consolidated balance sheets. Because debt issuance costs are related to a line of credit, they are presented as an asset, rather than an offset to the corresponding liability. Debt issuance costs are amortized using the straight-line method over the term of the related agreement. We capitalized additional debt issuance costs related to the Amended and Restated Credit Facility of $5.8 million and expensed $0.3 million of previous capitalized debt issuance costs related to the extinguishment of the prior credit facility. Capitalized debt issuance costs were approximately $8.4 million and $4.7 million as of September 30, 2024, and December 31, 2023, respectively. Amortization of debt issuance costs, which is included within interest expense in the unaudited condensed consolidated statements of operations, was approximately $1.8 million and $0.3 million for the nine months ended September 30, 2024 and 2023, respectively.

The Amended and Restated Credit Facility also requires INR Holdings to maintain compliance with financial ratios including a current ratio of not less than 1.0 to 1.0 and a leverage ratio no greater than 3.0 to 1.0, each of which is defined within the terms of the Amended and Restated Credit Agreement. INR Holdings is in compliance with the covenants and financial ratios under the Amended and Restated Credit Facility described above through the date these unaudited condensed consolidated financial statements were available to be issued.

Note 7 – Derivatives and Risk Management

We are exposed to volatility in market prices and basis differentials for oil, natural gas, and NGLs, which impacts the predictability of our cash flows related to the sale of those commodities. The overall objective of our

F-64

INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices, which we do by using various derivative instruments including fixed price swaps, basis swaps, and collars. As a result of our hedging activities, we may realize prices that are greater or less than the market prices that we would have otherwise received.

We typically enter into over the counter (OTC) derivative contracts with financial institutions and regularly monitor the creditworthiness of all counterparties. Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our revolving credit facility. As of September 30, 2024, we did not have any cash or letters of credit posted as collateral for our derivative financial instruments.

We do not designate any of our derivative instruments as cash flow hedges; therefore, all changes in fair value of our derivative instruments are recognized in other income within the unaudited condensed consolidated statements of operations. We recognize all derivative instruments as either assets or liabilities at fair value within the unaudited condensed 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 INR Holdings 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 INR Holdings’ derivative financial instruments. The tables present the notional amount, the weighted average contract prices and the fair values by expected maturity dates as of September 30, 2024.

	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Oil	(in MBbls)		($ per Bbl)		(in thousands)
Fixed price swaps
2024		349	$	73.97	$	2,127
2025		1,383	$	71.81		6,761
2026		519	$	69.58		1,863
2027		35	$	68.04		85
Total		2,286			$	10,836

	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Natural gas	(in MMBtu)		($ per MMBtu)		(in thousands)
Fixed price swaps
2024		1,605	$	3.84	$	1,464
2025		28,452	$	3.47		4,598
2026		23,356	$	3.69		958
2027		3,663	$	4.18		150
Total		57,076			$	7,170

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

	Volume		Basis Differential			Fair Value as of September 30, 2024
Natural gas	(in MMBtu)		($ per MMBtu)			(in thousands)
Basis swaps
2024		5,741	$	(1.34	)	$	(2,100	)
2025		30,529	$	(1.04	)		(6,583	)
2026		20,098	$	(1.06	)		(2,225	)
2027		1,239	$	(1.03	)		(141	)
Total		57,607				$	(11,048	)

	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Ethane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		2,546,800	$	0.24	$	56
2025		12,133,000	$	0.25		281
2026		6,063,500	$	0.28		135
2027		435,000	$	0.30		15
Total		21,178,300			$	487

	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Propane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		3,780,200	$	0.75	$	57
2025		17,764,200	$	0.72		(257	)
2026		8,080,500	$	0.70		5
2027		577,000	$	0.72		10
Total		30,201,900			$	(185	)

	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Isobutane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		841,400	$	0.93	$	(122	)
2025		3,755,600	$	0.87		(410	)
2026		1,667,500	$	0.83		(94	)
2027		114,000	$	0.82		(6	)
Total		6,378,500			$	(633	)

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Normal butane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		1,246,400	$	0.88	$	(204	)
2025		5,869,500	$	0.83		(480	)
2026		2,686,000	$	0.81		(62	)
2027		192,000	$	0.81		(2	)
Total		9,993,900			$	(749	)

	Volume		Weighted Average Price		Fair Value as of September 30, 2024
Pentane	(in gallons)		($ per gallon)		(in thousands)
Fixed price swaps
2024		1,078,000	$	1.46	$	29
2025		4,818,600	$	1.42		89
2026		2,168,500	$	1.38		107
2027		149,000	$	1.35		7
Total		8,214,100			$	232

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 unaudited condensed balance sheets.

The following table summarizes the gross fair value of our derivative assets and liabilities and the effect of netting as of September 30, 2024 and December 31, 2023:

	September 30, 2024
Balance Sheet Classification	Gross Amounts		Netting Adjustment			Net Amounts Presented on Balance Sheet
(in thousands)
Assets
Commodity derivative assets, short-term	$	15,148	$	(6,819	)	$	8,329
Commodity derivative assets, long-term		5,602		(3,438	)		2,164
Total assets	$	20,750	$	(10,257	)	$	10,493
Liabilities
Commodity derivative liabilities, short-term	$	9,355	$	(6,819	)	$	2,536
Commodity derivative liabilities, long-term		5,284		(3,438	)		1,846
Total liabilities	$	14,640	$	(10,257	)	$	4,383

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

	December 31, 2023
Balance Sheet Classification	Gross Amounts		Netting Adjustment			Net Amounts Presented on Balance Sheet
(in thousands)
Assets
Commodity derivative assets, short-term	$	26,176	$	(4,122	)	$	22,054
Commodity derivative assets, long-term		8,046		(1,873	)		6,173
Total assets	$	34,222	$	(5,995	)	$	28,227
Liabilities
Commodity derivative liabilities, short-term	$	4,128	$	(4,122	)	$	6
Commodity derivative liabilities, long-term		2,625		(1,873	)		752
Total liabilities	$	6,753	$	(5,995	)	$	758

Our total derivative gains and losses for the nine months ended September 30, 2024 and 2023 were as follows:

	For the Nine Months Ended September 30,
	2024			2023
(in thousands)
Realized gain on derivative instruments	$	27,755		$	13,477
Unrealized (loss) gain on derivative instruments		(21,358	)		(8,257	)
Total (loss) gain on derivative instruments	$	6,397		$	5,220

Note 8 – Fair Value Measurements

Certain of INR Holdings’ assets and liabilities are measured at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.

The carrying values of cash and cash equivalents, including accounts receivable, other current assets, accounts payable and other current liabilities on the unaudited condensed consolidated balance sheets approximate fair value because of their short-term nature. Additionally, the carrying value of outstanding borrowings under our revolving credit facility approximates fair value because the interest rates are variable and reflective of market rates. We consider the fair value of our revolving credit facility to be a Level 2 measurement on the fair value hierarchy, as discussed further below. The carrying value of borrowings under our revolving credit facility approximate fair value as interest rates applicable to our borrowings outstanding are based on prevailing market rates.

We follow ASC Topic 820, Fair Value Measurement (“ASC 820”), which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

• Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

• Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets (other than quoted prices included within Level 1), and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

• Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable but should reflect the assumptions that market participants would use when pricing the asset or liability, including assumptions about risk (consistent with the fair value measurement objective).

Recurring Fair Value Measurements

The following table presents, for each applicable level within the fair value hierarchy, INR Holdings’ net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis.

	September 30, 2024
	Level 1		Level 2			Level 3		Fair Value
(in thousands)
Assets
Fixed price swaps	$	—	$	18,724		$	—	$	18,724
Basis swaps		—		—			—		—
Liabilities
Fixed price swaps		—		(1,566	)		—		(1,566	)
Basis swaps		—		(11,048	)		—		(11,048	)
Total	$	—	$	6,110		$	—	$	6,110

	December 31, 2023
	Level 1		Level 2			Level 3		Fair Value
(in thousands)
Assets
Fixed price swaps	$	—	$	31,047		$	—	$	31,047
Basis swaps		—		—			—		—
Liabilities
Fixed price swaps		—		(742	)		—		(742	)
Basis swaps		—		(2,836	)		—		(2,836	)
Total	$	—	$	27,469		$	—	$	27,469

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. INR Holdings 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.

Nonrecurring Fair Value Measurements

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include asset retirement obligations when incurred and other long-lived assets that

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

are written down to fair value when they are impaired. INR Holdings did not record any impairment charge related to these assets and liabilities for the nine months ended September 30, 2024 and 2023.

Note 9 – Members’ Equity

On June 6, 2017, holders of INR Holdings’ equity interests approved the LLC Agreement to, among other things, authorize the issuance of approximately $102.7 million of Class A interests. Subsequently INR Holdings received $90.3 million of contributions in exchange for Class A interests, with the additional contributions received through 2021 up to the total commitment amount of $102.7 million.

On August 4, 2023, holders of INR Holdings’ Class A interests approved the Amended and Restated LLC Agreement to, among other things, authorize the issuance of approximately $23.0 million of Class B interests upon the signing of the purchase and sale agreement for the Ohio Utica Acquisition. The Amended and Restated LLC Agreement became effective on October 4, 2023. Upon the closing of the Ohio Utica Acquisition, INR Holdings issued an additional $199.3 million of Class B interests, the proceeds of which were used to fund a portion of the purchase consideration for the Ohio Utica Acquisition. In March 2024, we issued an additional $0.5 million of Class B interests.

INR Holdings is managed by a board of managers comprised of seven managers including two managers that are executives of INR Holdings, four managers that are representatives of Pearl Energy Investment Management, LLC, and one manager that is a representative of NGP Energy Capital Management, L.L.C. Each manager has one vote on any company matter decided by vote and each matter requires a majority vote, with the exception of the removal of any manager which requires a super majority. As of September 30, 2024, affiliates of Pearl Energy Investment Management, LLC and NGP XI US Holdings, L.P., an affiliate of NGP Energy Capital Management, L.L.C., owned 73.6% and 24.5 %, respectively, of our Class A and Class B interests.

Profits and losses for both Class A and Class B interests are determined and allocated among each equity interest holder in a manner such that the adjusted capital account of each equity interest holder is as nearly as possible equal to the distributions that would be made to such equity interest holder if certain transactions occur based on each equity interest holders proportionate ownership interest in INR Holdings.

In connection with the issuance of the Class A and Class B interests, pursuant to the LLC Agreement, INR Holdings also issued non-voting, performance-based incentive units to certain members of management. The incentive units contain one or more performance-based vesting conditions. INR Holdings determined that the grant date fair value was not material as it relates to the incentive units issued in conjunction with the issuance of the Class A interests in 2017. Further, while the Class B interests were issued in October 2023, the corresponding incentive units were not considered issued until January 1, 2024 given that the awards had not been granted from an accounting perspective prior to such date. Based on the assessment of the underlying performance condition as not being probable on the grant date, INR Holdings determined that the grant date fair value on January 1, 2024, and corresponding compensation expense for the nine months ended September 30, 2024, were not material

Distributions to Class A interests, Class B interests and incentive units are made in accordance with the Amended LLC Agreement, which are provided first to holders of Class A Units and then to Class B Units. Distributions to holders of Incentive Units are made upon the occurrence of each respective incentive unit Tier’s Payout as defined in the Amended and Restated LLC Agreement per each respective Incentive Unit Tier.

Once an Incentive Unit Tier’s Payout is achieved, the holders of that Incentive Unit Tier’s units receive a pro rata percentage of the distribution according to their ownership percentage. The overall amount of distribution allocated to each Incentive Unit Tier is subject to a predetermined percentage, as outlined in the

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

Amended and Restated LLC Agreement. For the nine months ended September 30, 2024 and 2023, INR Holdings has not paid any distributions to holders of the Class A interests, the Class B interests, or the Incentive Units.

Dividends

INR Holdings did not declare or pay any dividends during the nine months ended September 30, 2024 and 2023.

