As filed with the Securities and Exchange Commission on May 11, 2026.

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

WhiteHawk Income Corporation

(Exact name of registrant as specified in its charter)*

* WhiteHawk Income Corporation to be renamed WhiteHawk Minerals Corp. in connection with the consummation of this offering.

Delaware

1311

88-0862160

(State or Other Jurisdiction of

Incorporation or Organization)

(Primary Standard Industrial

Classification Code Number)

(I.R.S. Employer

Identification Number)

2000 Market Street, Suite 910

Philadelphia, PA 19103

(610) 484-3412

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

Daniel Herz

Chief Executive Officer

2000 Market Street, Suite 910

Philadelphia, PA 19103

(610) 484-3412

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent For Service)

Copies to:

Ryan J. Maierson
Christopher D. Lueking
Nick S. Dhesi
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, TX 77002
(713) 546-5400

Barrie Hananel
General Counsel
2000 Market Street, Suite 910
Philadelphia, PA 19103
(610) 484-3412

Douglas E. McWilliams
Thomas G. Zentner

Alexandra M. Lewis
Vinson & Elkins L.L.P.

845 Texas Avenue, Suite 4700

Houston, TX 77002
(713) 758-2222

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

PRELIMINARY PROSPECTUS

Subject to Completion, Dated May 11, 2026.

LOGO

WhiteHawk Income Corporation

(to be renamed WhiteHawk Minerals Corp.)

Shares

Class A Common Stock

This is the initial public offering of shares of our Class A common stock. We are offering shares of our Class A common stock.

Prior to this offering, there has been no public market for our common stock. The initial public offering price of our common stock is expected to be between $ and $ per share. We intend to apply to list our common stock on the New York Stock Exchange (“NYSE”) under the symbol “WHK.” We intend to change our corporate name to WhiteHawk Minerals Corp. in connection with the closing of this offering. See “Prospectus Summary—Summary of the Transactions” and “Our Organizational Structure.”

To the extent that the underwriters sell more than shares of common stock, the underwriters have the option to purchase, exercisable within 30 days from the date of this prospectus, up to an additional shares from us at the public offering price, less underwriting discounts and commissions.

Upon consummation of this offering, we will be a holding company in an organizational structure commonly referred to as an umbrella partnership-C-corporation (or “Up-C”) structure, and our principal assets will consist of (i) direct ownership of % of the common units (“OpCo Interests”) of WhiteHawk Income Operating Partnership L.P. (“WhiteHawk OpCo”) (or approximately % of the OpCo Interests if the underwriters exercise in full their option to purchase additional shares of Class A common stock), which entitle us to a corresponding percentage ownership of the economic interest in WhiteHawk OpCo, and (ii) all of the member interests of WhiteHawk Income OP GP LLC (“OP GP”), the sole general partner of WhiteHawk OpCo, which entitles us to control the business and affairs of WhiteHawk OpCo. See “Risk Factors—Risks Related to Our Capital Structure.” We will operate and control all of the business and affairs of WhiteHawk OpCo and its direct and indirect subsidiaries, and conduct our business through WhiteHawk OpCo. In addition, we will own all of the Series B preferred units of WhiteHawk OpCo.

Following this offering, we will have two series of authorized common stock: shares of Class A common stock, having one vote per share and economic rights, and shares of Class B common stock, having one vote per share and no economic rights (collectively, the “Common Stock”). Holders of Class A and Class B common stock will vote together as a single class on all matters to be presented to our shareholders for their vote or approval, except as otherwise required by applicable law or our Bylaws (as defined herein). Our outstanding Class A common stock and Class B common stock will represent approximately % and %, respectively, of the total voting power of our outstanding Common Stock immediately following this offering, assuming no exercise of the underwriters’ option to purchase additional shares of Class A common stock. See “Description of Capital Stock” and “Our Organizational Structure.”

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

Investing in our Class A common stock involves risks. See “Risk Factors” starting on page 34.

Price to Public

Underwriting
Discounts and
Commissions⁽¹⁾

Proceeds to
Issuer

Per Share

Total

(1)	See “Underwriting” for additional information regarding underwriter compensation.

Delivery of the shares of Class A common stock will be made on or about , 2026.

Neither the Securities and Exchange Commission (the “SEC”) nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Joint Lead Bookrunners


Raymond James		Stifel		J.P. Morgan

Bookrunning Managers


Capital One Securities				Stephens Inc.

Prospectus dated , 2026

LOGO

Building the Premier Natural Gas Mineral Company APPALACHIA HAYNESVILLE EQTANTE RORAN GECNX EXPAND OTHER EXPAND MITS UBIS HI COM STOCK TRINITY TOKYO GAS OTHER APPALACHIA & HAYNESVILLE MAP 8,700+ gross undeveloped locations 10,000+ producing wells ~13% exposure to all 2025 U.S. dry gas production 8 large acquisitions since inception 3.4MM+ gross DSU acre position 2025 PRODUCTION EXPOSURE BY OPERATOR 86452-044 07May26 20:02 Page 3

TABLE OF CONTENTS


	Page
ABOUT THIS PROSPECTUS		iii
PROSPECTUS SUMMARY		1
RISK FACTORS		34
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		76
OUR ORGANIZATIONAL STRUCTURE		79
USE OF PROCEEDS		83
DIVIDEND POLICY		84
CAPITALIZATION		85
DILUTION		87
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED FINANCIAL INFORMATION		89
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		95
BUSINESS		110
MANAGEMENT		141
EXECUTIVE AND DIRECTOR COMPENSATION		146
PRINCIPAL STOCKHOLDERS		155
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		157
DESCRIPTION OF MATERIAL INDEBTEDNESS		167
DESCRIPTION OF CAPITAL STOCK		174
SHARES ELIGIBLE FOR FUTURE SALE		182
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS OF COMMON STOCK		184
UNDERWRITING		188
LEGAL MATTERS		196
EXPERTS		196
CHANGE IN INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		197
WHERE YOU CAN FIND MORE INFORMATION		198
INDEX TO FINANCIAL STATEMENTS		F-1
ANNEX A – GLOSSARY OF NATURAL GAS AND OIL TERMS		A-1

You should rely only on the information contained in this prospectus or in any free writing prospectus we may specifically authorize to be delivered or made available to you. Neither we nor any of the underwriters (or any of our or their respective affiliates) have authorized anyone to provide 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 or to which we have referred you. Neither we nor the underwriters (or any of our or their respective affiliates) take any responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. This prospectus is an offer to sell only the shares of Class A common stock offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. You should assume that the information contained in this prospectus or any free writing prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or the time of any sale of shares of our Class A common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

For investors outside the United States: Neither we nor any of the underwriters have done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction where action for that purpose is required, other than in the United States. Persons outside of the United States who come into possession of this prospectus must inform themselves about, and observe any restrictions relating to, the offering of the shares of our Class A common stock and the distribution of this prospectus outside of the United States.

Through and including , 2026 (25 days after the date of this prospectus), all dealers effecting transactions in our Class A common stock, 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.

ABOUT THIS PROSPECTUS

Organizational Structure

In connection with the closing of this offering, we will undertake certain organizational transactions to reorganize our corporate structure. Unless otherwise stated or the context otherwise requires, all information in this prospectus reflects the consummation of the organizational transactions described in the section titled “Our Organizational Structure” and this offering, and the application of the proceeds therefrom, which we refer to collectively as the “Transactions.” Additionally, unless otherwise indicated, share amounts in this prospectus reflecting the consummation of the Transactions do not give effect to OpCo Interests or shares of our Class B common stock that may be issued as a part of the Earnout Amount (as defined herein), as more fully described in the section titled “Certain Relationships and Related Party Transactions—Internalization—Earnout.”

See “Our Organizational Structure” for a diagram depicting our organizational structure after giving effect to the Transactions, including this offering.

Certain Definitions

As used in this prospectus, unless the context otherwise requires, references to:

•

“Contribution Agreement” refers to the contribution agreement we will enter into with WhiteHawk OpCo, the Management Contributor, ManagementCo, WhiteHawk Energy LLC and WhiteHawk Energy Services LLC to effectuate the acquisition of ManagementCo, our current external manager, by WhiteHawk OpCo (the “Internalization”).

•

“Continuing Equity Owners” refers collectively to the Management Owners who will be holders of OpCo Interests (together with a corresponding number of shares of Class B common stock) immediately following consummation of the Transactions, who may, following the consummation of this offering, exchange at each of their respective options, in whole or in part from time to time, their OpCo Interests (together with a corresponding number of shares of Class B common stock), for, at our election (determined solely by our independent directors (within the meaning of the NYSE rules) who are disinterested), cash or newly-issued shares of our Class A common stock as described in “Certain Relationships and Related Person Transactions—OpCo Agreement—Agreement in Effect Upon Consummation of the Transactions.”

•

“Exchange” or “NYSE” refers to the New York Stock Exchange.

•

“Legacy Common Stock Investors” refers, collectively, to the holders of shares of Class A common stock, par value $0.0001 per share, Class I common stock, par value $0.0001 per share, and Class T common stock, par value $0.0001 per share, but excludes Continuing Equity Owners.

•

“OpCo Interests” refers to the common units of WhiteHawk Income Operating Partnership L.P., including those that we purchase with the net proceeds from this offering.

•

“Management Contributor” refers to WhiteHawk Minerals LLC.

•

“Management Owners” refers collectively to the direct and indirect owners of WhiteHawk Management, LLC (“ManagementCo”, “WHIC Manager” or “WhiteHawk Management”) prior to the consummation of the Transactions). Management Owners may also be Continuing Equity Owners. See “Certain Relationships and Related Person Transactions—Contribution Agreement.”

•

“OpCo Agreement” refers, as applicable, to WhiteHawk OpCo’s amended and restated limited partnership agreement, as currently in effect, or to the amended and restated limited partnership agreement effective immediately prior to the consummation of this offering, and as such agreement may thereafter be amended and/or restated.

•

“Transactions” refers to the organizational transactions described in the section titled “Our Organizational Structure” and this offering, and the application of the net proceeds therefrom.

iii

•

“we,” “us,” “our,” the “Company,” “WhiteHawk,” and similar references refer to, prior to this offering, WhiteHawk Income Corporation, and after this offering, WhiteHawk Minerals Corp., and, unless otherwise stated, in each case, all of its direct and indirect subsidiaries, including OP GP and WhiteHawk OpCo.