Note 10 – Supplemental Cash Flow Information

The following table provides additional information concerning non-cash activities and cash paid for interest, net of amounts capitalized, for the nine months ended September 30, 2024 and 2023:

	For the Nine Months Ended September 30,
	2024		2023
(in thousands)
Supplemental disclosure of non-cash transactions:
Right-of-use assets and lease liabilities incurred	$	322	$	19
Additions and revisions of asset retirement obligations		54		17
Additions to deferred offering costs included in accounts payable and accrued liabilities		5,938		—
Additions to oil and natural gas properties included in accounts payable and accrued liabilities		24,377		19,787
Additions to other property and equipment included in accounts payable and accrued liabilities		625		262
Debt issuance costs in accrued liabilities		645		—
Supplemental disclosure of cash flow information:
Interest paid	$	14,804	$	5,523

Note 11 – Commitments and Contingencies

South Bend Utica Farmout Agreement

On March 2, 2018, INR Holdings entered into an Exploration and Development Agreement and Farm Out Agreement (collectively, the “South Bend Utica Development Agreements”) with Dominion Energy Transmission, Inc. (“Dominion”) covering approximately 11,000 acres in Armstrong and Indiana Counties, Pennsylvania targeting the Utica Shale horizon.

Pursuant to the Utica Development Agreements, INR Holdings obtained approximately 90% participating interest in the acreage with South Bend Investments, LP owning the remaining 10%. Subsequent to the execution of the agreement, INR Holdings exchanged 10% of its interest to Chase Oil Company (“Chase”) in exchange for 100% of Chase’s interest in INR Holdings’ West Summit field in southern Fayette County, Pennsylvania.

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INFINITY NATURAL RESOURCES, LLC AND SUBSIDIARIES

Notes To Condensed Consolidated Financial Statements (Unaudited)

In April 2022, INR Holdings and Chase collectively acquired South Bend Investments’ interest in the Marcellus and Utica horizons at the South Bend Field for $0.5 million, increasing our working interest on those parcels to 85%.

The Utica Development Agreements had an initial term of 15 years and require the drilling of one (1) seven thousand foot lateral into the Utica formation. As of September 30, 2024, INR Holdings had yet to satisfy that obligation and has approximately 10 years remaining to meet its obligation.

Drilling Rig Service Commitments

We entered into a drilling contract with Patterson-UTI Energy, Inc. (“Patterson”) in September 2023 to drill seven (7) horizontal laterals. In the event that we did not drill the wells, INR would have a minimum payment of $3.2 million. The estimated minimum payment amounts represent the gross amounts that INR Holdings is committed to pay without regard to our proportionate share based on our working interest in each of the wells drilled or to be drilled under the contract. As of September 30, 2024, INR has drilled seven (7) wells satisfying the September 2023 drilling contract. During the first nine months ended September 30, 2024, we entered into an amendment to the September 2023 drilling contract to provide INR the ability drill six (6) additional wells for which the minimum total payments were expected to be $2.7 million. As of September 30, 2024, INR has drilled six (6) wells satisfying the amendment to the September 2023 drilling contract. In August 2024, INR entered into a second amendment to our September 2023 drilling contract to drill nine (9) horizontal laterals. In the event that INR elected to not drill any wells under that amendment, INR would have a minimum payment of $4.1 million.

Lease Commitments

Refer to Note 6 – Leases of the Company’s 2023 audited consolidated financial statements for details of INR Holdings’ operating lease agreements. INR Holdings does not have any finance lease obligations.

Litigation

From time to time, INR Holdings 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, INR Holdings believes that all such matters are without merit and involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material effect on our financial condition, results of operations or cash flows.

When it is determined that a loss is probable of occurring and is reasonably estimable, INR Holdings accrues an undiscounted liability for such contingencies based on our best estimate using information available at the time. INR Holdings discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.

Note 12 – Subsequent Events

INR Holdings has evaluated subsequent events through November 26, 2024, the date on which these unaudited condensed consolidated financial statements were available to be issued.

F-72

INDEPENDENT AUDITORS’ REPORT

To the Members of

Utica Resource Ventures, LLC

Opinion

We have audited the accompanying consolidated financial statements of Utica Resource Ventures, LLC (a Delaware Limited Liability Company) (the “Company”), which comprise the consolidated balance sheets as of December 31, 2022 and 2021, and the related consolidated statements of income and comprehensive income, changes in members’ equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of operations and cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Basis of Opinion

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Our responsibilities under those standards are further described in the Auditors’ Responsibilities for the Audit of the Consolidated Financial Statements section of our report. We are required to be independent of Utica Resource Ventures, LLC and to meet our other ethical responsibilities in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Responsibilities of Management for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the consolidated financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about Utica Resource Ventures, LLC’s ability to continue as a going concern within one year after the date that the consolidated financial statements are available to be issued.

Auditors’ Responsibilities for the Audit of the Consolidated Financial Statements

Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with generally accepted auditing standards will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional

F-73

omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the consolidated financial statements.

In performing an audit in accordance with generally accepted auditing standards, we:

• Exercise professional judgment and maintain professional skepticism throughout the audit.

• Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.

• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Utica Resource Ventures, LLC’s internal control. Accordingly, no such opinion is expressed.

• Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the consolidated financial statements.

• Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about Utica Resource Ventures, LLC’s ability to continue as a going concern for a reasonable period of time.

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control related matters that we identified during the audit.

Report on Supplementary Information

Our audit was conducted for the purpose of forming an opinion on the financial statements as a whole. The supplemental information is presented for purposes of additional analysis and is not a required part of the financial statements. Such information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the financial statements. The information has been subjected to the auditing procedures applied in the audit of the financial statements and certain additional procedures, including comparing and reconciling such information directly to the underlying accounting and other records used to prepare the financial statements or to the financial statements themselves, and other additional procedures in accordance with auditing standards generally accepted in the United States of America. In our opinion, the information is fairly stated in all material respects in relation to the financial statements as a whole.

/s/ Huselton, Morgan and Maultsby

Dallas, Texas

March 13, 2023, except for our report on supplementary information for which the date is August 5, 2024

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UTICA RESOURCE VENTURES, LLC

CONSOLIDATED BALANCE SHEETS

Years Ended December 31, 2022 and 2021

ASSETS
	2022			2021
Current assets:
Cash and equivalents	$	2,210,158		$	4,424,296
Accounts receivable		7,361,050			4,194,024
Accrued revenue		5,322,048			2,838,920
Derivative instruments		409,864			—
Prepaid expenses and other current assets		25,250,764			59,845
Total current assets		40,553,884			11,517,085
Oil and gas properties, at cost, using successful efforts:
Proved properties		128,612,527			74,620,823
Unproved properties		40,598,527			52,435,020
Asset retirement costs		552,774			479,071
Total oil and gas properties		169,763,828			127,534,914
Other property and equipment, net		520,882			517,414
Less: accumulated depreciation, depletion and amortization		(40,599,229	)		(26,518,711	)
Property and equipment, net		129,685,481			101,533,617
Other assets:
Restricted cash for letter of credit		1,000,000			1,000,000
Other assets, net		30,100			30,100
Total other assets		1,030,100			1,030,100
Total assets	$	171,269,465		$	114,080,802
LIABILITIES & MEMBERS’ EQUITY
Current liabilities:
Accounts payable	$	13,505,391		$	9,178,586
Accrued liabilities		9,661,627			4,615,033
Derivative instruments		—			3,408,766
Total current liabilities		23,167,018			17,202,385
Line of credit		24,977,400			24,891,792
Derivative instruments, long-term		—			56,430
Asset retirement obligation		728,466			609,377
Total liabilities		48,872,884			42,759,984
Members’ equity		122,396,581			71,320,818
Total liabilities and members’ equity	$	171,269,465		$	114,080,802

See accompanying notes and independent auditors’ report.

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UTICA RESOURCE VENTURES, LLC

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

Years Ended December 31, 2022 and 2021

	2022			2021
Revenues:
Oil sales	$	65,094,687		$	26,075,536
Natural gas sales		22,472,100			8,067,894
Natural gas liquid sales		11,582,646			7,162,326
Loss on derivative instruments		(9,791,991	)		(5,392,497	)
Total revenues		89,357,442			35,913,259
Operating expenses:
Depreciation, depletion, and amortization		14,123,134			7,700,359
Gathering, compression, processing, and transportation		8,094,707			4,806,636
General and administrative		3,799,251			3,401,465
Lease operating expense		3,902,976			2,173,059
Environmental expense		1,000,000			—
Production and ad valorem taxes		629,791			415,854
Accretion of asset retirement obligations		88,378			73,477
Total operating expenses		31,638,237			18,570,850
Other income (expense):
Operating overhead income		504,593			646,102
Interest		(1,295,851	)		(1,389,000	)
Other income		272,756			239,895
Total other expenses		(518,502	)		(503,003	)
Net income		57,200,703			16,839,406
Other comprehensive income:
Change in unrealized derivative loss arising during period		(5,747,080	)		(9,598,479	)
Reclassifications from other comprehensive income		9,622,140			5,512,360
Total other comprehensive income (loss)		3,875,060			(4,086,119	)
Total comprehensive income	$	61,075,763		$	12,753,287

See accompanying notes and independent auditors’ report.

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UTICA RESOURCE VENTURES, LLC

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

Years Ended December 31, 2022 and 2021

	Retained Earnings			Accumulated Other Comprehensive Income			Total Members’ Equity
Balance as of December 31, 2020	$	57,946,608		$	620,923		$	58,567,531
Net income		16,839,406			—			16,839,406
Other comprehensive loss		—			(4,086,119	)		(4,086,119	)
Balance as of December 31, 2021		74,786,014			(3,465,196	)		71,320,818
Distributions		(10,000,000	)		—			(10,000,000	)
Net income		57,200,703			—			57,200,703
Other comprehensive income		—			3,875,060			3,875,060
Balance as of December 31, 2022	$	121,986,717		$	409,864		$	122,396,581

See accompanying notes and independent auditors’ report.

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UTICA RESOURCE VENTURES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31, 2022 and 2021

	2022			2021
Cash flows from operating activities:
Net income	$	57,200,703		$	16,839,406
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and depletion		14,037,526			7,614,751
Amortization of debt issuance costs		85,608			85,608
Accretion of asset retirement obligation		88,378			73,477
Changes in operating assets and liabilities:
(Increase) decrease in:
Accounts receivable		(3,167,026	)		(3,713,130	)
Accrued revenue		(2,483,128	)		(474,033	)
Prepaid expenses and other current assets		(25,190,919	)		34,737
Increase (decrease) in:
Accounts payable		4,326,805			8,816,771
Accrued liabilities		5,046,594			1,369,062
Asset retirement obligation		119,089			99,710
Net cash provided by operating activities		50,063,630			30,746,359
Cash flows from investing activities:
Proceeds from sale of oil and gas properties		2,848,055			386,528
Acquisitions of oil and gas properties		(45,122,354	)		(30,101,434	)
Purchase of property and equipment		(3,469	)		—
Net cash used by investing activities		(42,277,768	)		(29,714,906	)
Cash flows from financing activities:
Distributions		(10,000,000	)		—
Proceeds from line of credit		15,000,000			—
Payments on line of credit		(15,000,000	)		—
Net cash used by financing activities		(10,000,000	)		—
Net (decrease) increase in cash and cash equivalents		(2,214,138	)		1,031,453
Cash, cash equivalents and restricted cash, beginning of year		5,424,296			4,392,843
Cash, cash equivalents and restricted cash, end of year	$	3,210,158		$	5,424,296
Supplemental notes:
Interest paid	$	1,310,188		$	1,385,997
State taxes paid	$	65,680		$	18,054

See accompanying notes and independent auditors’ report.

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UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2022 and 2021

1. ORGANIZATION AND NATURE OF OPERATIONS

Utica Resource Ventures, LLC (URV) was organized as a limited liability company in Delaware on January 26, 2018 to ultimately acquire properties owned by PDC Energy, Inc., and began operations as of February 9, 2018. The Company is primarily engaged in the acquisition, development, production, exploration for, and the sale of oil, gas and natural gas liquids. Currently, the Company is focused on oil and gas exploration and production through ownership of operated working interests in producing properties located in the Utica Shale in Ohio, USA.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting

The accompanying consolidated financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of URV and Utica Resource Operating, LLC (URO) (collectively, the “Company”). All intercompany accounts and transactions have been eliminated in consolidation.

Recently Adopted Accounting Pronouncements

The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-02, Leases, which supersedes the previous lease requirements in Accounting Standards Codification (ASC) 840. The ASU requires lessees to recognize a right-to-use asset and related lease liability for all leases, with a limited exception for short-term leases. Leases are classified as either finance or operating, with the classification affecting the pattern of expense recognition in the statement of operations. Management has evaluated the requirements of the new standard and determined it does not have a material impact on the financial statements.

The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities to better align a Company’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. ASU 2017-12 relaxes the timing of performing the initial quantitative assessment of hedge effectiveness; provides an election to subsequently assess hedge effectiveness qualitatively; eliminates the requirement to disclose hedge ineffectiveness; and aligns (combines) the recognition and presentation of the effects of the hedging instrument and the hedged item in the consolidated financial statements. ASU 2017-12 was adopted by the Company as of January 1, 2021 on a modified retrospective basis. The new ASU resulted in presentation changes for the Company.

Upcoming Accounting Pronouncements

In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-13, Financial Instruments — Credit Losses: Measurement of Credit Losses on Financial Instruments. The ASU includes changes to the accounting and measurement of financial assets, including the Company’s accounts receivable and debt by requiring the Company to recognize an allowance for all expected losses over the life of the financial asset at origination. This is different from the current practice where an

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allowance is not recognized until the losses are considered probable. The new guidance will be effective for the year ended December 31, 2023. Upon adoption, the ASU will be applied using a modified retrospective transition method to the beginning of the earliest period presented.

Use of Estimates

Management uses estimates and assumptions in preparing the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. Those estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported revenues and expenses. Actual results could vary from the estimates that were used for financial reporting purposes. Significant items subject to such estimates and assumptions include estimates of proved reserves and related estimates of the present value of future revenues, the carrying value of oil and gas properties, asset retirement obligations, and derivative financial instruments.

Cash and Cash Equivalents

Management considers all highly liquid investments with original maturities of three months or less to be cash and cash equivalents.

Fair Value of Financial Instruments

The Company’s financial instruments, none of which are held for trading purposes, include cash and cash equivalents, notes and accounts receivable, accounts payable, other liabilities, and long-term debt. Management estimates that the fair value of all financial instruments as of December 31, 2022 and 2021 does not differ materially from the aggregate carrying values of its financial instruments recorded in the accompanying consolidated financial statements.

Derivatives

The Company is exposed to certain risks relating to its ongoing business operations. The Company has entered into oil and gas swap contracts to hedge exposure to price fluctuations on natural gas, crude oil and natural gas liquids sales. Interest rate swaps are entered into to manage interest rate risk associated with the Company’s floating rate borrowings.

All derivatives are accounted for as cash flow hedges and are recorded at fair value on the consolidated balance sheet. The Company determines the fair value of its oil and gas swap contracts based on the difference between the swap’s fixed contract price and the estimated underlying market price at the determination dates.

For derivative instruments that are designated and qualify as a cash flow hedge, unrealized gains and losses are recorded as a component of accumulated other comprehensive income and reclassified into earnings in the period during which the hedged transaction affects earnings.

The initial fair value of hedge components excluded from the assessment of effectiveness is recognized in the income statement under a systematic and rational method over the life of the hedging instrument and is presented in the same income statement line item as the earnings effect of the hedged item. Any difference between the change in the fair value of the hedge components excluded from the assessment of effectiveness and the amounts recognized in earnings is recorded as a component of other comprehensive income.

Oil and Gas Properties and Equipment

The Company uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory

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wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed. In some instances, this determination may take longer than one year. The Company’s management reviews the status of all suspended exploratory drilling costs quarterly.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Additions to capitalized exploratory well costs that are pending the determination of proved reserves total $17,904,198 and $23,085,073 for the years ended December 31, 2022 and 2021, respectively. Capitalized costs of producing oil and gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit- of-production method. Capitalized exploratory well costs reclassified to wells equipment and facilities based on the determination of proved reserves total $27,242,507 and $0 for the years ended December 31, 2022 and 2021, respectively.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Other Property and Equipment

Other property and equipment are stated at cost. The Company capitalizes assets with useful lives greater than one year and values in excess of $500. Depreciation is computed over the estimated useful life of the other property and equipment using the straight-line method. Estimated useful lives range from five to eight years. Additions and improvements, unless minor in amount, are capitalized. Maintenance and repairs that do not extend the useful life of an asset are expensed as incurred.

Asset Retirement Obligations

The Company follows ASC 410, Asset Retirement and Environmental Obligations, which requires certain industries to record the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations for the Company primarily relate to the abandonment of oil and gas producing facilities. ASC 410 requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of- production basis, while the accretion to be recognized will escalate over the life of the producing assets, typically as production declines. See Note 8 for further information.

Revenue Recognition

The Company’s oil and gas sales are accounted for using the sales method. Under this method, sales are recorded on all production sold by the Company regardless of the Company’s ownership interest in the respective property. Imbalances result when sales differ from the buyer’s net revenue interest in the particular property’s reserves and are tracked to reflect the Company’s balancing position. As of December 31, 2022 and 2021, the imbalance and related value were immaterial.

Revenues include the sale of oil, gas and natural gas liquid (NGL) production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred, and collectability of the revenue is probable. The contracts specify a delivery point which

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represents the point at which control of the product is transferred to the customer. Revenue is measured based on consideration specified in the contract and excludes any amounts collected on behalf of third parties. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying Consolidated Statements of Income and Comprehensive Income.

The Company’s oil production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the wellhead at the net price received.

Under the Company’s gas and NGL processing contracts, gas and NGL is delivered to a processing entity at the wellhead or the inlet of the midstream processing entity’s system. The processing entity gathers and processes the gas and NGL and remits proceeds for the resulting sales of gas and NGL. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. In all cases, the Company has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, compression, processing and transportation fees presented as a component of operating expenses in the Consolidated Statements of Income and Comprehensive Income.

Income Taxes

Under existing provisions of the Internal Revenue Code, the income or loss of a limited liability company is recognized by the individual members for federal income tax purposes. Accordingly, no provision for federal income tax has been provided for in accompanying consolidated financial statements. However, the Company remains liable for state severance taxes.

Management has evaluated the Company’s tax positions and has not identified any material uncertain tax positions that would not be sustained in a federal or state income tax examination. Accordingly, no provision for uncertainties in income taxes has been made in the accompanying consolidated financial statements. The Company is subject to routine audits by taxing jurisdictions; however, there are currently no audits for any tax periods in progress.

Concentrations

The cash balances of the Company are held in various financial institutions. If cash balances exceed the amounts covered by insurance provided by the Federal Deposit Insurance Corporation, the excess balances could be at risk of loss. As of December 31, 2022, cash in excess of insured limits totals $2,289,165.

During the years ended December 31, 2022 and 2021, four customers accounted for approximately 92 percent and three customers accounted for 94 percent of total revenue, respectively. During the years ended December 31, 2022 and 2021, three customers accounted for approximately 80 percent and four customers accounted for approximately 97 percent of total joint interest billing receivables, respectively. Additionally, all of the Company’s oil and gas properties are concentrated in one geographic location, the Utica Shale. Management does not believe it is subject to significant risk due to these concentrations.

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3. DERIVATIVE INSTRUMENTS

Fair values of derivatives designated as hedging instruments at December 31, 2022 and 2021 are presented in the Consolidated Balance Sheets as follows:

		Fair Value
	Location	2022		2021
Oil and gas swaps	Current assets	$	322,903	$	—
Oil and gas swaps	Current liabilities		—		(3,300,807	)
Oil and gas swaps	Long-term liabilities		—		(28,253	)
Interest rate contracts	Current assets		86,961		—
Interest rate contracts	Current liabilities		—		(107,959	)
Interest rate contracts	Long-term liabilities		—		(28,177	)
Total derivatives		$	409,864	$	(3,465,196	)

The effect of derivative instruments on the Consolidated Statements of Income and Comprehensive income for the years ended December 31, 2022 and 2021 are as follows:

	December 31, 2022
	Oil and Gas Swaps			Interest Rate Swaps			Total
(Loss) gain recognized in Other Comprehensive Income	$	(6,140,029	)	$	392,949		$	(5,747,080	)
Reclassifications from Other Comprehensive Income to:
Loss on derivative instruments	$	(9,791,991	)	$	—		$	(9,791,991	)
Interest income	$	—		$	169,851		$	169,851
	December 31, 2021
	Oil and Gas Swaps			Interest Rate Swaps			Total
Loss recognized in Other Comprehensive Income	$	(9,582,898	)	$	(15,581	)	$	(9,598,479	)
Reclassifications from Other Comprehensive Income to:
Loss on derivative instruments	$	(5,392,497	)	$	—		$	(5,392,497	)
Interest expense	$	—		$	(119,863	)	$	(119,863	)

Approximately $409,864 of the accumulated other comprehensive gain balance is expected to be reclassified into earnings during the next twelve months (when the associated forecasted sales and purchases are expected to occur). This estimate will fluctuate as contracts are settled based on the derivative’s fixed contract price and underlying market price at the determination date.

4. FAIR VALUE MEASUREMENT

FASB ASC 820-10, Fair Value Measurements, provides a framework for measuring fair value. That framework includes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The three levels of the fair value hierarchy are described below:

Level 1 – inputs are unadjusted quoted prices for identical assets or liabilities in active markets.

Level 2 – inputs are other than quoted prices included within level 1 that are directly or indirectly observable, such as quoted prices for similar assets and liabilities in active markets, or quoted prices for similar assets or liabilities in inactive markets.

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Level 3 – inputs are unobservable in which little or no market value data exists, therefore requiring an entity to develop its own assumption, such as valuation derived from techniques in which one or more significant value drivers are observable.

The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques maximize the use of relevant observable inputs and minimize the use of unobservable inputs.

The following is a description of the valuation methodologies used for assets measured at fair value:

Derivative instruments: The fair value of the Company’s derivative contracts is measured using Level II inputs, and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices.

The following tables set forth by level, within the fair value hierarchy, the Company’s derivative instruments at fair value as of December 31, 2022 and 2021:

	Fair Value Measurements as of December 31, 2022
	Level 1		Level 2			Level 3		Total
Derivative instruments	$	—	$	409,864		$	—	$	409,864
Total	$	—	$	409,864		$	—	$	409,864
	Fair Value Measurements as of December 31, 2021
	Level 1		Level 2			Level 3		Total
Derivative instruments	$	—	$	(3,465,196	)	$	—	$	(3,465,196	)
Total	$	—	$	(3,465,196	)	$	—	$	(3,465,196	)

5. ACCOUNTS RECEIVABLE

The following is a summary of accounts receivable by major classification as of December 31, 2022 and 2021:

	2022		2021
Joint interest billing receivables	$	7,327,604	$	4,194,024
Other accounts receivable		33,446		—
Total	$	7,361,050	$	4,194,024

Management believes all receivables to be fully collectible. As such, there is no allowance for doubtful accounts as of December 31, 2022 and 2021.

6. RESTRICTED CASH FOR LETTER OF CREDIT

On December 1, 2019, URO signed a Natural Gas Sales/Purchase Agreement (Agreement) with Aspire Energy of Ohio, LLC (Aspire). The Agreement includes a commitment between the two parties whereby URO agrees to sell and deliver natural gas produced into Aspire’s gathering system, and Aspire agrees to receive and purchase such natural gas. On September 21, 2020, URO signed an amendment to the Agreement, which has a special provisions addendum where URO provides Aspire with credit support to sufficiently cover URO’s future payment obligations. On October 7, 2020, BOK Financial, N.A. issued a $1,000,000 letter of credit to Aspire on URO’s behalf. Cash totaling $1,000,000 is restricted and held in a CD at BOK Financial, N.A. at December 31, 2022 and 2021 to cover any draws on the letter of credit. URO will maintain the letter of credit until the predetermined volume of natural gas flowing through Aspire’s gathering system has been paid pursuant to the Agreement.