We are a holding company and the sole member of WhiteHawk Income OP GP LLC (“OP GP”), the sole general partner of WhiteHawk OpCo. As the sole member of OP GP, we control the business and affairs of WhiteHawk OpCo.

Presentation of Financial Results

WhiteHawk Income Corporation (“WhiteHawk,” the “Company,” “we,” “us” and “our”) was formed in February 2022. On June 23, 2025, pursuant to that certain Agreement and Plan of Merger, dated as of May 8, 2025 (the “PHX Merger Agreement”), by and among WhiteHawk Acquisition, Inc., a Delaware corporation and wholly owned subsidiary of the Company (“WH Acquisition Corp.”), WhiteHawk Merger Sub, Inc., a Delaware corporation (“Merger Sub” and, together with WH Acquisition Corp., the “Company Parties”) and PHX Minerals, Inc. (“PHX”), the Company Parties fully acquired all of the issued and outstanding shares of PHX’s common stock (the “PHX Acquisition”). On March 31, 2025, the Company purchased mineral and royalty interests in the Marcellus Shale (the “Three Rivers Royalty Acquisition” or the “TRR Acquisition”) from Three Rivers Royalty, LLC (the “TRR Seller”). Prior to the Three Rivers Royalty Acquisition, the TRR Seller was a wholly owned subsidiary of San Jacinto Minerals I, LLC (“SJM”).

This prospectus includes historical consolidated financial information of the Company and its subsidiaries as of December 31, 2025 (as restated) and 2024. This prospectus also includes historical financial information of PHX for the years ended December 31, 2024 and 2023 and the three months ended March 31, 2025 and 2024, as well as the carve-out financial statement information of the TRR Seller for the years ended December 31, 2024 and 2023. Historical financial and operating information is not indicative of the results that may be expected in any future periods. For more information, please see the historical consolidated financial statements and related notes thereto included elsewhere in this prospectus. Unless otherwise indicated, the historical financial information presented in this prospectus represents the historical data and information of WhiteHawk, without giving effect to the PHX Acquisition for periods prior to June 23, 2025, the Three Rivers Royalty Acquisition for periods prior to March 31, 2025, the Transactions or other adjustments.

This prospectus also includes certain unaudited pro forma financial information. See “Unaudited Pro Forma Condensed Consolidated Combined Financial Information.” As used herein, except as noted in this prospectus, the term “pro forma” when used with respect to any financial data, refers to the historical data of WhiteHawk, as adjusted after giving effect to (i) the PHX Acquisition, (ii) the Three Rivers Royalty Acquisition and (iii) the Transactions. Pro forma financial data for the year ended December 31, 2025 gives effect to the PHX Acquisition, the Three Rivers Royalty Acquisition and the Transactions as if each had been consummated on January 1, 2025. Pro forma financial data as of December 31, 2025 gives effect to the Transactions as if they had been consummated on December 31, 2025. Pro forma financial data contains certain reclassification adjustments to conform the historical PHX financial statement presentation and the historical TRR Seller financial statement presentation to the Company’s financial statement presentation. The pro forma data is presented for illustrative purposes only and should not be relied upon as an indication of the financial condition or the operating results that would have been achieved if the PHX Acquisition, the Three Rivers Royalty Acquisition and the Transactions had taken place on the specified dates. Future results may vary significantly from the results reflected in such pro forma financial data and should not be relied on as an indication of future results.

Certain monetary amounts, percentages and other figures included in this prospectus have been subject to rounding adjustments. Percentage amounts included in this prospectus have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, percentage amounts in this prospectus may vary from those obtained by performing the same calculations using the figures

in our consolidated financial statements included elsewhere in this prospectus. Certain other amounts that appear in this prospectus may not sum due to rounding.

Restatement

On April 22, 2026, we concluded that our audited consolidated financial statements for the fiscal year ended December 31, 2025 could no longer be relied upon as a result of certain material accounting errors identified by management subsequent to the issuance of our audited consolidated financial statements as of and for the fiscal year ended December 31, 2025. Accordingly, the audited consolidated financial statements as of and for the fiscal year ended December 31, 2025 included elsewhere in this prospectus were restated by the Company in order to reflect the correction of the identified errors (the “Misstatements”) related to (i) the recording of management fees and (ii) the misclassification of pre-closing date and post-effective date monies received related to acquisitions (the “Restatement”). For additional information, see “Note 3, Restatement of Financial Statements” to our audited consolidated financial statements as of and for the fiscal year ended December 31, 2025 included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Internal Controls and Procedures—Material Weaknesses in Internal Control over Financial Reporting.”

Control Considerations

Although management did not, and was not required to, conduct a formal assessment of internal control over financial reporting as of December 31, 2025, as a result of the Misstatements and the Restatement, the Company identified certain material weaknesses in its internal control over financial reporting. As a result of these material weaknesses in internal control over financial reporting, our disclosure controls and procedures were not effective at a reasonable assurance level as of December 31, 2025. Management expects to implement changes to strengthen our internal controls and remediate the material weaknesses. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Internal Controls and Procedures—Material Weaknesses in Internal Control over Financial Reporting” for additional information related to the material weaknesses in internal control over financial reporting and our related remediation activities. See “Risk Factors—Risks Related to Our Business—We recently restated our audited consolidated financial statements as of and for the fiscal year ended December 31, 2025 to correct material accounting errors and have identified material weaknesses in our internal control over financial reporting.”

Reserves Estimates and Acreage Presentation

Unless otherwise indicated, operating and reserve information of the Company presented herein does not give effect to the PHX Acquisition or the Three Rivers Royalty Acquisition for the periods prior to the date of such transactions. We provide estimates of our proved reserves in this prospectus as of December 31, 2025 and 2024 based on SEC pricing, meaning the unweighted first day of the month arithmetic average price of natural gas and oil over the 12 months prior to the determination date. The estimates of our proved reserves as of December 31, 2025 were prepared by Cawley, Gillespie & Associates (“CG&A”), independent petroleum engineers. The estimates of our proved reserves as of December 31, 2024 have been prepared by Schaper Energy Consulting, LLC (“Schaper Energy”), independent petroleum engineers. We refer to Schaper Energy and CG&A as our “reserve engineers.” Summaries of their reports are included as exhibits to the registration statement of which this prospectus forms a part. We refer to such reports herein as “our reserve reports.” The estimates of PHX’s proved reserves as of December 31, 2024 were prepared by CG&A, PHX’s independent petroleum engineer. The estimates of the proved reserves of the TRR Seller as of December 31, 2024 have been prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the TRR Seller’s independent petroleum engineer, at the request of SJM as part of their audit process. For additional information regarding our, PHX’s and TRR Seller’s reserves estimates as of December 31, 2025 and 2024, see “Business—Natural Gas, NGL and Oil Data.”

In this prospectus, references to gross DSU acres include both actual and theoretical DSUs. Theoretical DSUs are drilling spacing units that have not yet been formally established but are internally delineated by our engineering

and land teams based on operator unitization practices, development patterns in the surrounding area and our reasonable assumptions regarding future well development.

Non-GAAP Financial Measures

This prospectus contains certain financial measures that are not required by or prepared in accordance with generally accepted accounting principles (“GAAP”), including Adjusted EBITDA and Cash Available for Distribution (and their pro forma counterparts). We refer to these measures as “non-GAAP financial measures.” See “Prospectus Summary—Summary Historical and Pro Forma Condensed Consolidated Financial and Other Data—Non-GAAP Financial Measures” for our definitions of these non-GAAP financial measures, information about how and why we use these non-GAAP financial measures and a reconciliation of each of these non-GAAP financial measures to its most directly comparable financial measure calculated in accordance with GAAP.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. 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 us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the TM, SM or ^® 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 right of the applicable licensor to these trademarks, service marks and trade names.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. These sources include reports entitled: Electric Power Monthly, dated December 2025, (the “EIA Electric Monthly”), Short-Term Energy Outlook, dated December 2025 (the “EIA Short-Term Energy Outlook”), Natural Gas Annual, dated December 2025 (the “EIA Natural Gas Annual”), the Liquefied Natural Gas Monthly, dated December 2025 (the “EIA Natural Gas Monthly”), the Annual Report of Domestic Oil and Gas Reserves, U.S. Crude Oil and Natural Gas Proved Reserves, Year-end 2023, dated December 2025 (the “EIA Reserve Report”), Liquefied U.S. Natural Gas Exports, dated December 2025 (the “EIA Natural Gas Exports”), U.S. Liquefaction Capacity, dated December 2025 (the “EIA Liquefaction Report”), by the Energy Information Administration (the “EIA”), a report entitled 2024 Statistical Review of World Energy (the “World Energy Report”) by the Energy Institute, FactSet International LNG Pricing, dated January 2025 (the “International LNG Report”), FactSet Spot Price, dated December 2025 (the “Spot Price Report”) and Upstream Outlook, dated December 2025 (the “Upstream Outlook Report”) by FactSet, as well as data and analytics derived from Enverus Prism^®, dated December 31, 2025 (the “Enverus Data”). Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Additionally, this prospectus includes industry and market data and forecasts that we obtained from internal company surveys, publicly available information and industry publications and surveys. Our internal research and forecasts are based on management’s understanding of industry conditions, and such information has not been verified by independent sources. Industry publications and surveys generally state that the information contained therein has been obtained from sources believed to be reliable.

PROSPECTUS SUMMARY

This summary highlights certain significant aspects of our business and this offering. This is a summary of information contained elsewhere in this prospectus, is not complete and does not contain all of the information that you should consider before making your investment decision. You should carefully read the entire prospectus, including the information presented under the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” and the consolidated financial statements and related notes thereto, before making an investment decision. This summary contains forward-looking statements that involve risks and uncertainties. Unless the context requires otherwise, references to “our company,” “we,” “us,” “our,” and “WhiteHawk” refer to WhiteHawk Income Corporation and its direct and indirect subsidiaries on a consolidated basis prior to this offering, and WhiteHawk Minerals Corp. and its direct and indirect subsidiaries on a consolidated basis following this offering. This prospectus includes certain terms commonly used in the natural gas and oil industry, which are defined elsewhere in this prospectus in the “Glossary of Natural Gas and Oil Terms” contained in Annex A to this prospectus.

The estimates of our proved reserves as of December 31, 2025 have been prepared by CG&A, our independent reserve engineers. CG&A’s report is included as an exhibit to the registration statement of which this prospectus forms a part. The estimates of our proved reserves as of December 31, 2024 have been prepared by Schaper Energy, our independent reserve engineers. Schaper Energy’s report is included as an exhibit to the registration statement of which this prospectus forms a part. The estimates of PHX’s (as defined herein) proved reserves as of December 31, 2024 have been prepared by CG&A, PHX’s independent reserve engineers. CG&A’s report is included as an exhibit to the registration statement of which this prospectus forms a part. The estimates of the TRR Seller’s proved reserves as of December 31, 2024 have been prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the TRR Seller’s independent reserve engineers. Ryder Scott’s report is included as an exhibit to this registration statement of which this prospectus forms a part.

Our Company

WhiteHawk is focused on being the premier natural gas mineral and royalty business in the United States. We are committed to delivering cash flow and total returns to our investors through the disciplined acquisition, active management and ownership of high-quality mineral and royalty interests. Our assets are concentrated in the Marcellus and Haynesville Shales, which are located in the Appalachian and Haynesville Basins, which are among the most productive and lowest-cost U.S. natural gas basins.¹ Upon completion of the offering, we will own the largest, high-quality publicly traded natural gas mineral portfolio in the United States.² As a mineral and royalty business, we do not pay any drilling-related capital expenditures and only minimal operating expenses on our properties. This results in a high-margin business and allows us to distribute a meaningful portion of our cash flow to investors, while providing them with potential for significant capital appreciation over time.

¹	EIA Short-Term Energy Outlook; Enverus Data.

²	Based upon management’s review of public filings with the SEC, excluding those companies which either derive a majority of their revenue from oil or are oil and NGL weighted in production.

³	Enverus Data.

approximately 33 Bcf/d, and the Haynesville Basin would rank eighth with daily production of approximately 13 Bcf/d.⁴ In 2025, the Appalachian and Haynesville Basins together accounted for more than 50%⁵ of total U.S. dry gas production, providing the foundation of domestic natural gas supply and export growth. Our mineral interests are concentrated in the core of these premier natural gas regions and offer long-term participation in two of the largest, most active and lowest-cost natural gas weighted basins in the United States.⁶

WhiteHawk’s mineral interests are developed by many of the largest, most active and well-capitalized natural gas operators in the United States, including EQT (NYSE: EQT), Range Resources (NYSE: RRC), CNX Resources (NYSE: CNX), Antero Resources (NYSE: AR), Expand Energy (NASDAQ: EXE), Comstock Resources (NYSE: CRK) and Aethon Energy. In 2025, approximately 18%⁷ of all wells drilled in the Appalachian and Haynesville Basins were located on acreage in which we hold royalty interests. Our significant footprint across both basins provides alignment and scale with these premier operators. In 2025, EQT was the largest natural gas producer in the Appalachian Basin, and Expand Energy was the largest producer in the Haynesville Basin.⁸ In the same year, approximately 49% of EQT’s Appalachian production and 57% of Expand Energy’s Haynesville production were sourced from acreage in which we hold royalty interests.⁹ Because our mineral interests are concentrated within these operators’ active and planned development areas, we can benefit directly from their scale, financial strength and efficiency. Our exposure to leading operators enables us to gain from their continuous development across commodity cycles and provides a resilient base for predictable cash flow growth.

Leveraging our scale and position alongside leading operators, we believe we are well positioned to capitalize on two powerful natural gas demand catalysts: artificial intelligence (“AI”) driven electricity demand growth and expanding U.S. liquefied natural gas (“LNG”) exports. Natural gas remains the most reliable, scalable and cost-effective source of baseload power and accounted for approximately 41%¹⁰ of total U.S. electricity generation in 2025. The rapid buildout of AI and cloud-computing infrastructure is projected to create additional demand for natural gas-fired power generation, with a management-estimated 7.8 Bcf/d of total natural gas demand associated with new power plants expected to be constructed by 2031,¹¹ largely within WhiteHawk’s Appalachian Basin footprint. In addition to an increase in domestic demand, global demand for U.S. natural gas is expected to further accelerate through LNG export growth. The EIA projects the United States will nearly double its LNG export capacity from approximately 17 Bcf/d¹² in 2025 to nearly 34 Bcf/d by 2031¹³ as European and Asian buyers seek to diversify supply and reduce exposure to higher regional benchmark prices. The Haynesville Basin’s proximity and pipeline connectivity to the Gulf Coast LNG corridor position our mineral interests to benefit directly from this expansion in export capacity and feed-gas demand. Together, accelerating power demand from AI and the continued buildout of LNG export capacity, inclusive of announced projects, are expected to drive a structural step-change in U.S. natural gas demand—driving roughly a 36%¹⁴ increase in combined demand by 2031 compared to 2025 levels. WhiteHawk believes it offers public investors direct equity exposure to the powerful tailwinds of AI-driven power demand and expanding U.S. LNG exports without drilling-related capital expenditures.

⁴	World Energy Report.

⁵	EIA Short-Term Energy Outlook.

⁶	Enverus Data.

⁷	Enverus Data.

⁸	Enverus Data.

⁹	Enverus Data.

¹⁰	EIA Electric Monthly.

¹¹	Assumes 1 gigawatt of capacity equates to 154 mmcf/d of natural gas demand.

¹²	EIA Natural Gas Exports.

¹³	EIA Electric Monthly. Includes current operating and under construction projects only.

¹⁴	EIA Natural Gas Monthly.

over $31 billion of energy transactions across the upstream, midstream, and minerals and royalty value chain. Members of our team previously served as senior executives or founders of Atlas Energy (NYSE: ATLS), Atlas Pipeline Partners (NYSE: APL) and Falcon Minerals Corporation (NASDAQ: FLMN), each of which were successful public companies that generated substantial shareholder value through disciplined growth, accretive acquisitions and strategic monetizations.

Since its inception, WhiteHawk has completed eight large acquisitions, making it the most active acquirer of natural gas mineral and royalty properties in the United States.¹⁵ More importantly, these acquisitions have been highly accretive to shareholders and have resulted in approximately 36%¹⁶ cash-on-cash return to our initial investors through 46 months of consecutive cash dividend payments, plus an additional 41% increase in shareholder value through three share dividends through January 1, 2026. We continue to execute a focused consolidation strategy in a fragmented market, targeting accretive acquisitions to expand scale, enhance returns and extend development visibility. Our ability to consistently source, evaluate and close accretive transactions ahead of broader market consolidation underscores WhiteHawk’s leadership as a focused, data-driven consolidator with a proven track record of value creation.

Our History

We were founded in 2022 with a clear mission to build the premier natural gas minerals and royalty platform. Our thesis was that natural gas minerals and royalties represent one of the most efficient and resilient ways to participate in the energy value chain, combining high-margin cash yield with exposure to long-term macro tailwinds in U.S. natural gas demand.

We began executing on a strategy to consolidate high-quality, core-basin mineral and royalty assets from institutional and private equity owners. We identified an estimated $3 – $5 billion of natural gas minerals and royalties in the Appalachian and Haynesville Basins that were held by private equity funds nearing the end of their investment cycles and fund lives with few buyers of scale in the market. This imbalance created an attractive entry point to acquire premium assets at compelling valuations. WhiteHawk was created to capitalize on this opportunity, bringing technical expertise, public market experience and fresh capital to a fragmented sector.

In addition to our strategic acquisitions of larger, consolidated natural gas mineral packages, we launched a dedicated “ground game” in 2025 that has become an important component of our growth strategy. This approach builds on a meaningful track record, including at Falcon Minerals Corporation, where our team successfully executed more than 30 acquisitions through a similar strategy. Leveraging significant in-house land and engineering expertise alongside an established network of regional brokers, we seek to efficiently source and underwrite smaller-scale opportunities that we believe are highly accretive. Since December 2025, we have completed 14 such transactions totaling approximately $39.7 million. We expect the ground game to remain a component of our acquisition strategy, with the goal of adding scale consistent with our existing portfolio quality.

This opportunity may be enhanced by the fragmentation across our existing asset base. With an average net revenue interest of approximately 0.48% across our DSUs and an average royalty rate of approximately 17% as of December 31, 2025, we believe there is more than 33 times our current ownership potentially available for acquisition within our existing footprint.

¹⁵	Enverus Data.

¹⁶	Reflects a cash-on-cash return to our initial investors whose share price did not include any selling commissions on investment. Returns to our initial investors whose share price included selling commissions on investment resulted in cash-on-cash returns of approximately 33%.

As of December 31, 2025, WhiteHawk has accumulated natural gas mineral and royalty assets across approximately 3.4 million gross DSU acres focused primarily on the Appalachian and Haynesville Basins. From our inception in 2022 through 2025, WhiteHawk has made seven acquisitions and has paid more than 46 consecutive monthly cash dividends, representing approximately 36%¹⁷ cash-on-cash return to our initial investors, plus an additional 41% increase in shareholder value through three share dividends through January 1, 2026.

The figure below summarizes our acquisition history with respect to acquired net royalty acres on an 8/8^th basis (“NRAs”).

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Members of our management team were some of the early pioneers in the Marcellus Shale and, prior to the formation of WhiteHawk, collectively drilled some of the first horizontal wells in the Marcellus Shale. With over 20 years of Appalachian Basin-specific experience, our land and engineering teams specialize in identifying and acquiring high-quality land assets that underpin valuable, long-term mineral and royalty interests. This technical capability, combined with our extensive history of operating in Appalachia, proprietary deal sourcing, and data-driven analysis, allows WhiteHawk to efficiently negotiate and close transactions while maintaining disciplined capital allocation. In addition to utilizing technical analysis, we strive to acquire mineral and royalty interests in properties with top-tier E&P operators. We seek E&P operators that are well-capitalized, have a strong operational track record, and we believe will continue to increase production through the application of the latest drilling and completion techniques across our mineral and royalty interests, and have demonstrated resilience through commodity cycles.