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7. SALE OF INTERESTS IN OIL AND GAS PROPERTIES

The Company sold interest in certain unproved properties to Providence Energy Operators, LLC for $2,848,055 and $386,528 during the years ended December 31, 2022 and 2021, respectively. No gain or loss resulted from these transactions.

8. ASSET RETIREMENT OBLIGATION

The Company’s asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon, and remediate proved producing properties at the end of their productive lives, in accordance with applicable state and federal laws. The Company determines the asset retirement obligation by calculating the present value of estimated cash flows related to the liability.

The following is a summary of asset retirement obligation activity for the years ended December 31, 2022 and December 31, 2021:

Asset retirement obligation, December 31, 2020	$	509,667
Liability incurred upon acquiring and drilling wells		61,419
Liabilities settled and divested		(35,186	)
Accretion		73,477
Asset retirement obligation, December 31, 2021		609,377
Liability incurred upon acquiring and drilling wells		73,703
Liabilities settled and divested		(42,992	)
Accretion		88,378
Asset retirement obligation, December 31, 2022	$	728,466

9. PAYROLL PROTECTION PROGRAM LOAN

In 2021, the Company received a loan from BOK Financial, N.A. in the amount of $238,800 under the Paycheck Protection Program established by the Coronavirus Aid, Relief, and Economic Security Act (CARES). The loan is subject to a note dated February 8, 2021. The Company applied for and has been notified that $238,800 in eligible expenditures for payroll and other expenses described in the CARES Act and the Consolidated Appropriations Act, 2021 has been forgiven. Loan forgiveness is reflected in other income in the accompanying Consolidated Statements of Income and Comprehensive Income for the year ended December 31, 2021.

10. LONG-TERM DEBT

On March 29, 2018, the Company obtained a line of credit (LOC) with Citibank. The LOC provides for maximum borrowings of up to $250,000,000 and expires March 29, 2023. On October 16, 2020, the LOC was amended and the borrowing base decreased to $25,000,000. On January 14, 2022, the LOC was amended to increase the borrowing base to $30,000,000. On August 11, 2022, the LOC was amended to extend the maturity date to March 28, 2024 and reduce the borrowing base to $25,000,000. The LOC bears interest at the adjusted LIBOR rate plus an applicable margin determined at the time of borrowing. Interest rates on outstanding borrowings ranged from 4.50 percent to 8.62 percent for the year ended December 31, 2022 and were 5.00 percent for the year ended December 31, 2021. For the years ended December 31, 2022 and 2021, $15,000,000 and $0, respectively, have been drawn against the LOC. Repayments of the LOC total $15,000,000 and $0 for the years ended December 31, 2022 and 2021, respectively. The LOC requires the Company to maintain certain swap agreements and covenants. As of December 31, 2022 and 2021, the Company is in compliance with the covenants. The LOC is secured by the Company’s oil and gas properties.

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Long-term debt at December 31, 2022 and 2021 consists of the following:

	2022			2021
Line of credit to Citibank	$	25,000,000		$	25,000,000
Less: unamortized debt issuance costs		(22,600	)		(108,208	)
Total	$	24,977,400		$	24,891,792

For the years ended December 31, 2022 and 2021, interest expense totals $1,295,851 and $1,389,000, respectively.

Future maturities of long-term debt as of December 31, 2022 are as follows:

2023	$	—
2024		25,000,000
2025		—
2026		—
2027		—
Thereafter		—
Total	$	25,000,000

11. COMMITMENTS AND CONTINGENCIES

Operating Leases

The Company leases vehicles under non-cancelable leases expiring at various dates through December 31, 2023. The Company also leases office space and surface space under month-to-month arrangements. For the years ended December 31, 2022 and 2021, rent expense totals $118,601 and $119,478, respectively.

Minimum annual payments for the remainder of the lease terms are as follows:

2023	$	18,278
2024		—
2025		—
2026		—
2027		—
Thereafter		—
Total	$	18,278

Environmental Redemption Obligation

In August 2020, the Company received a Notice and Finding of Violation alleging various violations of federal and Ohio air quality laws and regulations and permit requirements at approximately 11 oil and gas production facilities in Ohio. The Company has been in negotiations with the Environmental Protection Agency (EPA) to resolve the violations. In November 2022, the Company and EPA executed a Consent Decree to resolve all alleged violations including a civil penalty of $1,000,000 and certain injunctive relief at URO’s facilities. The anticipated civil penalty of $1,000,000 is reflected in accrued liabilities in the accompanying Consolidated Balance Sheet as of December 31, 2022.

12. EMPLOYEE RETIREMENT PLAN

The Company maintains an employee retirement plan structured under Section 401(k) of the Internal Revenue Code, covering all employees. The Plan allows employees to make voluntary contributions from one

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percent of their earnings up to the maximum amount allowed by the Internal Revenue Code. The Company’s matching contributions are discretionary and determined annually by the Members. Matching contributions are fully vested immediately. For the years ended December 31, 2022 and 2021, Company contributions total $125,321 and $119,993, respectively.

13. MEMBERS’ EQUITY

On February 1, 2018, holders of URV equity interests approved a limited liability company agreement (the “LLC Agreement”) to, among other things, authorize the issuance of $54,000,000 of equity interests (the “URV Interests”). Subsequently, URV received $3,254,167 from its members as an initial capital contribution in exchange for URV Interests. After the initial capital contribution, URV subsequently received additional capital contributions totaling $64,579,997 in exchange for URV Interests. Additionally, the LLC Agreement provided for the formation of a Delaware limited liability company to be formed by key management persons of URV, which did not commit or contribute any capital to URV, but which was to be the incentive member in URV.

URV is managed by an executive committee comprised of five members including three members that are appointed by, and representatives of, Energy Trust Partners V LP (“ETP”), one member that is appointed by Eland Interests Partners, LLC (“Eland”), and one member that is appointed by Republic Utica Partners, LLC (“Republic”), each of which shall have the right to designate said number of members so long as each holds URV Interests. Additionally, the member to be designated by Eland and Republic shall be a key management person in accordance with the terms of the LLC Agreement. Each member has one vote on any company matter decided by vote and each matter requires a supermajority vote of the executive committee representing 66 2/3 percent of all capital members and ETP. As of December 31, 2022, ETP, Eland, and Republic owned 92.6 percent, 3.7 percent, and 3.7 percent, respectively, of URV Interests.

Profits and losses for the URV Interests and incentive member are determined and allocated among the holders of the URV Interests and incentive member in a manner following the ratios and priorities outlined in the LLC Agreement. Distributions are made at such times and in such amounts at the discretion of the Executive Committee in accordance with the LLC Agreement, which are provided first to holders of URV Interests and then to incentive members. Distributions to holders of incentive membership interests are not made until the occurrence of the payout tiers applicable to the URV Interests at the pro rata percentages for each payout tier as defined in the LLC Agreement to be calculated based on each URV Interest holder’s ownership percentage.

The Company paid distributions totaling $10,000,000 and $0 for the years ended December 31, 2022 and 2021, respectively.

14. SUBSEQUENT EVENTS

Management has reviewed subsequent events through March 13, 2023, the date the consolidated financial statements were available to be issued.

The Consent Decree related to the EPA violation was lodged with the United States District Court for the Southern District of Ohio on January 3, 2023 and is awaiting approval.

In February 2023, the LOC with Citibank was amended increasing the borrowing base to $45,000,000 until later subject to reductions of $5,000,000 on May 31, 2023, $5,000,000 on June 30, 2023, and $10,000,000 on July 31, 2023.

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SUPPLEMENTAL INFORMATION

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first day of the month prices. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond URV’s control such as reservoir performance, prices, economic conditions, and government restrictions. In addition, results of drilling, testing, and production subsequent to the date of an estimate may justify revision of that estimate.

Reserve estimates are often different from the quantities of oil, and natural gas, that are ultimately recovered. Estimating quantities of proved oil and natural gas reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical, and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon, economic factors, such as oil and natural gas prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating proved undeveloped (PUD) reserves, proved developed non-producing reserves, and proved developed reserves that are early in their production life. As a result, URV’s reserve estimates are inherently imprecise.

The following table reflects changes in proved reserves during the years ended December 31, 2022 and 2021 and the estimated quantities of proved developed and PUD oil, natural gas and NGL reserves as of the dates indicated.

See independent auditors’ report.

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	Crude Oil (Bbls)			Natural Gas (Mcf)			Natural Gas Liquids (Bbls)			Total (Boe)
Total proved reserves:
December 31, 2020		5,718,371			32,377,813			2,561,121			13,675,794
Extensions		—			—			—			—
Revisions to previous estimates(1)		1,364,431			15,705,104			1,029,417			5,011,365
Purchases of reserves in place		—			—			—			—
Production		(433,700	)		(2,381,239	)		(178,660	)		(1,009,233	)
December 31, 2021		6,649,102			45,701,678			3,411,878			17,677,926
Extensions(2)		3,718,833			20,868,962			1,256,593			8,453,586
Revisions to previous estimates(3)		(422,722	)		(4,198,856	)		(548,671	)		(1,671,202	)
Purchases of reserves in place		—			—			—			—
Production		(710,984	)		(3,547,770	)		(245,393	)		(1,547,672	)
December 31, 2022		9,234,229			58,824,014			3,874,407			22,912,638
Proved developed reserves:
December 31, 2020		1,419,499			9,662,006			715,894			3,745,727
December 31, 2021		1,578,648			15,331,835			1,201,105			5,335,059
December 31, 2022		2,632,625			21,775,027			1,500,897			7,762,693
Proved undeveloped reserves:
December 31, 2020		4,298,872			22,715,808			1,845,227			9,930,067
December 31, 2021		5,070,454			30,369,842			2,210,773			12,342,867
December 31, 2022		6,601,604			37,048,987			2,373,510			15,149,945

(1) Revisions to previous estimates. In 2021, total revisions to previous estimates increased proved reserves by 4.9 MMBoe. These upward revisions primarily consisted of 1.5 MMBoe of positive revisions based on increases in pricing, 2.6 MMBoe of positive revisions associated with well forecasting, 0.6 MMBoe of positive revisions related to changes in commercial expenses and 0.1 MMBoe of positive revisions associated with additional infill wells.

(2) Extensions. In 2022, total extensions to previous estimates increased proved reserves by 8.5 MMBoe. These extensions primarily related to the addition of six (6) proved undeveloped (“PUD”) locations to be developed by 2027 (as that year entered the 5-year development window) and converting unproved reserves to proved developed reserves.

(3) Revisions to previous estimates. In 2022, total revisions to previous estimates reduced proved reserves by 1.7 MMBoe. These downward revisions primarily consisted of 2.0 MMBoe of negative revisions associated with well forecasting, offset by 0.4 MMBoe of positive revisions based on increases in pricing.

Standardized Measure of Discounted Future Net Cash Flows

The following table reflects URV’s standardized measure of discounted future net cash flows of proved oil, natural gas and NGL reserves:

	December 31,
	2022			2021
Future cash inflows	$	1,373,699,517		$	680,626,195
Future development costs(1)		(285,308,733	)		(161,275,858	)
Future production costs		(114,405,185	)		(101,707,634	)
Future net cash flows		973,985,599			417,642,703
10% discount to reflect timing of cash flows		(403,243,606	)		(208,739,968	)
Standardized measure of discounted future net cash flows	$	570,741,993		$	208,902,735

(1) Future development costs include costs associated with the future abandonment of proved properties, including proved undeveloped locations.

See independent auditors’ report.

F-89

The following table reflects the principal changes in the standardized measure of discounted future net cash flows attributable to URV’s proved reserves:

	For the Year Ended December 31,
	2022			2021
Standardized measure of discounted future net cash flows, beginning of period	$	208,902,735		$	29,333,917
Sales of oil, natural gas, NGLs, net of production costs		173,986,732			133,366,190
Purchases of minerals in place		—			—
Extensions, net of future development costs		210,753,193			—
Net change in price and production costs		(86,521,959	)		(33,910,000	)
Previously estimated development costs incurred		8,825,090			—
Change in estimated future development costs		20,011,334			2,817,746
Revisions of previous quantity estimates		—			78,826,745
Accretion of discount		20,890.274			2,933,392
Net change in income taxes		—			—
Net change in timing of production and other		13,894,594			(4,465,255	)
Standardized measure of discounted future net cash flows, end of period	$	570,741,993		$	208,902,735

See independent auditors’ report.

F-90

UTICA RESOURCE VENTURES, LLC

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

ASSETS
	September 30, 2023			December 31, 2022
Current assets:
Cash and equivalents	$	1,095,879		$	2,210,158
Accounts receivable		1,073,023			7,361,050
Accrued revenue		10,633,984			5,322,048
Derivative instruments					409,864
Prepaid expenses and other current assets		106,236			25,250,764
Total current assets		12,909,122			40,553,884
Oil and gas properties, at cost, using successful efforts:
Proved properties		191,317,974			128,612,527
Unproved properties		34,395,462			40,598,527
Asset retirement costs		552,774			552,774
Total oil and gas properties		226,266,210			169,763,828
Other property and equipment		520,882			520,882
Less: accumulated depreciation, depletion, and amortization		(75,783,382	)		(40,599,229	)
Property and equipment, net		151,003,710			129,685,481
Other assets:
Restricted cash for letter of credit		1,000,000			1,000,000
Other assets, net		30,100			30,100
Total other assets		1,030,100			1,030,100
Total assets	$	164,942,932		$	171,269,465
LIABILITIES & MEMBERS’ EQUITY
Current liabilities:
Accounts payable	$	882,422		$	13,505,391
Accrued liabilities		11,079,171			9,661,627
Derivative instruments		—			—
Total current liabilities		11,961,593			23,167,018
Line of credit		3,994,347			24,977,400
Derivative instruments, long-term		—			—
Asset retirement obligation		742,106			728,466
Total liabilities		16,698,046			48,872,884
Members’ equity		148,244,886			122,396,581
Total liabilities and members’ equity	$	164,942,932		$	171,269,465

F-91

UTICA RESOURCE VENTURES, LLC

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(UNAUDITED)

For the Nine Months Ended September 30, 2023 and 2022

	2023			2022
Revenues:
Oil sales	$	65,162,441		$	52,880,562
Natural gas sales		7,689,501			17,743,676
Natural gas liquid sales		7,793,797			9,271,463
Gain (loss) on derivative instruments		682,814			(9,082,169	)
Total revenues		81,328,553			70,813,532
Operating expenses:
Depreciation, depletion, and amortization		35,192,740			12,955,311
Gathering, compression, processing, and transportation		9,225,875			6,086,448
General and administrative		3,164,398			2,885,051
Lease operating expense		5,231,992			2,949,029
Production and ad valorem taxes		795,228			483,390
Accretion of asset retirement obligations		22,007			58,608
Total operating expenses		53,632,240			25,417,837
Other income (expense):
Operating overhead income		444,320			360,349
Interest		(2,082,401	)		(994,233	)
Other income		199,937			88,468
Total other expenses		(1,438,144	)		(545,416	)
Net income		26,258,169			44,850,279
Other comprehensive income:
Change in unrealized derivative gain (loss) arising during period		472,079			(11,098,347	)
Reclassifications from other comprehensive income		(881,943	)		9,075,423
Total other comprehensive (loss) income		(409,864	)		2,022,924
Total comprehensive income	$	25,848,305		$	46,873,203

F-92

UTICA RESOURCE VENTURES, LLC

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

(UNAUDITED)

For the Nine Months Ended September 30, 2023 and 2022

	Retained Earnings		Accumulated Other Comprehensive Income			Total Members’ Equity
Balance as of December 31, 2021	$	74,786,014	$	(3,465,196	)	$	71,320,818
Net income		44,850,279		—			44,850,279
Other comprehensive income		—		2,022,924			2,022,924
Balance as of September 30, 2022	$	119,636,293	$	(1,442,272	)	$	118,194,021

	Retained Earnings		Accumulated Other Comprehensive Income			Total Members’ Equity
Balance as of December 31, 2022	$	121,986,717	$	409,864		$	122,396,581
Net income		26,258,169		—			26,258,169
Other comprehensive loss		—		(409,864	)		(409,864	)
Balance as of September 30, 2023	$	148,244,886	$	—		$	148,244,886

F-93

UTICA RESOURCE VENTURES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

For the Nine Months Ended September 30, 2023 and 2022

	2023			2022
Cash flows from operating activities:
Net income	$	26,258,169		$	44,850,279
Adjustments to reconcile net income net cash provided by operating activities:
Depreciation and depletion		35,175,793			12,891,105
Amortization of debt issuance costs		16,947			64,206
Accretion of asset retirement obligation		22,007			58,608
Changes in operating assets and liabilities:
(Increase) decrease in:
Accounts receivable		6,288,027			2,234,142
Accrued revenue		(5,311,936	)		(4,022,108	)
Prepaid expenses and other current assets		25,144,528			(150,743	)
Increase (decrease) in:
Accounts payable		(12,622,969	)		(6,803,111	)
Accrued liabilities		1,417,544			5,779,131
Asset retirement obligation		13,640			33,943
Net cash provided by operating activities		76,401,750			54,935,452
Cash flows from investing activities:
Proceeds from sale of oil and gas properties		1,751,335			1,881,052
Acquisitions of oil and gas properties		(58,267,364	)		(19,304,613	)
Purchase of property and equipment		—			(3,470	)
Net cash used by investing activities		(56,516,029	)		(17,427,031	)
Cash flows from financing activities:
Proceeds from line of credit		15,000,000			5,000,000
Payments on line of credit		(36,000,000	)		(15,000,000	)
Net cash used by financing activities		(21,000,000	)		(10,000,000	)
Net (decrease) increase in cash and cash equivalents		(1,114,279	)		27,508,421
Cash, cash equivalents and restricted cash at beginning of period		3,210,158			5,424,296
Cash, cash equivalents and restricted cash at end of period	$	2,095,879		$	32,932,717
Supplemental notes:
Interest paid	$	2,091,821		$	1,085,028
State taxes paid	$	37,565		$	39,134

F-94

UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. ORGANIZATION AND NATURE OF OPERATIONS

Utica Resource Ventures, LLC (“URV”) was organized as a limited liability company in Delaware on January 26, 2018, to ultimately acquire properties owned by PDC Energy, Inc., and began operations as of February 9, 2018. The Company is primarily engaged in the acquisition, development, production, exploration for, and the sale of oil, gas, and natural gas liquids. Currently, the Company is focused on oil and gas exploration and production through ownership of operated working interests in producing properties located in the Utica Shale in Ohio, USA.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting

The accompanying consolidated financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of URV and Utica Resource Operating, LLC (“URO”) (collectively, the “Company”). All intercompany accounts and transactions have been eliminated in consolidation.

Recently Adopted Accounting Pronouncements

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments – Credit Losses (Topic 326). ASU 2016-13 revises the accounting requirements related to the measurement of credit losses and requires organizations to measure all expected credit losses for financial assets based on historical experience, current conditions, and reasonable and supportable forecasts about collectability. Assets must be presented in the financial statements at the net amount expected to be collected.

On January 1, 2023, the Company adopted ASU 2016-13 using the modified retrospective method. Results for the reporting period beginning January 1, 2023, are presented under ASC 326. The adoption did not result in a material impact to the financial statements.

In February 2016, The FASB issued ASU No. 2016-02, Leases, which supersedes the previous lease requirements in Accounting Standards Codification (“ASC”) 840. The ASU requires lessees to recognize a right- to-use asset and related lease liability for all leases, with a limited exception for short-term leases. Leases are classified as either finance or operating, with the classification affecting the pattern of expense recognition in the statement of operations. Management has evaluated the requirements of the new standard and determined it does not have a material impact on the financial statements.

Upcoming Accounting Pronouncements

On October 28, 2021, the FASB issued ASU 2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. ASU 2021-08 changes the accounting for contract assets and liabilities acquired in a business combination by requiring an acquiring entity to measure contract assets and liabilities in accordance with FASB Accounting Standards Codification 606, Revenue from Contracts with Customers. The new guidance will be effective for the Company as of January 1, 2024, and will be applied prospectively to business combinations occurring on or after the effective date. Management is still evaluating the impact this standard will have on the financial statements.

F-95

UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In March 2023, the FASB issued ASU No. 2023-01, Leases (Topic 842): Common Control Arrangements, which clarifies application of Topic 842 for leases with a related party. The new guidance requires entities to determine whether a related party arrangement between entities under common control is a lease, and if so determined, be classified, and accounted for on the same basis as an agreement with an unrelated party on the basis of legally enforceable terms and conditions. This is a change from previous guidance which classified and accounted for the lease on the basis of economic substance if the terms and conditions were between related parties. The amendment in this update requires that lease improvements associated with common control leases be amortized by the lessee over the useful life of the leasehold improvements to the common control group, regardless of the lease term, as long as the lessee controls the use of the underlying asset. Leasehold improvements should also be accounted for as a transfer between entities under common control through an adjustment to equity if, and when, the lessee no longer controls the use of the underlying asset. The new guidance will be effective for the Company’s year ending December 31, 2024. Management does not believe this standard will have a material impact on the financial statements.

Use of Estimates

Management uses estimates and assumptions in preparing the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. Those estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, and the reported revenues and expenses. Actual results could vary from the estimates that were used for financial reporting purposes. Significant items subject to such estimates and assumptions include estimates of proved reserves and related estimates of the present value of future revenues, the carrying value of oil and gas properties, asset retirement obligations, and derivative financial instruments.

Cash and Cash Equivalents

Management considers all highly liquid investments with original maturities of three months or less to be cash and cash equivalents.

Fair Value of Financial Instruments

The Company’s financial instruments, none of which are held for trading purposes, include cash and cash equivalents, notes, and accounts receivable, accounts payable, other liabilities, and long-term debt. Management estimates that the fair value of all financial instruments as of September 30, 2023 and 2022 does not differ materially from the aggregate carrying values of its financial instruments recorded in the accompanying consolidated financial statements.

Derivatives

The Company is exposed to certain risks relating to its ongoing business operations. The Company has entered into oil and gas swap contracts to hedge exposure to price fluctuations on natural gas, crude oil, and natural gas liquids sales. Interest rate swaps are entered into to manage interest rate risk associated with the Company’s floating rate borrowings.

All derivatives are accounted for as cash flow hedges and are recorded at fair value on the consolidated balance sheet. The Company determines the fair value of its oil and gas swap contracts based on the difference between the swap’s fixed contract price and the estimated underlying market price at the determination dates.

F-96

UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

For derivative instruments that are designated and qualify as a cash flow hedge, unrealized gains and losses are recorded as a component of accumulated other comprehensive income and reclassified into earnings in the period during which the hedged transaction affects earnings.

The initial fair value of hedge components excluded from the assessment of effectiveness is recognized in the income statement under a systematic and rational method over the life of the hedging instrument and is presented in the same income statement line item as the earnings effect of the hedged item. Any difference between the change in the fair value of the hedge components excluded from the assessment of effectiveness and the amounts recognized in earnings is recorded as a component of other comprehensive income.