The U.S. natural gas minerals and royalties market remains highly fragmented with many private owners and few scaled aggregators. This structural fragmentation presents a significant opportunity for continued consolidation. WhiteHawk is one of the few active, large mineral buyers focused exclusively on natural gas. Upon completion of this offering, WhiteHawk will be the only public natural gas mineral and royalty company with meaningful, scaled exposure to the Appalachian and Haynesville Basins, allowing WhiteHawk to capitalize on this fragmented market.¹⁸ We intend to leverage our position to pursue disciplined, accretive acquisitions that enhance portfolio quality, expand our footprint in premier basins, and drive sustainable growth in cash flow and shareholder returns over time.

¹⁷	Reflects a cash-on-cash return to our initial investors whose share price did not include any selling commissions on investment. Returns to our initial investors whose share price included selling commissions on investment resulted in cash-on-cash returns of approximately 33%.

¹⁸	Based upon management’s review of public filings with the SEC, excluding those companies which either derive a majority of their revenue from oil or are oil and NGL weighted in production.

Natural Gas Industry and Future Development

Natural gas is the largest source of U.S. electricity generation and a cornerstone of global energy supply, accounting for approximately 41%¹⁹ of total domestic power output in 2025. U.S. natural gas demand has the potential to increase from 107 Bcf/d in 2025 to approximately 148 Bcf/d by 2031, supported by structural growth across LNG exports, power generation expansion, rising electricity demand from data centers and AI, and advanced manufacturing.²⁰

U.S. LNG export capacity could expand to around 45 Bcf/d by 2031, supported by approximately 34 Bcf/d currently operating or under construction and an additional 11 Bcf/d of capacity announced but not currently under construction²¹. If all export capacity is active by 2031, this would represent a 28% increase in natural gas demand over 2025 levels from LNG exports alone. The continued growth in LNG exports is expected to position the United States as the world’s leading supplier of natural gas to Europe and Asia as international buyers seek secure, competitively priced and transparent alternatives to oil-indexed or regional benchmarks.

The figure below illustrates estimated liquefaction capacity for existing, under construction and announced projects as of December 2025:

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Note: Liquefaction Capacity reflects Peak Nameplate Capacity. Commercial Operation includes commissioned projects. Source: EIA Liquefaction Report.

Additionally, as of December 2025, WhiteHawk has identified 21 publicly announced new or planned natural gas power plants in close proximity to WhiteHawk’s Appalachia mineral position, which are estimated to generate natural gas demand of approximately 7.8 Bcf/d by 2031.²²

¹⁹	EIA Electric Monthly.

²⁰	Management estimated based on EIA Short-Term Energy Outlook.

²¹	EIA Liquefaction Report as supplemented by management’s review of recently announced facilities.

²²	Assumes 1 gigawatt of capacity equates to 154 mmcf/d of natural gas demand.

WhiteHawk’s mineral position in the Appalachian Basin lies in close proximity to major data center growth corridors across Virginia, Ohio and Pennsylvania, where WhiteHawk has identified, as of December 2025, publicly announced 28 new data centers representing what management estimates will generate 3.3 Bcf/d of incremental natural gas demand, of which approximately 1.7 Bcf/d is under construction or has achieved FID and approximately 1.6 Bcf/d is in pre-FID and announced stages.²³

Together, these structural demand drivers are expected to sustain drilling and development activity on WhiteHawk’s mineral acreage for years to come. With concentrated exposure to some of the most productive natural gas basins in the United States, we believe our mineral and royalty portfolio is well positioned to deliver stable production growth, increase royalty income and durable cash flow, and grow dividends and net asset value per share over the long term.

Our Focus on Key Gas Basins

WhiteHawk’s assets are concentrated in the Appalachian Basin and Haynesville Basin, which collectively represent the core of U.S. natural gas production. Each region combines substantial resource depth, high-quality operators, and access to major infrastructure and end-markets.

Appalachian Basin (Pennsylvania / West Virginia / Ohio)

The Appalachian Basin, located primarily in Pennsylvania, West Virginia and Ohio, constitutes the largest and most prolific natural gas basin in the United States and a critical source of future global natural gas supply, as of December 2025.²⁴ The basin’s scale, consistent reservoir quality and access to infrastructure have made it a cornerstone of U.S. natural gas production and a key driver of the nation’s transition toward cleaner, lower-carbon energy. The Appalachian Basin’s importance to future natural gas growth is underpinned by its vast remaining resource potential and direct connectivity to both domestic and international demand. The basin benefits from an extensive network of gathering, processing and long-haul pipeline infrastructure that links production to major population centers and growing data center markets in the Northeast, Midwest and Northern Virginia, as well as to LNG export markets along the Gulf Coast. Continued expansion of southbound takeaway capacity and LNG facilities is expected to reinforce the region’s role as a primary growth engine for U.S. natural gas supply over the next decade.

In the Appalachian Basin, the Marcellus Shale has transformed the United States from a net importer to a net exporter of natural gas over the past 20 years. During 2025, it accounted for roughly one-third of total U.S. dry gas production, producing at some of the lowest breakeven costs in the United States.²⁵ Exceptional pressure regimes, thick, laterally continuous pay zones and modern completion techniques allow operators to achieve recoveries and sustained productivity that rank among the highest in the industry.²⁶ The Utica Shale provides additional stacked-pay potential that enhances the economic life and development diversity of the basin and already accounted for 8% of total U.S. natural gas production in 2025.²⁷

As of December 31, 2025, WhiteHawk’s interests cover approximately 975,000 gross DSU acres across Southwest Pennsylvania and Northern West Virginia, operated by leading Appalachian Basin producers,

²³	Assumes 1 gigawatt of capacity equates to 154 mmcf/d of natural gas demand.

²⁴	EIA Short-Term Energy Outlook.

²⁵	EIA Short-Term Energy Outlook.

²⁶	Enverus Data.

²⁷	EIA Short-Term Energy Outlook.

including EQT, Range Resources, CNX Resources and Antero Resources. These operators possess deep drilling inventories, strong balance sheets and a proven track record of disciplined development. Throughout 2024 and 2025, approximately 47% of wells turned in line by these operators in the Appalachian Basin were drilled on our acreage.²⁸

The Appalachian Basin forms the foundation of WhiteHawk’s asset base and provides investors with exposure to a region positioned to remain a highly productive source of low-cost, scalable natural gas for the U.S. and global markets for decades to come.

Haynesville Basin (East Texas / North Louisiana)

The Haynesville Basin, located in East Texas and North Louisiana, is one of the largest and most productive natural gas plays in the United States and a cornerstone of future U.S. supply growth. The basin’s combination of exceptional reservoir quality, proximity to demand centers and direct access to the Gulf Coast has positioned it as a critical source of feed gas for the rapidly expanding LNG export market.

Strategically located within 150 miles of the Gulf Coast, the Haynesville Basin provides a direct and cost-advantaged connection between prolific supply and fast-growing global demand. It is estimated that nearly all existing and planned U.S. LNG export terminals—including Sabine Pass, Cameron, Golden Pass, Port Arthur and Plaquemines—source a substantial portion of their feed gas from the Haynesville Basin. This geographic alignment ensures that the basin will remain a key driver of U.S. natural gas export growth for decades as global markets seek cheaper, reliable sources of natural gas and lower-carbon alternatives to coal and oil.

Since its renewed development in 2017, the Haynesville Basin has delivered steady volume growth supported by high-deliverability wells and low full-cycle development costs.²⁹ The basin is characterized by over pressured, laterally extensive shale formations that yield high initial production rates and long-lived reserves.³⁰ Continued advances in lateral lengths, completion designs and multi-well pad efficiencies have enhanced recoveries and reduced breakeven costs, making the Haynesville Basin one of the most economically viable sources of natural gas in the world. In addition to the Haynesville Shale, our acreage also benefits from additional resources from the Cotton Valley and Mid-Bossier formations, which together produced approximately 3.2%³¹ of U.S. natural gas production in 2025.

As of December 31, 2025, WhiteHawk’s Haynesville interests cover approximately 600,000 gross DSU acres across East Texas and North Louisiana, operated by leading producers such as Expand Energy, Comstock Resources and Aethon Energy. These operators are among the most active and technically proficient in the basin, each maintaining multi-year drilling inventories and robust infrastructure connectivity.

The Haynesville Basin represents another cornerstone of WhiteHawk’s portfolio, providing exposure to one of the highest-margin, infrastructure-advantaged gas plays in the United States. Its proximity to LNG export facilities, industrial corridors and petrochemical complexes along the Gulf Coast positions the basin—and WhiteHawk’s assets within it—at the center of the next phase of global natural gas demand growth.

Mid-Con Region (Anadarko Basin, Oklahoma)

The Mid-Con region, anchored by the Anadarko Basin in Oklahoma and extending into portions of Texas, Arkansas and Kansas, is one of the most historically productive and geologically diverse hydrocarbon basins in the United States. The region has been a major contributor to U.S. natural gas and liquids supply for nearly a century and remains a critical source of stable production, infrastructure access and development optionality.

²⁸	Enverus Data.

²⁹	EIA Short-Term Energy Outlook.

³⁰	Upstream Outlook Report.

³¹	Enverus Data.

With its combination of legacy production, existing infrastructure and ongoing technical innovation, the Anadarko Basin continues to play an important role in maintaining domestic supply reliability and supporting industrial and power-generation demand across the central United States. The basin’s multi-zone potential and moderate development costs have led to renewed operator activity, as natural gas demand expands through LNG exports and increasing AI-driven electricity demand.³²

The Anadarko Basin is characterized by multiple geological formations—including the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher counties), Woodford Shale and Cherokee Shale, which together provide exposure to both dry gas and liquids-rich zones. These intervals offer extensive development potential through established drilling and completion techniques, allowing operators to target high-return projects across varying commodity price environments. The basin’s mature gathering, processing and takeaway infrastructure ensures efficient market access to the Gulf Coast, Midwest and Mid-Con gas hubs.

As of December 31, 2025, WhiteHawk’s Mid-Con position spans approximately 1.7 million gross DSU acres across the SCOOP, STACK and Arkoma plays, operated by established and well-capitalized producers such as Continental Resources and Devon Energy (NYSE: DVN). These operators maintain deep, de-risked inventories and continue to optimize recovery through longer laterals, tighter spacing and improved completion designs.