Oil and Gas Properties and Equipment

The Company uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed. In some instances, this determination may take longer than one year. The Company’s management reviews the status of all suspended exploratory drilling costs quarterly.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Additions to capitalized exploratory well costs that are pending the determination of proved reserves total $4,778,576 and $10,010,605 for the nine months ended September 30, 2023 and 2022, respectively. Capitalized costs of producing oil and gas properties, after considering estimated residual salvage values, are depreciated, and depleted by the unit-of-production method. Capitalized exploratory well costs reclassified to wells equipment and facilities based on the determination of proved reserves total $9,614,352 and $27,242,061 for the nine months ended September 30, 2023 and 2022, respectively.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized in income.

Other Property and Equipment

Other property and equipment are stated at cost. The Company capitalizes assets with useful lives greater than one year and values in excess of $500. Depreciation is computed over the estimated useful life of the other property and equipment using the straight-line method. Estimated useful lives range from five to eight years. Additions and improvements, unless minor in amount, are capitalized. Maintenance and repairs that do not extend the useful life of an asset are expensed as incurred.

Asset Retirement Obligations

The Company follows ASC 410, Asset Retirement and Environmental Obligations, which requires certain industries to record the fair value of a liability for an asset retirement obligation in the period in which the liability is incurred. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations for the Company primarily relate to the abandonment

F-97

UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

of oil and gas producing facilities. ASC 410 requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of- production basis, while the accretion to be recognized will escalate over the life of the producing assets, typically as production declines. See Note 8 for further information.

Revenue Recognition

The Company’s oil and gas sales are accounted for using the sales method. Under this method, sales are recorded on all production sold by the Company regardless of the Company’s ownership interest in the respective property. Imbalances result when sales differ from the buyer’s net revenue interest in the particular property’s reserves and are tracked to reflect the Company’s balancing position. As of September 30, 2023 and 2022, the imbalance and related value were immaterial.

Revenues include the sale of oil, gas, and natural gas liquid (“NGL”) production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred, and collectability of the revenue is probable. The contracts specify a delivery point which represents the point at which control of the product is transferred to the customer. Revenue is measured based on consideration specified in the contract and excludes any amounts collected on behalf of third parties. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying Consolidated Statements of Income and Comprehensive Income.

The Company’s oil production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. Revenue is recognized when control transfers to the purchaser at the wellhead at the net price received.

Under the Company’s gas and NGL processing contracts, gas and NGL is delivered to a processing entity at the wellhead or the inlet of the midstream processing entity’s system. The processing entity gathers and processes the gas and NGL and remits proceeds for the resulting sales of gas and NGL. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. In all cases, the Company has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, compression, processing, and transportation fees presented as a component of operating expenses in the Consolidated Statements of Income and Comprehensive Income.

Income Taxes

Under existing provisions of the Internal Revenue Code, the income or loss of a limited liability company is recognized by the individual members for federal income tax purposes. Accordingly, no provision for federal income tax has been provided for in accompanying consolidated financial statements. However, the Company remains liable for state severance taxes.

Management has evaluated the Company’s tax positions and has not identified any material uncertain tax positions that would not be sustained in a federal or state income tax examination. Accordingly, no provision for uncertainties in income taxes has been made in the accompanying consolidated financial statements. The Company is subject to routine audits by taxing jurisdictions; however, there are currently no audits for any tax periods in progress.

F-98

UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

Concentrations

The cash balances of the Company are held in various financial institutions. If cash balances exceed the amounts covered by insurance provided by the Federal Deposit Insurance Corporation, the excess balances could be at risk of loss. As of September 30, 2023, cash in excess of insured limits totals $1,914,044.

During the nine months ended September 30, 2023 and 2022, two customers accounted for approximately 69 percent and four customers accounted for 94 percent of total revenue, respectively. During the nine months ended September 30, 2023 and 2022, three customer accounted for approximately 81 percent and three customers accounted for approximately 79 percent of total joint interest billing receivables, respectively. Additionally, all of the Company’s oil and gas properties are concentrated in one geographic location, the Utica Shale. Management does not believe it is subject to significant risk due to these concentrations.

3. ACCOUNTS RECEIVABLE

The following is a summary of accounts receivable by major classification as of September 30, 2023 and December 31, 2022:

	2023		2022
Joint interest billing receivables	$	1,073,023	$	7,327,604
Other accounts receivable		—		33,446
Total	$	1,073,023	$	7,361,050

Management evaluates credit losses expected to arise over the life of the receivables based on historical experience, current conditions, and reasonable and supportable collectability forecasts. Management believes all receivables to be fully collectible. As such, there is no allowance for credit losses as of September 30, 2023 and 2022.

4. DERIVATIVE INSTRUMENTS

Fair values of derivatives designated as hedging instruments at September 30, 2023 and December 31, 2022 presented in the Consolidated Balance Sheets as follows:

		Fair Value
	Location	2023		2022
Oil and gas swaps	Current assets		—		322,903
Interest rate swaps	Current liabilities		—		86,961
Total derivatives		$	—	$	409,864

The effect of derivative instruments on the Consolidated Statements of Income and Comprehensive income for the nine months ended September 30, 2023 and 2022 are as follows:

	September 30, 2023
	Oil and Gas Swaps		Interest Rate Swaps		Total
Gain recognized in Other Comprehensive Income	$	359,912	$	112,167	$	472,079
Reclassifications from Other Comprehensive Income to:
Fixed price swaps	$	682,814	$	—		682,814
Basis swaps	$	—	$	199,129		199,129

F-99

UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

	September 30, 2022
	Oil and Gas Swaps			Interest Rate Swaps			Total
Loss recognized in Other Comprehensive Income	$	(10,758,914	)	$	(339,433	)	$	(11,098,347	)
Reclassifications from Other Comprehensive Income to:
Fixed price swaps	$	(9,082,169	)	$	—			(9,082,169	)
Basis swaps	$	—		$	6,746			6,746

5. FAIR VALUE MEASUREMENT

FASB ASC 820-10, Fair Value Measurements, provides a framework for measuring fair value. That framework includes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3).

The three levels of the fair value hierarchy are described below:

Level 1 – inputs are unadjusted quoted prices for identical assets or liabilities in active markets.

Level 2 – inputs are other than quoted prices included within level 1 that are directly or indirectly observable, such as quoted prices for similar assets and liabilities in active markets, or quoted prices for similar assets or liabilities in inactive markets.

Level 3 – inputs are unobservable in which little or no market value data exists, therefore requiring an entity to develop its own assumption, such as valuation derived from techniques in which one or more significant value drivers are observable.

The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques maximize the use of relevant observable inputs and minimize the use of unobservable inputs.

The following is a description of the valuation methodologies used for assets measured at fair value:

Derivative instruments: The fair value of the Company’s derivative contracts is measured using Level II inputs and are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices.

The following tables set forth by level, within the fair value hierarchy, the Company’s derivative instruments at fair value as of September 30, 2023 and December 31, 2022:

	Fair Value Measurements as of September 30, 2023
	Level 1		Level 2		Level 3		Fair Value
Derivative instruments	$	—	$	—	$	—	$	—
Total	$	—	$	—	$	—	$	—

	Fair Value Measurements as of December 31, 2022
	Level 1		Level 2		Level 3		Fair Value
Derivative instruments	$	—	$	409,864	$	—	$	409,864
Total	$	—	$	409,864	$	—	$	409,864

F-100

UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

6. RESTRICTED CASH FOR LETTER OF CREDIT

On December 1, 2019, URO signed a Natural Gas Sales/Purchase Agreement (“Agreement”) with Aspire Energy of Ohio, LLC (“Aspire”). The Agreement includes a commitment between the two parties whereby URO agrees to sell and deliver natural gas produced into Aspire’s gathering system and Aspire agrees to receive and purchase such natural gas. On September 21, 2020, URO signed an amendment to the Agreement, which has a special provisions addendum where URO provides Aspire with credit support to sufficiently cover URO’s future payment obligations. On October 7, 2020, BOK Financial, N.A. issued a $1,000,000 letter of credit to Aspire on URO’s behalf. Cash totaling $1,000,000 is restricted and held in a CD at BOK Financial, N.A. at September 30, 2023 and 2022, to cover any draws on the letter of credit. URO is to maintain the letter of credit until the predetermined volume of natural gas flowing through Aspire’s gathering system has been paid pursuant to the Agreement.

7. SALE OF INTERESTS IN OIL AND GAS PROPERTIES

On August 7, 2023, the Company and Providence Energy Operators, LLC (“PEO”) entered into a purchase and sale agreement (“PSA”) with Wolf Run Operating, LLC (the “buyer”) for the sale of all rights, titles, and interests associated with its oil and gas wells, including related equipment and acreage. The total transaction, which closed on October 4, 2023, amounted to a sale price of $245,000,000 to the Company. Concurrently, an operational agreement was established between the Company and the buyer, stipulating the Company’s continued operation of the wells from March 1, 2023, until September 30, 2023. Net revenues of $58,984,768 and related expenses of $37,169,119 for that period were included as a purchase price adjustment. Subsequently, the buyer assumed revenues and expenses associated with the operation. See Note 12 for further information.

The Company sold interest in certain unproved properties to POE for $1,751,335 and $1,881,052 during the periods ended September 30, 2023 and 2022, respectively. No gain or loss resulted from these transactions.

8. ASSET RETIREMENT OBLIGATION

The Company’s asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon, and remediate proved producing properties at the end of their productive lives, in accordance with applicable state and federal laws. The Company determines the asset retirement obligation by calculating the present value of estimated cash flows related to the liability.

The following is a summary of asset retirement obligation activity for the nine months ended September 30, 2023:

Asset retirement obligation, December 31, 2022	$	728,466
Liabilities settled and divested		(61,420	)
Liability incurred upon acquiring and drilling wells		53,053
Accretion		22,007
Asset retirement obligation, September 30, 2023	$	742,106

9. LONG-TERM DEBT

On March 29, 2018, the Company obtained a line of credit (“LOC”) with Citibank. The LOC originally provided for maximum borrowings of up to $250,000,000 with an expiration date of March 29, 2023. On October 16, 2020, the LOC was amended, and the borrowing base decreased to $25,000,000. On January 14, 2022, the LOC was amended to increase the borrowing base to $30,000,000. On August 11, 2022, the LOC was

F-101

UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

amended to extend the maturity date to March 28, 2024, and reduce the borrowing base to $25,000,000. On February 7, 2023, the LOC was amended to increase the borrowing base to $45,000,000. The LOC bears interest at the adjusted LIBOR rate plus an applicable margin determined at the time of borrowing. Interest rates on outstanding borrowings ranged from 8.31 percent to 9.81 percent for the period ended September 30, 2023 and ranged from 4.50 percent to 5.94 percent for the period ended September 30, 2022. For the nine months ended September 30, 2023 and 2022, $15,000,000 and $5,000,000, respectively, have been drawn against the LOC. Repayments of the LOC total $36,000,000 and $15,000,000 for the nine months ended September 30, 2023 and 2022, respectively. The LOC is secured by the Company’s oil and gas properties.

Long-term debt at September 30, 2023 and December 31, 2022 consists of the following:

	2023			2022
Line of credit to Citibank	$	4,000,000		$	25,000,000
Less: unamortized debt issuance costs		(5,653	)		(22,600	)
Total	$	3,994,347		$	24,977,400

For the nine months ended September 30, 2023 and 2022, interest expense totals $2,082,401 and $1,058,451, respectively.

Future maturities of long-term debt as of September 30, 2023 are as follows:

2023	$	4,000,000
2024		—
2025		—
2026		—
2027		—
Thereafter		—
Total	$	4,000,000

10. COMMITMENTS AND CONTINGENCIES

Operating Leases

The Company leased vehicles under non-cancelable leases that expired at various dates through December 31, 2023. The Company leases office space under month-to-month arrangements. For the nine months ended September 30, 2023 and 2022, rent expense totals $76,789 and $90,631, respectively.

Environmental Redemption Obligation

In August 2020, the Company received a Notice and Finding of Violation alleging various violations of federal and Ohio air quality laws and regulations and permit requirements at approximately eleven oil and gas production facilities in Ohio. The Company has been in negotiations with the Environmental Protection Agency (“EPA”) to resolve the violations. In November 2022, the Company and EPA executed a Consent Decree to resolve all alleged violations including a civil penalty of $1,000,000 and certain injunctive relief at URO’s facilities. In April 2023, the penalty of $1,000,000 was remitted.

F-102

UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

11. EMPLOYEE RETIREMENT PLAN

The Company maintains an employee retirement plan structured under Section 401(k) of the Internal Revenue Code, covering all employees. The Plan allows employees to make voluntary contributions from one percent of their earnings up to the maximum amount allowed by the Internal Revenue Code. The Company’s matching contributions are discretionary and determined annually by the Members. Matching contributions are fully vested immediately. For the nine months ended September 30, 2023 and 2022, Company contributions total $102,859 and $98,343, respectively.

12. MEMBERS’ EQUITY

On February 1, 2018, holders of URV equity interests approved a limited liability company agreement (the “LLC Agreement”) to, among other things, authorize the issuance of $54,000,000 of equity interests (the “URV Interests”). Subsequently, URV received $3,254,167 from its members as an initial capital contribution in exchange for URV Interests. After the initial capital contribution, URV subsequently received additional capital contributions totaling $64,579,997 in exchange for URV Interests. Additionally, the LLC Agreement provided for the formation of a Delaware limited liability company to be formed by key management persons of URV, which did not commit or contribute any capital to URV, but which was to be the incentive member in URV.

URV is managed by an executive committee comprised of five members including three members that are appointed by, and representatives of, Energy Trust Partners V LP (“ETP”), one member that is appointed by Eland Interests Partners, LLC (“Eland”), and one member that is appointed by Republic Utica Partners, LLC (“Republic”), each of which shall have the right to designate said number of members so long as each holds URV Interests. Additionally, the member to be designated by Eland and Republic shall be a key management person in accordance with the terms of the LLC Agreement. Each member has one vote on any company matter decided by vote and each matter requires a supermajority vote of the executive committee representing 66 2/3 percent of all capital members and ETP. As of September 30, 2023, ETP, Eland, and Republic owned 92.6 percent, 3.7 percent, and 3.7 percent, respectively, of URV Interests.

Profits and losses for the URV Interests and incentive member are determined and allocated among the holders of the URV Interests and incentive member in a manner following the ratios and priorities outlined in the LLC Agreement. Distributions are made at such times and in such amounts at the discretion of the Executive Committee in accordance with the LLC Agreement, which are provided first to holders of URV Interests and then to incentive members. Distributions to holders of incentive membership interests are not made until the occurrence of the payout tiers applicable to the URV Interests at the pro rata percentages for each payout tier as defined in the LLC Agreement to be calculated based on each URV Interest holder’s ownership percentage.

No distributions were paid for the nine months ended September 30, 2023 and 2022, respectively.

13. SUBSEQUENT EVENTS

Management has reviewed subsequent events through August 5, 2024, the date the unaudited consolidated financial statements were available to be issued.

In accordance with the PSA with Wolf Run Operating, LLC previously discussed, wells, acreage, and well equipment totaling $162,669,812 were sold for an adjusted purchase price after customary closing adjustments of $223,184,351 resulting in a gain on the sale of $58,822,769 after transaction costs of $1,691,770. A holdback

F-103

UTICA RESOURCE VENTURES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

amount of $18,375,000 is in escrow as a means to protect the buyer from misrepresentations or misstatements associated with the representations and warranties outlined in the PSA and was included in accounts receivable on December 31, 2023. As of August 5, 2024, management is not aware of any such claims. Half of the escrow balance was paid in April 2024, and management anticipates payment of the remaining balance in October 2024.

Following the completion of the sale, the Company proceeded to engage in a Transition Service Agreement (“TSA”) with the buyer. The agreement stipulated that the Company continue to furnish operational support subsequent to the closure for a duration of two months. These services include routine field operations in addition to comprehensive accounting functions, encompassing accounts payable management and revenue disbursement oversight. Fees received from TSA total $728,013.

On October 4, 2023, the line of credit was paid in full and terminated upon the sale of oil and gas properties.

Effective October 4, 2023, the Agreement with Aspire was terminated and URO was released from all respective obligations related to the restricted letter of credit.

F-104

Independent Auditors’ Report

The Members

PEO Ohio, LLC – Ohio Appalachian Basin Working and Revenue Interests:

Opinion

We have audited the accompanying statements of revenues and direct operating expenses (the statements) of PEO Ohio, LLC – Ohio Appalachian Basin Working and Revenue Interests (the Utica Assets), for the years ended December 31, 2022 and 2021, and the related notes to the statements.

In our opinion, the accompanying statements present fairly, in all material respects, the revenues and direct operating expenses of the Utica Assets for the years ended December 31, 2022 and 2021 in accordance with U.S. generally accepted accounting principles.

Basis for Opinion

We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditors’ Responsibilities for the Audit of the Statements section of our report. We are required to be independent of the Utica Assets and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Emphasis of Matter

As discussed in Note 1 to the statements, these statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not intended to be a complete presentation of the operations of the Utica Assets. Our opinion is not modified with respect to this matter.

Responsibilities of Management for the Statements

Management is responsible for the preparation and fair presentation of the statements in accordance with U.S. generally accepted accounting principles, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of statements that are free from material misstatement, whether due to fraud or error.

In preparing the statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Utica Assets’ ability to continue as a going concern for one year after the date that the statements are available to be issued.

Auditors’ Responsibilities for the Audit of the Statements

Our objectives are to obtain reasonable assurance about whether the statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the statements.

In performing an audit in accordance with GAAS, we:

• Exercise professional judgment and maintain professional skepticism throughout the audit.

F-105

• Identify and assess the risks of material misstatement of the statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the statements.

• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Utica Assets’ internal control. Accordingly, no such opinion is expressed.

• Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the statements.

• Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Utica Assets’ ability to continue as a going concern for a reasonable period of time.

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control related matters that we identified during the audit.

Required Supplementary Information

U.S. generally accepted accounting principles require that the Supplementary Oil and Gas Disclosures be presented to supplement the basic statements. Such information is the responsibility of management and, although not a part of the basic statements, is required by Financial Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with GAAS, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic statements, and other knowledge we obtained during our audit of the basic statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

/s/ KPMG LLP

Dallas, Texas

August 6, 2024

F-106

PEO Ohio, LLC

Ohio Appalachian Basin Working and Revenue Interests

Statements of Revenues and Direct Operating Expenses

For the Years Ended December 31, 2022 and 2021

	2022			2021
Revenues
Crude oil		16,235,954			6,556,681
Natural gas		5,624,690			2,027,937
Natural gas liquids		2,882,481			1,800,559
Total revenues		24,743,125			10,385,177
Direct Operating Expenses		(3,115,935	)		(1,918,297	)
Excess of Revenues over Direct Operating Expenses	$	21,627,190		$	8,466,880

See accompanying notes to statements of revenues and direct operating expenses

F-107

PEO Ohio, LLC

Ohio Appalachian Basin Working and Revenue Interests

Notes to Statements of Revenues and Direct Operating Expenses

For the Years Ended December 31, 2022 and 2021

1. Nature of operations and summary of significant accounting policies

Organization and Nature of Operations

PEO Series D, LLC (“Series D”) was established for the principal purpose of investing in oil and gas- related properties and business through joint operations with third-party operators across the United States of America. Series D began its operations on July 16, 2018.

PEO Ohio, LLC (“PEO Ohio” or the “Company”), a wholly-owned subsidiary of Series D, holds ownership in non-operated working and revenue interests in various oil and gas properties, along with associated leasehold and infrastructure assets, situated in the Appalachian Basin in Guernsey, Morgan, Noble, and Washington Counties, Ohio (collectively referred as the “Utica Assets”). PEO Ohio acquired the Utica Assets through several acquisitions consummated between the years ended December 31, 2018 and 2022.

The Utica Assets were operated by Utica Resource Operating, LLC (“Utica Resources”). PEO Ohio’s interest in the Utica Assets was held on an undivided basis and was roughly equivalent to 25% of the undivided interest owned by Utica Resources and its affiliate, Utica Resource Ventures, LLC.

Summary of Significant Accounting Policies

Basis of Presentation

The accompanying audited statements of revenues and direct operating expenses (the “financial statements”) include revenues from oil and gas production, as well as condensate and natural gas liquids, and direct operating expenses associated with the Utica Assets for the years ended December 31, 2022 and 2021. The revenues and direct operating expenses are derived from the historical operating statements obtained from Utica Resources and are presented on the accrual basis of accounting.

These financial statements vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America (“GAAP”) in that the financial statements do not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Utica Assets. The financial statements are not intended to be a complete presentation of the results of operations of the Utica Assets and may not be representative of future operations as they do not include indirect general and administrative expenses; interest expense; depreciation, depletion, and amortization expenses; provision for income taxes; and certain other revenues and expenses not directly associated with the Utica Assets.

Moreover, a balance sheet has not been presented because the Utica Assets were not accounted for as a separate segment, subsidiary of the parent entity, or division of Series D or PEO Ohio, and a complete set of financial statements are not available or practicable to produce. Accordingly, information regarding the Utica Assets’ operating, investing and financing cash flows has been omitted for similar reasons. As such, the statements of revenues and direct operating expenses of the Utica Assets are presented in lieu of the full set of financial statements required under Item 3-05 of SEC Regulation S-X. These financial statements do not reflect the anticipated operational outcome for the Utica Assets on a prospective basis.

Use of Estimates

The preparation of the financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the direct revenues and direct operating expenses reported herein. These estimates and assumptions are based on management’s best estimates and judgement. Actual results could differ from those estimates.

F-108

PEO Ohio, LLC

Ohio Appalachian Basin Working and Revenue Interests

Notes to Statements of Revenues and Direct Operating Expenses

For the Years Ended December 31, 2022 and 2021

Revenue Recognition

Revenues are primarily derived from the sale of oil, condensate, and natural gas production, as well as the sale of natural gas liquids (“NGLs”) that are extracted from the reserves essential to the Utica Assets in which PEO Ohio holds working and royalty interests. All sales of oil, condensate, natural gas, and NGLs are recognized when PEO Ohio satisfies a performance obligation by transferring control of a product to a customer. Revenue is typically recorded in the month of production based on an estimate of the Utica Assets’ share of volumes produced and prices realized. Sales of oil, condensate, natural gas, and NGLs as presented on the financial statements represent the Utica Assets’ share of revenues, including income from royalty interests owned by PEO Ohio, but excluding revenue relating to interests owned by other parties. The Utica Assets’ royalty income for the years ended December 31, 2022 and 2021 was not material.

Direct Operating Expenses

Direct operating expenses encompass the costs associated with the operational activities directly involved in the production operations of the Utica Assets. These expenses typically include expenditures related to routine and non-routine lease operating costs, operator general and administrative expenses, and production taxes. Lease operating expenses to produce wells include lifting costs, well repair expenses, facility maintenance expenses, well workover costs, and other field-related expenses. Lease operating expenses also included expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and gas production activities. Direct operating expense is recognized in the month it is incurred.

Income Taxes

PEO Ohio does not record a provision for U.S. federal, state, or local income taxes because its members report their share of the company’s income or loss on their income tax returns.

2. Contingencies

The Utica Assets record reserves for loss contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. The Utica Assets have no contingent liabilities at the reporting date.

3. Subsequent events

On October 4, 2023 (the “Closing Date”), PEO Ohio completed a divestiture of all of its interests in the Utica Assets to Wolf Run Operating, LLC for cash consideration of $55,907,915, after customary closing adjustments.

The financial statements were available for issuance on August 6, 2024. Subsequent events have been evaluated through that date and no events were identified that required adjustment or additional disclosure.