Our Mineral and Royalty Interests

Nature of Our Mineral and Royalty Interests

WhiteHawk’s portfolio consists primarily of producing and undeveloped mineral and royalty interests in the Appalachian Basin, Haynesville Basin and Mid-Con region that provide the right to receive a share of production revenue from the sale of natural gas, natural gas liquids (“NGLs”) and oil produced by third-party operators. These interests include fee mineral ownership, non-participating royalty interests and overriding royalty interests.

We own two types of interests: mineral and royalty interests and non-operating working interests. Of the mineral and royalty interests, we own three types: mineral interests, non-participating royalty interests (“NPRIs”) and overriding royalty interests (“ORRIs”). For the year ended December 31, 2025, our mineral and royalty interests accounted for approximately 99% of our royalty revenues and our non-operating working interests accounted for approximately 1% of our royalty revenues. Each of these interests have different rights and obligations as further described below:

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Mineral Interests: Mineral interests are perpetual real property interests rights of the owner to exploit, mine and/or produce the minerals lying below the surface of the property. When we lease our mineral interests to third-party operators, we retain a royalty interest—the ongoing right to a portion of the revenue from any oil or gas later produced—and receive a one-time payment known as a lease bonus. Typically, the resulting royalty interest is a cost-free percentage of production revenues for minerals extracted from the acreage. Holders of royalty interests are generally not responsible for capital expenditures or lease operating expenses but may be responsible for certain post-production expenses and typically have limited environmental liability. While mineral interests are usually perpetual, gas and oil leases have a set term. Therefore, if drilling stops or no production occurs during that term, the lease ends, and the mineral owner is free to lease the rights again to another party and receive another lease bonus. Royalty interests expire upon the expiration of the gas and oil lease, but the mineral interests would be retained. Mineral interests represented approximately 92% of our mineral and royalty interests as of December 31, 2025.

³²	Enverus Data.

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Non-Participating Royalty Interest. A NPRI has the same characteristics as a standard royalty interest except that the term “non-participating” indicates that the interest owner has the right to participate in the execution of gas and oil leases but does not share in the bonus or rentals from a gas and oil lease. NPRIs represented approximately 3% of our mineral and royalty interests as of December 31, 2025.

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Overriding Royalty Interest. ORRIs are created by carving out the right to receive royalties from a working interest. Like royalty interests, ORRIs do not confer an obligation to make capital expenditures or pay for lease operating expenses and have limited environmental liability; however, ORRIs may be calculated net of post-production expenses, depending on how the ORRI is structured. ORRIs that are carved out of working interests are linked to the same underlying gas and oil lease that created the working interest and, therefore, ORRIs are typically subject to expiration upon the expiration or termination of the underlying gas and oil lease. ORRIs represented approximately 5% of our mineral and royalty interests as of December 31, 2025.

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Non-Operating Working Interest. In addition to our mineral and royalty interests, we own certain non-operating working interests acquired in connection with the PHX Acquisition. Non-operating working interest holders have the right to extract minerals from acreage leased pursuant to a gas and oil lease from a mineral interest holder. Holders of working interests are responsible for their pro rata share of capital expenditures and lease operating expenses, but holders of working interests only receive revenues after distributions have first been made to holders of royalty interests and ORRIs. Working interests expire upon the termination or expiration of the underlying gas and oil lease. As of December 31, 2025, our non-operating working interest portfolio consisted of 437 gross (18.1 net) wells located exclusively in the Mid-Con region and accounted for approximately 1% of our royalty revenues. These non-operating working interests represented approximately 7% of our total proved reserves and 3% of our total production for the year ended December 31, 2025.

The following table presents information as of December 31, 2025 about our mineral and royalty interest acreage by the resource plays we consider most material to our current and future business and accounted for approximately 99% of our royalty revenue for the year ended December 31, 2025.


	Net Mineral Acres		Average Royalty Rate			NRA 100% Basis (Mineral Interest)⁽²⁾		NRA 100% Basis (ORRIs)⁽²⁾		NRA 100% Basis (NPRIs)⁽²⁾		Total NRAs 100% Basis⁽²⁾		NRA (1/8^th Basis)		Gross DSU Acres		Implied Average Net Revenue Interest Across DSUs⁽¹⁾
Appalachian Basin		20,074		16	%		3,192		227		575		3,994		31,948		975,000		0.41	%
Haynesville Basin		5,943		21	%		1,248		66		—		1,314		10,513		600,000		0.22	%
Mid-Continent Region		63,256		15	%		9,691		487		—		10,177		81,419		1,700,000		0.60	%
Other		6,041		17	%		1,018		0.3		—		1,018		8,146		150,000		0.68	%

Total		95,314		17	%		15,149		780		575		16,503		132,026		3,425,000		0.48	%

(1)	Calculated as total net royalty acres divided by gross DSU acres.

(2)	Within the mineral and royalty industry, ownership is typically standardized to NRAs to compare portfolios on an equivalent basis. NRAs are adjusted either to a 1/8 royalty (12.5%) standardized basis or to a 100% royalty equivalent.

³³	Enverus Data.

86% natural gas, 10% NGLs and 4% crude oil, with $293,690 thousand of PV-10. Of these proved reserves, 98% were classified as PD reserves and 2% were classified as undeveloped reserves. For the year ended December 31, 2025, the average net daily production associated with our portfolio was 50,351 Mcfe/d, consisting of 45,442 Mcf/d of natural gas, 577 Bbls/d of NGLs and 241 Bbls/d of oil and on a pro forma basis, average net daily production of 67,255 Mcfe/d, consisting of 59,621 Mcf/d of natural gas, 790 Bbls/d of NGLs and 483 Bbls/d of oil.

We earn most of our revenues through a steady stream of royalties and lease bonuses, all tied to the success of gas and oil production on our acreage. We differ from traditional upstream gas and oil companies as we, and any other royalty interest owner, do not pay for nor operate wells. All of the costs and risks involved in finding, drilling and maintaining wells are borne by the working interest owners. Royalty interest owners generally are only responsible for certain taxes tied to production, such as severance and property taxes, and fees related to transportation or marketing of gas and oil.

Because we do not pay for drilling or bear the risks of dry holes or operational setbacks, we typically enjoy much higher operating margins compared to our third-party operators. Our business model is more capital-light, focusing on management and acquisition of various mineral and royalty interests, rather than the direct, costly development capital necessary for the extraction of resources. This gives us a recurring income stream with less variability in free cash flow than the traditional exploration and production business.

As an active consolidator of mineral and royalty interests, WhiteHawk works closely with third-party operators throughout the lifecycle of each asset—from negotiating and optimizing lease terms at inception, to confirming timely in-pay status as wells are drilled and completed and continuously validating that we receive the correct revenue interest over the life of the well. This engagement has supported improved royalty terms, more favorable pricing provisions, and reduced post-production deductions, enhancing realized revenues and long-term returns.

WhiteHawk’s mineral and royalty ownership model allows the Company to generate stable, capital-efficient cash flow from producing assets while maintaining organic growth potential through the continued development of its undeveloped mineral position without the need to pay for associated drilling capital expenditures. Over time, we have reinvested proceeds from lease bonuses and free cash flow from our assets to expand our footprint in the most economically attractive natural gas basins in the United States while maintaining a conservative balance sheet and disciplined capital strategy.

The following table provides information regarding our gross and net locations by region or basin based on technical parameters as of December 31, 2025. For additional information with respect to our gross and net locations, please see the section titled “Business—Natural Gas, NGL and Oil Data.”


	Gross Undeveloped Location Count⁽¹⁾						Net Undeveloped Location Count⁽⁴⁾		Average Lateral Length
Region / Basin	Included in Proved Reserves⁽²⁾		Other Locations⁽³⁾		Total		Total		(feet)
Appalachian Basin		229		2,563		2,792		8.7		13,246
Haynesville Basin		94		1,487		1,581		3.1		9,267
Mid-Continent Basin⁽⁵⁾		86		3,866		3,952		14.1		9,314
Other⁽⁶⁾		21		437		458		2.1		9,864

(1)	Numbers of gross well locations may vary based on actual lateral lengths drilled by operators.

(2)	Includes Proved Undeveloped locations included as part of CG&A’s reserve report dated March 13, 2026 with respect to the Company’s proved reserves as of December 31, 2025. Includes WIPs and permits as defined by management.

(3)	Includes locations not included as part of CG&A’s reserve report dated March 13, 2026 with respect to the Company’s proved reserves as of December 31, 2025; however, such locations have been audited and approved by CG&A. Includes other undeveloped locations, as defined by management.

(4)	Reflects management’s estimated net revenue interest multiplied by Total Gross Undeveloped Locations as audited by CG&A.

(5)	Includes locations in the SCOOP, STACK, Cherokee, Arkoma and Fayetteville.

(6)	Includes locations in the Bakken.

Key Operators

We strive to acquire mineral and royalty interests in properties with top-tier E&P operators that are well capitalized, have a strong operational track record and that we believe will continue to increase production through the application of the latest drilling and completion techniques. Our royalty interests are developed and operated by many of the highest-quality natural gas producers in the United States. The graphs below highlight the portion of production from top operators captured on our position across each region in 2025:³⁴

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Strengths

We believe that the following competitive strengths will allow us to successfully capitalize on our market opportunities, execute our business strategies, and achieve our primary business objectives:

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Premier, large-scale natural gas mineral and royalty company in America’s most productive gas basins. We have assembled one of the largest pure-play natural gas mineral and royalty portfolios in the United States, spanning approximately 3.4 million gross DSU acres and providing exposure to more than 10,900 producing wells as of December 31, 2025. Our acreage is concentrated in the Appalachian and Haynesville Basins, two of the most productive and lowest-cost sources of natural gas in the United States, which together accounted for more than 50% of total U.S. dry gas production³⁵ and 81% of our royalty revenue in 2025. These basins feature thick, laterally continuous shale intervals, high-pressure reservoirs, and well-developed gathering and long-haul pipeline infrastructure that enable some of the lowest breakeven development economics in the United States. The fact that 11% and 33%³⁶ of Appalachian and Haynesville Basin wells, respectively, were drilled on our acreage in 2025, is indicative that our assets are located in the core development areas of these premier gas plays. We believe our proximity to the core development areas of these basins will provide long-term visibility into drilling activity and sustained royalty cash flow through consistent operator investments and stacked play potential.

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High-margin, capital-light business model. WhiteHawk’s business model is designed to generate substantial cash flow as our mineral and royalty interests have no drilling capital expenditure requirements and minimal operating costs. Our mineral and royalty interests allow us to capture the

³⁴	Enverus Data. Percentages exceed 100% due to rounding.

³⁵	EIA Short-Term Energy Outlook.

³⁶	Enverus Data.

economic benefits of natural gas development without bearing the capital risk or inflationary cost pressures typical of traditional E&P companies because we do not incur drilling, completion, lease operating expenses, or plugging and abandonment obligations at the end of a well’s productive life. This capital-light model enables us to convert a significant portion of our revenue directly into free cash flow. Our recurring costs are limited primarily to production taxes, gathering, processing, and transportation expenses, and modest general and administrative overhead.

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High-quality assets supported by top-tier operators with visible development activity. Our mineral interests are operated by leading, well-capitalized E&P companies in some of the most productive and economically attractive natural gas basins in the United States. In 2025, the Appalachian Basin accounted for approximately 38% of the total U.S. natural gas production,³⁷ with WhiteHawk’s acreage operated by premier producers including EQT, Antero Resources, Range Resources and CNX Resources. Combined, these operators accounted for approximately 96% of our royalty revenue in the Appalachian Basin in 2025. The Haynesville Basin contributed approximately 15% of total U.S. natural gas production in 2025,³⁸ with WhiteHawk’s acreage operated by premier producers including Expand Energy, Comstock Resources and Aethon Energy. Combined, these operators accounted for approximately 58% of our royalty revenue in the Haynesville Basin for 2025. As of December 31, 2025, our portfolio includes nearly 430 wells in progress (“WIPs”) and permitted locations, and more than 8,000 remaining identified undeveloped locations. We believe this embedded inventory provides a visible, multi-year growth runway that requires no additional capital investment from us. Our exposure to operators with strong balance sheets, basin-leading drilling productivity, and disciplined capital programs is designed to enhance the stability of our production base and support long-term royalty cash flow generation.

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Capturing value from AI-driven electricity demand growth. We are positioned to benefit from the accelerating rise in electricity demand driven by AI and data center expansion, much of which is expected to be met by natural gas. Natural gas is the primary fuel for U.S. power generation accounting for approximately 41%³⁹ of total electricity output in 2025. In line with this trend, our Appalachian Basin acreage is located near 21 publicly announced new or planned natural gas fired power plants representing what management estimates to be approximately 7.8 Bcf/d of total natural gas demand associated with new power plants expected by 2031.⁴⁰ The ongoing expansion of AI-driven and digital-infrastructure power needs is expected to support long-term natural gas consumption and price stability, encouraging sustained operator investment and development activity on our mineral acreage and providing predictable recurring cash flows that can be distributed to investors.

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Positioned to capitalize on LNG export growth. U.S. LNG export capacity is expected to nearly double from approximately 17 Bcf/d in 2025 to nearly 34 Bcf/d by 2031⁴¹, as European and Asian buyers seek secure, competitively priced supply and diversify away from oil-indexed benchmarks or regional international benchmarks such as JKM (Asia) and TTF (Europe), where the average pricing is 3-4x Henry Hub pricing in the United States for the year 2025.⁴² In addition, as of December 2025, approximately 28 Bcf/d of incremental LNG capacity is in various stages of regulatory review and development, representing further upside to long-term U.S. export potential.⁴³ The Haynesville Basin’s proximity and pipeline connectivity to the Gulf Coast LNG corridor position our assets to benefit directly from this expansion. Sustained growth in U.S. LNG exports is expected to drive long-term feed-gas demand from the basins where our mineral interests are concentrated, for years to come.

³⁷	EIA Short-Term Energy Outlook.

³⁸	EIA Short-Term Energy Outlook.

³⁹	EIA Electric Monthly.

⁴⁰	Assumes 1 gigawatt of capacity equates to 154 mmcf/d of natural gas demand.

⁴¹	EIA Natural Gas Exports. Includes current operating and under construction projects only.

⁴²	FactSet LNG Pricing.

⁴³	EIA Liquefaction Report as supplemented by management’s review of recently announced facilities.

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Proven management team with a track record of public company value creation and accretive growth. Our management team is among the most experienced and acquisitive in the minerals sector, with more than 125 years of combined industry experience and over $31 billion of completed energy transactions across the upstream, midstream, and mineral and royalty value chain. Members of our team previously served as senior executives or founders of Atlas Energy, Atlas Pipeline Partners and Falcon Minerals, each a successful public company that created substantial shareholder value through disciplined growth, accretive acquisitions, and strategic monetization. Since our founding, WhiteHawk has been the most active acquirer of natural gas minerals and royalties, completing eight large transactions across the most prolific gas-oriented basins in the United States.⁴⁴ Our ability to consistently source, evaluate, and close accretive transactions underscores WhiteHawk’s leadership as a focused, data-driven consolidator with proven expertise in capital allocation, M&A execution and public-market stewardship.

Strategies

Our primary business objective is to deliver shareholder value through dividends and total return from our mineral interests in premier natural gas-weighted properties. We intend to accomplish this objective by executing the following key strategies:

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Provide sustained income to investors through strong Cash Available for Distribution generation and cash dividends. We expect initially to pay dividends from our Cash Available for Distribution with the remaining cash flow to be used for additional acquisitions that meet our investment criteria or to maintain our conservative capital structure. As mineral and royalty owners, we benefit from the continued organic development of our acreage and are able to convert a high percentage of our revenues to Cash Available for Distribution (as defined herein). We believe that our mineral and royalty interests are positioned for growth as E&P operators continue to concentrate on the Appalachian Basin, Haynesville Basin and Mid-Con region to meet growing global demand for natural gas. Since our inception in 2022, we have paid 46 consecutive monthly common equity dividends, totaling approximately $30 million and representing a cash-on-cash return of approximately 36%⁴⁵ to our initial investors through January 1, 2026. We believe our efficient, conservatively levered structure, with low capital intensity and disciplined financial management, provides a sustainable foundation for attractive dividend yields, balance sheet flexibility, and long-term value creation for shareholders.

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Strategically source and acquire de-risked, cash-flowing natural gas mineral and royalty interests of scale from long-term partnerships. Our strategy focuses on acquiring high-quality mineral and royalty interests that generate immediate cash flow and offer long-term development visibility. We target assets operated by leading, well-capitalized producers in the core of the Appalachian Basin, Haynesville Basin, and Mid-Con region, where continued drilling activity provides durable revenue growth without direct capital risk exposure. WhiteHawk differentiates itself through a disciplined, partnership-oriented sourcing approach with private-equity sponsors and other institutional owners seeking liquidity from later-life funds. This positions WhiteHawk as one of the few large-scale consolidators of natural gas-weighted minerals, particularly in the Appalachian Basin, which remains underrepresented in public minerals markets.

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⁴⁴	Enverus Data.

⁴⁵	Reflects a cash-on-cash return to our initial investors whose share price did not include any selling commissions on investment. Returns to our initial investors whose share price included selling commissions on investment resulted in cash-on-cash returns of approximately 33%.

extensive industry relationships, and proprietary geologic and title data, we target assets that can provide accretive growth in shareholder value while strengthening our production and reserve base. Since inception, we have been among the most active consolidators in the natural gas minerals sector, completing seven transactions that have materially increased our scale and enhanced cash flow. These acquisitions have been highly accretive to shareholders and have resulted in approximately 36%⁴⁶ cash-on-cash return to our initial investors. We believe current market conditions remain highly favorable for consolidation, as fragmented ownership across numerous private sellers continues to create opportunities for accretive acquisitions that meet our investment criteria.

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Optimize portfolio to maximize Cash Available for Distribution and maintain diversified exposure. We actively manage our portfolio to prioritize acreage with a strong cash-flow base, visible near-term development, and substantial future inventory. A core component of this strategy is maintaining a broad, diversified mineral footprint across multiple core natural gas basins, encompassing an average NRI of 0.69% in more than 10,900 producing wells, with additional wells consistently in various stages of development across a footprint exceeding 3.4 million gross DSU acres as of December 31, 2025. This scale and diversity provide exposure to the most prolific, lowest-cost natural gas plays in the United States while reducing reliance on any single operator or well. The result is a balanced portfolio designed to generate resilient cash flow and mitigate volatility through commodity cycles. Through disciplined asset management, targeted reinvestment, and continued optimization, we seek to enhance portfolio productivity, strengthen cash flow stability and grow our dividend over time.

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Maintain conservative and flexible capital structure to support our business and facilitate long-term operations. We are committed to maintaining a conservative capital structure that will afford us the financial flexibility to execute our business strategies on an ongoing basis. We expect to maintain a prudent level of debt to support our acquisition and growth strategy while preserving balance sheet flexibility. We believe that the combination of cash flow from operations, proceeds from this offering, and selective use of other debt and equity financings will provide us with sufficient liquidity to pursue accretive acquisitions, enhance our cash flow profile, and return capital to our shareholders. We intend to manage our leverage conservatively and finance future acquisitions through cash flow from operations or opportunistically utilizing equity or debt to support disciplined growth.

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Commitment to responsible natural gas development and governance excellence. Natural gas, the primary driver of our royalty income, is a critical, lower-emission component of the modern energy mix and remains central to meeting global demand for reliable and affordable power. As a cleaner-burning fuel, it provides consistent and scalable energy that complements renewable energy and supports grid stability. The operators developing our mineral acreage, including EQT, Range Resources, Antero Resources and CNX Resources, have each adopted measurable standards focused on reducing emissions and promoting responsible development. With all of our assets located in the most economic natural gas basins in the United States, we are positioned to benefit from the growing recognition of natural gas as a reliable, cleaner source of energy. We also intend to reinforce the durability of our business through rigorous corporate governance, transparency, and alignment with our shareholders. Our governance framework emphasizes independence, accountability, and disciplined capital allocation. We believe our governance framework reduces our risk profile and sustains investor confidence through commodity cycles. We believe our adherence to governance best practices and partnerships with responsible operators differentiate WhiteHawk as a transparent, sustainable, and income-oriented energy investment capable of delivering attractive returns over the long term.

⁴⁶	Reflects a cash-on-cash return to our initial investors whose share price did not include any selling commissions on investment. Returns to our initial investors whose share price included selling commissions on investment resulted in cash-on-cash returns of approximately 33%.