F-109

PEO Ohio, LLC

Ohio Appalachian Basin Working and Revenue Interest

Supplementary Oil and Gas Disclosures (Unaudited)

December 31, 2022 and 2021

Supplementary Oil and Gas Disclosures

Net Proved Developed and Undeveloped Oil and Gas Reserves

The following table of unaudited supplemental reserve information set forth the changes in quantities of the net proved developed and undeveloped oil and gas reserves attributable to the Utica Assets, as allocated by the respective contractual production participation interests for the years ended December 31, 2022 and 2021.

	Oil (MBbls)			Natural Gas (MMcf)			NGLs (MBbls)			Total (MBoe)
Net proved developed and undeveloped reserves at December 31, 2020		1,435			8,162			645			3,440
Proved developed reserves at December 31, 2020:		358			2,462			182			950
Proved undeveloped reserves at December 31, 2020:		1,077			5,699			463			2,490
Balance at January 1, 2021		1,435			8,162			645			3,440
Production		(110	)		(601	)		(45	)		(255	)
Revisions of previous estimates (1)		342			3,921			257			1,253
Net proved developed and undeveloped reserves at December 31, 2021		1,667			11,481			857			4,438
Proved developed reserves at December 31, 2021		399			3,880			304			1,350
Proved undeveloped reserves at December 31, 2021		1,268			7,601			553			3,088
Balance at January 1, 2022		1,667			11,481			857			4,438
Extensions (2)		652			3,641			296			1,555
Production		(177	)		(885	)		(61	)		(386	)
Revisions of previous estimates (3)		3			(1,348	)		(36	)		(258	)
Net proved developed and undeveloped reserves at December 31, 2022		2,145			12,889			1,056			5,349
Proved developed reserves at December 31, 2022		973			7,024			579			2,723
Proved undeveloped reserves at December 31, 2022		1,172			5,865			477			2,626

(1) Revisions of previous estimates. In 2021, total revisions to previous estimates increased proved reserves by 1.3 MMBoe. These upward revisions primarily consisted of positive revisions based on increases in pricing for the year ended December 31, 2021.

(2) Extensions. In 2022, total extensions to previous estimates increased proved reserves by 1.6 MMBoe. These extensions primarily related to the addition of four (4) proved undeveloped (“PUD”) locations to be developed by 2027 (as that year entered the 5-year development window) and converting unproved reserves to proved developed reserves. Specifically, three (3) proved developed producing (“PDP”) wells, one (1) proved developed nonproducing well, and three (3) PUD wells were added in the Beros unit and one (1) PDP well and (1) PUD well were added in the Rubel unit, for a total of eight (8) wells that were added to proved reserves during the year ended December 31, 2022.

(3) Revisions of previous estimates. In 2022, total revisions to previous estimates reduced proved reserves by 0.3 MMBoe. These downward revisions were primarily driven by lower forecasts for natural gas and NGLs reserves recovery.

Net proved reserves were calculated utilizing the twelve-month unweighted arithmetic average of the first-day- of-the-month price based on the respective benchmark price. The average price includes adjustments for heat content, crude handling, quality, and a regional price differential. Each year’s estimate of proved reserves were also prepared in accordance with then-current rules and guidelines established by the SEC and the Financial Accounting Standards Board.

See accompanying independent auditors’ report

F-110

PEO Ohio, LLC

Ohio Appalachian Basin Working and Revenue Interest

Supplementary Oil and Gas Disclosures (Unaudited)

December 31, 2022 and 2021

Proved oil and gas reserves are defined by the SEC Rule 4.10(a) of Regulation S-X as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recovered under current economic conditions, operating methods, and government regulations. Inherent uncertainties exist in estimating proved reserve quantities, projecting future production rates and timing of development expenditures.

Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgement. Because all reserve estimates are to some degree subjective, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may each differ from those assumed in these estimated oil and gas reserves attributable to the Utica Assets. Furthermore, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure of Discounted Future Net Cash Flows (“SMOG”) is computed by applying the 12- month unweighted average of the first-day-of-the-month pricing for oil and natural gas to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves. The average price includes adjustments for heat content, crude handling, quality, and a regional price differential. Estimated future production and development costs of proved reserves are based on current costs, assuming continuation of existing economic conditions. The estimated annual future net cash flows are discounted at a rate of 10%. As discussed in Note 1, the financial statements do not include provisions for income tax expense, therefore future income tax expense was omitted from the SMOG calculation.

The projections should not be interpreted as representing the fair value to the oil and natural gas reserves of the Utica Assets. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, anticipated future oil and natural gas prices, interest rates, changes in development and production costs, risks associated with future production, and consideration of expected future economic and operating conditions.

The following table reflect the standardized measure of discounted future net cash flows attributed to the proved oil and natural gas reserves:

	December 31,
	2022			2021
	(In thousands)
Future cash inflows	$	327,396		$	172,737
Future production costs		(56,450	)		(40,352	)
Future development costs(1)		(32,701	)		(25,014	)
Future net cash flows		238,245			107,371
10% annual discount for estimated timing of cash flows		(109,215	)		(53,922	)
Standardized measure of discounted future net cash flows related to proved reserves	$	129,030		$	53,449

(1) Future development costs include costs associated with the future abandonment of proved properties, including proved undeveloped locations.

See accompanying independent auditors’ report

F-111

PEO Ohio, LLC

Ohio Appalachian Basin Working and Revenue Interest

Supplementary Oil and Gas Disclosures (Unaudited)

December 31, 2022 and 2021

Changes in the Standardized Measure of Discounted Net Cash Flows

The principal sources of changes in the Standardized Measure of Discounted Future Net Cash Flows relating to prove oil and natural gas reserves are as follows:

	December 31,
	2022			2021
	(In thousands)
Balance, beginning of period	$	53,449		$	7,909
Net Sales of oil and gas produced during the period		(21,718	)		(8,549	)
Net change in prices and production (lifting) costs related to future production		45,715			26,490
Change in estimated future development costs		(8,491	)		(2,400	)
Previously estimated development costs incurred during the period		7,992			5,801
Net change due to extensions		42,633			—
Net change due to revisions in quantity estimates		(7,077	)		18,609
Accretion of discount		5,345			791
Change in timing and other		11,182			4,798
Standardized measure of discounted future net cash flows	$	129,030		$	53,449

See accompanying independent auditors’ report

F-112

PEO Ohio, LLC

Ohio Appalachian Basin Working and Revenue Interests

Statements of Revenues and Direct Operating Expenses

(Unaudited)

	Nine Months Ended
	September 30, 2023			September 30, 2022
Revenues
Crude oil		16,327,201			13,216,936
Natural gas liquids		1,953,402			2,320,422
Natural gas		1,896,844			4,455,787
Total revenues		20,177,447			19,993,145
Direct Operating Expenses		(3,840,209	)		(2,390,795	)
Excess of Revenues over Direct Operating Expenses	$	16,337,238		$	17,602,350

See accompanying notes to unaudited statements of revenues and direct operating expenses

F-113

PEO Ohio, LLC

Ohio Appalachian Basin Working and Revenue Interests

Notes to Unaudited Statements of Revenues and Direct Operating Expenses

For the Nine Months Ended September 30, 2023 and 2022

1. Nature of operations and summary of significant accounting policies

Organization and Nature of Operations

PEO Series D, LLC (“Series D”) was established for the principal purpose of investing in oil and gas- related properties and business through joint operations with third-party operators across the United States of America. Series D began its operations on July 16, 2018.

PEO Ohio, LLC (“PEO Ohio” or the “Company”), a wholly-owned subsidiary of Series D, holds ownership in non-operated working and revenue interests in various oil and gas properties, along with associated leasehold and infrastructure assets, situated in the Appalachian Basin in Guernsey, Morgan, Noble, and Washington Counties, Ohio (collectively referred as the “Utica Assets”). PEO Ohio acquired the Utica Assets through several acquisitions consummated between the periods ended September 30, 2023 and 2022.

The Utica Assets were operated by Utica Resource Operating, LLC (“Utica Resources”). PEO Ohio’s interest in the Utica Assets was held on an undivided basis and was roughly equivalent to 25% of the undivided interest owned by Utica Resources and its affiliate, Utica Resource Ventures, LLC.

Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited statements of revenues and direct operating expenses (the “financial statements”) include revenues from oil and gas production, as well as condensate and natural gas liquids, and direct operating expenses associated with the Utica Assets for the nine months ended September 30, 2023 and 2022. The revenues and direct operating expenses are derived from the historical operating statements obtained from Utica Resources and are presented on the accrual basis of accounting.

These financial statements vary from a complete income statement in accordance with accounting principles generally accepted in the United States of America (“GAAP”) in that the financial statements do not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Utica Assets. The financial statements are not intended to be a complete presentation of the results of operations of the Utica Assets and may not be representative of future operations as they do not include indirect general and administrative expenses; interest expense; depreciation, depletion, and amortization expenses; provision for income taxes; and certain other revenues and expenses not directly associated with the Utica Assets.

Moreover, a balance sheet has not been presented because the Utica Assets were not accounted for as a separate segment, subsidiary of the parent entity, or division of Series D or PEO Ohio, and a complete set of financial statements are not available or practicable to produce. Accordingly, information regarding the Utica Assets’ operating, investing and financing cash flows has been omitted for similar reasons. As such, the statements of revenues and direct operating expenses of the Utica Assets are presented in lieu of the full set of financial statements required under Item 3-05 of SEC Regulation S-X. These financial statements do not reflect the anticipated operational outcome for the Utica Assets moving forward.

Use of Estimates

The preparation of the financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the direct revenues and direct operating expenses reported herein. These estimates and assumptions are based on management’s best estimates and judgement. Actual results could differ from those estimates.

F-114

PEO Ohio, LLC

Ohio Appalachian Basin Working and Revenue Interests

Notes to Unaudited Statements of Revenues and Direct Operating Expenses

For the Nine Months Ended September 30, 2023 and 2022

Revenue Recognition

Revenues are primarily derived from the sale of oil, condensate, and natural gas production, as well as the sale of natural gas liquids (“NGLs”) that are extracted from the reserves essential to the Utica Assets in which PEO Ohio hold working and royalty interests. All sales of oil, condensate, natural gas, and NGLs are recognized when PEO Ohio satisfies a performance obligation by transferring control of a product to a customer. Revenue is typically recorded in the month of production based on an estimate of the Utica Assets’ share of volumes produced and prices realized. Sales of oil, condensate, natural gas, and NGLs as presented on the financial statements represent the Utica Assets’ share of revenues, including income from royalty interests owned by PEO Ohio, but excluding revenue interests owned by other parties. The Utica Assets’ royalty income for the nine months ended September 30, 2023 and 2022 was not material.

Direct Operating Expenses

Direct operating expenses encompass the costs associated with the operational activities directly involved in the production operations of the Utica Assets. These expenses typically include expenditures related to routine and non-routine lease operating costs, operator general and administrative expenses, and production taxes. Lease operating expenses to produce wells include lifting costs, well repair expenses, facility maintenance expenses, well workover costs, and other field-related expenses. Lease operating expenses also included expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and gas production activities. Direct operating expense is recognized in the month it is incurred.

Income Taxes

PEO Ohio does not record a provision for U.S. federal, state, or local income taxes because its members report their share of the company’s income or loss on their income tax returns.

2. Contingencies

The Utica Assets record reserves for loss contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. The Utica Assets have no contingent liabilities at the reporting date.

3. Subsequent events

On October 4, 2023 (the “Closing Date”), PEO Ohio completed a divestiture of all of its interests in the Utica Assets to Wolf Run Operating LLC for cash consideration of $55,907,915, after customary closing adjustments.

The financial statements were available for issuance on August 6, 2024. Subsequent events have been evaluated through that date and no events were identified that required adjustment or additional disclosure.

F-115

13,250,000 Shares

Infinity Natural Resources, Inc.

Class A Common Stock

PROSPECTUS

CITIGROUP

RAYMOND JAMES

RBC CAPITAL MARKETS

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BTIG

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January 30, 2025

Through and including February 24, 2025 (the 25th day after the date of this prospectus), all dealers effecting transactions in our shares, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.