Recent Transactions

PHX Acquisition

Pursuant to the PHX Merger Agreement, by and among the Company Parties and PHX, the Company Parties agreed to acquire in an all-cash transaction all issued and outstanding shares of PHX’s common stock for a purchase price of $4.35 per share, a total value of $194.8 million, including PHX’s net debt.

Subsequently, on June 23, 2025, the Company Parties closed on the PHX Acquisition and fully acquired all of the outstanding shares of PHX’s common stock. The PHX Acquisition increased the Company’s mineral and royalty ownership position by acquiring additional mineral and royalty interests in the Haynesville Shale as well as the SCOOP/STACK, Bakken, Arkoma and others. The PHX Acquisition also increased the Company’s exposure to some of its top third-party operators, including Expand Energy, Comstock Resources and Aethon Energy in the Haynesville Shale, while adding other top operators including Continental Resources and Devon Energy in the SCOOP/STACK region in Oklahoma. As a result of the PHX Acquisition, WhiteHawk added approximately 1.8 million gross DSU acres of premier natural gas mineral and royalty assets, significantly expanding its footprint in the core of the Haynesville Shale in East Texas/North Louisiana and diversifying its portfolio into the SCOOP/STACK region.

Marcellus Assets

On March 31, 2025, the Company purchased in the Three Rivers Royalty Acquisition mineral and royalty interests in the Marcellus Shale for a purchase price of $118.0 million from the TRR Seller. The Company believes these Marcellus Shale assets represent some of the highest quality natural gas reserves in the United States.

Haynesville Assets

On March 2, 2026, the Company and its affiliate entered into a definitive purchase and sale agreement to acquire certain natural gas mineral and royalty interests primarily located in the core of the Haynesville Shale in Louisiana and east Texas (“Haynesville Assets”). The Haynesville Assets cover approximately 150,000 gross DSU acres and will further increase the Company’s exposure to high-quality development across the Haynesville and Mid-Bossier formations. The assets are concentrated in core areas of the basin and are operated by established, well-capitalized operators. The Haynesville Assets acquisition closed on April 3, 2026. We funded the purchase price of the Haynesville Assets acquisition primarily through the issuance of approximately $37.8 million of shares of Series D preferred stock. See “Description of Capital Stock—Preferred Stock—Series D Preferred Stock.” The Company intends to use a portion of the proceeds from this offering to redeem any shares of Series D Preferred Stock outstanding. See “Use of Proceeds.” To the extent the proceeds of this offering are insufficient to redeem the total aggregate principal amount of Series D Preferred Stock outstanding, the Company intends to use cash on hand to fully redeem the total aggregate principal amount of Series D Preferred Stock outstanding.

Summary of the Transactions

In connection with the consummation of the offering, we will consummate the following organizational transactions (the “Transactions”):

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we will amend and restate our certificate of incorporation (our “amended and restated certificate of incorporation”) to, among other things, (i) change our name to “WhiteHawk Minerals Corp.”; (ii) provide for the reclassification of shares held by the Legacy Common Stock Investors issued and outstanding immediately prior to the offering into one validly issued, fully paid and non-assessable

share of our Class A common stock, on a one-for-one basis (such reclassification, the “Common Stock Reclassification”); (iii) provide for an adjustment to the number of authorized shares such that our authorized capital stock shall consist of 250,000,000 shares of Class A common stock, par value $0.0001 per share, 100,000,000 shares of Class B common stock, par value $0.0001 per share, and 10,000,000 shares of preferred stock, par value $0.0001 per share; (iv) authorize our board of directors to establish and issue one or more series of preferred stock from time to time and to fix the rights, preferences, privileges and restrictions thereof; (v) provide for the creation of Class B common stock in connection with our anticipated Up-C structure, with shares of Class B common stock to be issued to Continuing Equity Owners, with each share of Class B common stock entitled to one vote per share and no economic rights; and (iv) establish that Legacy Common Stock Investors are prohibited from selling their Class A common stock or related securities for 365 days following the consummation of this offering, or such shorter period as determined by the board of directors, but in no event less than 180 days without the prior written consent of the managing underwriter of this offering;

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WhiteHawk OpCo will enter into an amended and restated limited partnership agreement (the “OpCo Agreement”) to, among other things, (i) appoint OP GP as the sole general partner of WhiteHawk OpCo with the authority to manage and control the business and affairs of WhiteHawk OpCo, (ii) authorize the issuance of OpCo Interests to us in exchange for the interests we own in WhiteHawk OpCo prior to this offering as well as the proceeds from this offering, (iii) provide the Continuing Equity Owners with the right to require WhiteHawk OpCo to redeem their OpCo Interests for, at our election (determined solely by our independent directors who are disinterested), cash or newly-issued shares of our Class A common stock on a one-for-one basis (subject to customary adjustments), (iv) provide that, in connection with any redemption or exchange of OpCo Interests, if applicable, a corresponding number of shares of Class B common stock held by the redeeming or exchanging Continuing Equity Owner will automatically be transferred to us for no consideration and canceled, and (v) authorize the issuance to us of such number of Series B preferred units in WhiteHawk OpCo equal to the number of shares of our Series B preferred stock outstanding upon the consummation of the Transactions;

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we will enter into a registration rights agreement with certain of our Continuing Equity Owners (the “Registration Rights Agreement”), as further described in “Certain Relationships and Related Person Transactions;”

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in connection with and in order to effectuate the Internalization, the Contribution Agreement will be entered into by the parties thereto, pursuant to which, among other things, OpCo will acquire all of the outstanding equity interests in ManagementCo from the Management Owners in exchange for OpCo Interests and shares of Class B common stock. Prior to the closing of this offering, ManagementCo, as our external manager, provided management, acquisition, disposition and oversight functions with respect to us and WhiteHawk OpCo. As a result of the Internalization, ManagementCo will become a wholly owned subsidiary of WhiteHawk OpCo and we will become internally managed;

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we will issue shares of our Class A common stock to the purchasers in this offering (or shares if the underwriters exercise in full their option to purchase additional shares of Class A common stock) in exchange for net proceeds of approximately $ million (or approximately $ million if the underwriters exercise in full their option to purchase additional shares of Class A common stock) based upon an assumed initial public offering price of $ per share (which is the midpoint of the estimated price range set forth on the cover page of this prospectus), less the underwriting discount; and

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we will use the net proceeds from this offering to purchase newly issued OpCo Interests for approximately $ million directly from WhiteHawk OpCo at the initial public offering price less the underwriting discount.

Immediately following the consummation of the Transactions (including this offering):

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we will be a holding company and our principal assets will consist of OpCo Interests we acquire or are otherwise issued directly from WhiteHawk OpCo and all the membership interests in OP GP;

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as the sole member of OP GP, the sole general partner of WhiteHawk OpCo, we will control the business and affairs of WhiteHawk OpCo;

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we will own, directly or indirectly, OpCo Interests, representing approximately % of the economic interest in WhiteHawk OpCo (or OpCo Interests, representing approximately % of the economic interest in WhiteHawk OpCo if the underwriters exercise in full their option to purchase additional shares of Class A common stock);

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we will own a number of Series B preferred units in WhiteHawk OpCo equal to the number of shares of Series B preferred stock outstanding after the consummation of the Transactions, representing 100% of the preferred units of WhiteHawk OpCo;

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we will no longer have any shares of Series D preferred stock outstanding;

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the Continuing Equity Owners will own (i) OpCo Interests, representing approximately % of the economic interest in WhiteHawk OpCo (or OpCo Interests, representing approximately % of the economic interest in WhiteHawk OpCo if the underwriters exercise in full their option to purchase additional shares of Class A common stock) and (ii) shares of our Class B common stock, representing approximately % of the combined voting power of all of our common stock (or shares of our Class B common stock, representing approximately % if the underwriters exercise in full their option to purchase additional shares of Class A common stock);

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the purchasers in this offering will own (i) shares of our Class A common stock (or shares of our Class A common stock if the underwriters exercise in full their option to purchase additional shares of Class A common stock), representing approximately % of the combined voting power of all of our common stock and % of the economic interest in us (or approximately % of the combined voting power and % of the economic interest if the underwriters exercise in full their option to purchase additional shares of Class A common stock), and (ii) through our ownership of OpCo Interests, indirectly will hold approximately % of the economic interest in WhiteHawk OpCo (or approximately % of the economic interest in WhiteHawk OpCo if the underwriters exercise in full their option to purchase additional shares of Class A common stock).

The foregoing description of the Transactions does not give effect to OpCo Interests or shares of our Class B common stock that may be issued as a part of the Earnout Amount (as defined herein), as more fully described in the section titled “Certain Relationships and Related Party Transactions—Internalization—Earnout.”

Following the Transactions, including this offering, we will control the management of WhiteHawk OpCo through our ownership of OP GP. As a result, we will consolidate WhiteHawk OpCo in our consolidated financial statements.

Unless otherwise indicated, this prospectus assumes the shares of Class A common stock are offered at $ per share (the midpoint of the estimated price range set forth on the cover page of this prospectus). For more information regarding the impact of the initial offering price on the share information included throughout this prospectus, see “The Offering.”

Our corporate structure following this offering, as described below, is commonly referred to as an Up-C structure. The Up-C structure will allow the Continuing Equity Owners to retain their equity ownership in WhiteHawk OpCo following the Transactions and to continue to realize tax benefits associated with owning interests in an entity that is treated as a partnership, or “flow-through” entity, for U.S. federal income tax

purposes. Investors in this offering will, by contrast, hold their equity ownership in us, a Delaware corporation that is a domestic corporation for U.S. federal income tax purposes, in the form of shares of Class A common stock. One of the tax benefits to the Continuing Equity Owners associated with this structure is that future taxable income of WhiteHawk OpCo that is allocated to the Continuing Equity Owners will be taxed on a flow-through basis and, therefore, will not be subject to corporate taxes at the entity level. Moreover, the Up-C structure permits the Continuing Equity Owners to defer the recognition of taxable gain on their OpCo Interests until they elect to exercise their redemption right (rather than recognizing such gain at the time of this offering). Additionally, because the Continuing Equity Owners may at their election have their OpCo Interests redeemed by WhiteHawk OpCo (or at our option, directly exchanged by us) for newly issued shares of our Class A common stock on a one-for-one basis (subject to customary adjustments, including for stock splits, stock dividends, and reclassifications) or, at our option, for cash, the Up-C structure also provides the Continuing Equity Owners with potential liquidity that holders of non-publicly traded limited liability companies are not typically afforded. Upon any such redemption or exchange of OpCo Interests for shares of Class A common stock, the Company may benefit from certain tax attributes, including potential increases in tax basis that may reduce the amount of tax that would otherwise be payable by us. In connection with any such redemption or exchange of OpCo Interests, a corresponding number of shares of Class B common stock held by the relevant Continuing Equity Owner will automatically be transferred to us for no consideration and be canceled.

For more information regarding the Transactions and our structure, see “Our Organizational Structure.”

Organizational Structure

The diagram below depicts our organizational structure after giving effect to the Transactions, including this offering and proposed use of proceeds, assuming no exercise by the underwriters of their option to purchase additional shares of Class A common stock and does not give effect to the issuance of any OpCo Interests or shares of Class B common stock in respect of the Earnout Amount.

LOGO

(1)	Excludes any Continuing Equity Owners who hold Class A common stock as a result of the Common Stock Reclassification (in addition to OpCo Interests and Class B common stock).

(2)

Legacy Common Stock Investors will be prohibited from selling their Class A common stock or related securities for up to 365 days following the consummation of this offering, or such shorter period as determined by the board of directors, but in no event less than 180 days without the prior written consent of the managing underwriter of this offering.

(3)

We intend to use a portion of the proceeds from this offering to redeem any shares of Series D preferred stock outstanding. See “Use of Proceeds.” To the extent the proceeds of offering are insufficient to redeem the total aggregate principal amount of Series D preferred stock outstanding, the Company intends to use cash on hand to fully redeem the total aggregate principal amount of Series D preferred stock outstanding. As a result, following this offering, the only outstanding preferred stock outstanding will be the Series B preferred stock.

Corporate Information

WhiteHawk Income Corporation was formed on February 18, 2022 and is the issuer of the Class A common stock offered by this prospectus. We intend to change our corporate name to WhiteHawk Minerals Corp. in connection with the closing of this offering. See “—Summary of the Transactions” and “Our Organizational Structure.” Our principal executive offices are located at 2000 Market Street, Suite 910, Philadelphia, PA 19103, and our telephone number is (610) 484-3412. Our corporate website address is https://www.whitehawkenergy.com/. Our website and the information contained on or that can be accessed through our website is not deemed to be incorporated by reference in, and is not considered part of, this prospectus. You should not rely on any such information in making your decision whether to purchase our Class A common stock.

Summary of Risk Factors

Investing in our Class A common stock involves a number of risks. The following is a summary of the principal factors that make an investment in our Class A common stock speculative or risky, all of which are more fully described in the section titled “Risk Factors” included elsewhere in this prospectus. This summary should be read in conjunction with the “Risk Factors” section and should not be relied upon as an exhaustive summary of the material risks facing our business.

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Our revenues are primarily derived from mineral and royalty payments that are based on the price of natural gas, NGL and oil which is subject to volatility due to factors beyond our control;

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Lower natural gas, NGL and oil prices or negative adjustments of natural gas, NGL and oil prices may result in significant impairment charges;

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Our derivative activities may limit the cash flows received from natural gas and oil sales;

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The development of our properties relies exclusively on our third-party operators and these operators may fail to develop our existing inventory of mineral and royalty acreage;

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Drilling for and producing natural gas, NGLs and oil are high-risk activities with many uncertainties;

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Our third-party operators may fail to drill sufficient wells to hold acreage before lease expiration which may result in loss of lease and prospective drilling opportunities;

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We may experience delays in the receipt of royalty payments and may not be able to terminate leases with defaulting lessees if our third-party operators declare bankruptcy;

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We may incur losses as a result of title defects or other issues in the properties we own;

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A limited number of third-party operators currently generate a significant portion of our revenue and accounts receivable;

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The substantial majority of our business is concentrated in the Appalachian and Haynesville Basins, making us vulnerable to risks associated with such geographic concentration of our assets;

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We are subject to risks related to our wells where we are a non-operating working interest owner;

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Our future success depends on replacing reserves through acquisitions and there may be constraints in our ability to finance acquisitions;

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We have experienced significant business and portfolio growth in a short time, and our significant growth rates and financial results may not be sustainable or indicative of future financial performance;

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Any acquisition of additional mineral and royalty interests that we complete will be subject to substantial risks;

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Our failure to retain our key personnel or attract additional qualified personnel could negatively affect our business strategy;

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Our estimated proved reserves are based on many assumptions that may prove to be inaccurate;

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Our identified drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling and there is no guarantee that our estimates will be materially consistent with actual drilling activities;

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We rely on our third-party operators, other third parties and government databases for information regarding our assets and such information may be incorrect, incomplete or lost;

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We may be subject to information technology system failures, network disruptions, cyber-attacks or other breaches in data security;

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Declining general economic, business or industry conditions, which could have a material adverse effect on our business;

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Our industry is highly competitive, and competitive pressures could negatively affect our business;

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Exported liquified natural gas could fail to be a competitive source of energy for the United States or international markets;

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Our growth strategy is partly dependent upon the continued expansion of electricity demand driven by AI data center development and expectations regarding increased demand may not materialize;

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The unavailability, high cost or shortages of equipment, raw materials, supplies or personnel for our third-party operators related to developing and operating our properties;

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The marketability of natural gas, NGLs and crude oil is dependent on the availability of equipment and transportation facilities that is outside of our and our third-party operators’ control;

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Our third-party operators are subject to significant governmental regulations, and governmental authorities can delay or deny permits and approvals or change legal requirements governing our business, which could restrict their operations, increase costs of conducting our business, and delay our implementation of, or cause us to change, our business strategy;

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The development and enactment of climate change legislation as well as increased attention to sustainability may impact our business or the business of our third-party operators;

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Future legislative or regulatory changes may have a material adverse effect on our business;

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Our use of borrowings to finance our business exposes us to risks and any future indebtedness we may incur could further increase the risks associated with our indebtedness;

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We recently restated our audited consolidated financial statements to correct certain errors and have identified material weaknesses in our internal control over financial reporting that caused our management to conclude that we did not maintain effective internal control over financial reporting and disclosure controls and procedures.

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No market currently exists for our Class A common stock, and an active, liquid trading market for our Class A common stock may not develop, which may cause our Class A common stock to trade at a discount from the initial offering price and make it difficult for you to sell the Class A common stock you purchase;

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We cannot predict the effect our dual class structure may have on the market price of our Class A common stock;

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Our organizational structure confers certain benefits upon the Continuing Equity Owners that will not benefit holders of our Class A common stock to the same extent that it will benefit the Continuing Equity Owners;

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Delaware law and anti-takeover provisions in our governing documents, to be adopted upon the consummation of this offering, may have the effect of delaying or preventing a change of control or changes in our management and may deprive our investors of the opportunity to receive a premium for their shares;

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Our ability to pay regular dividends to our stockholders may be limited by our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements, instruments governing our indebtedness and other factors and restrictions; and

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The requirements of being a public company may strain our resources, divert management’s attention and affect our ability to attract and retain qualified board members and officers.

For a discussion of these and other risks you should consider before making an investment in our common stock, see the section entitled “Risk Factors.”

Emerging Growth Company

We are an “emerging growth company” as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the JOBS Act. For as long as we are an emerging growth company, unlike other public companies that do not meet those qualifications, we are not required to:

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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 Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”);

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provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations in a registration statement on Form S-1;

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comply with any new requirements adopted by the Public Company Accounting Oversight Board (“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;

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provide certain disclosure regarding executive compensation required of larger public companies or hold stockholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (the “Dodd-Frank Act”); or

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obtain stockholder approval of any golden parachute payments not previously approved.

In addition, Section 107 of the JOBS Act also 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.

We will cease to be an “emerging growth company” upon the earliest of: (i) the last day of the first fiscal year in which our annual gross revenues are $1.235 billion or more; (ii) the date on which we have issued more than $1.0 billion of non-convertible debt over a three-year period; (iii) the last day of the fiscal year following the fifth anniversary of our initial public offering; or (iv) the date on which we have been deemed a “large accelerated filer,” which will occur as of the end of any fiscal year in which we (A) have an aggregate worldwide market value of voting and non-voting shares of common equity securities held by our non-affiliates of $700 million or more as of the last business day of our most recently completed second fiscal quarter, (B) have been subject to the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), for a period of at least 12 calendar months, (C) have filed at least one annual report pursuant to Section 13(a) or 15(d) of the Exchange Act, and (D) are no longer eligible to use the requirements for “smaller reporting companies,” as defined in the Exchange Act, for our annual and quarterly reports.

THE OFFERING

Issuer

WhiteHawk Income Corporation (to be changed to WhiteHawk Minerals Corp. in connection with the closing of the offering).

Class A Common stock offered by us

shares (or shares, if the underwriters exercise in full their option to purchase additional shares).

OpCo Interests to be outstanding after this offering

OpCo Interests, representing an approximately % economic interest in WhiteHawk OpCo (or OpCo Interests, representing an approximately % economic interest in WhiteHawk OpCo, if the underwriters exercise their option to purchase additional shares of Class A common stock in full)).

Option to purchase additional shares

We have granted the underwriters a 30-day option to purchase up to an aggregate of additional shares of our Class A common stock to the extent the underwriters sell more than shares of Class A common stock in this offering.

Class A common stock to be outstanding after this offering

shares (or shares if the underwriters exercise in full their option to purchase additional shares).

Shares of Class B common stock to be outstanding immediately after this offering

shares, representing approximately % of the combined voting power of all of our common stock (or shares, representing approximately % of the combined voting power of all of our common stock if the underwriters exercise in full their option to purchase additional shares of Class A common stock) and no economic interest in WhiteHawk Minerals Corp.

OpCo Interests to be held by us immediately after this offering

OpCo Interests, representing approximately % of the economic interest in WhiteHawk OpCo (or OpCo Interests, representing approximately % of the economic interest in WhiteHawk OpCo if the underwriters exercise in full their option to purchase additional shares of Class A common stock).

OpCo Interests to be held directly by the Continuing Equity Owners immediately after this offering

Ratio of shares of Class A common stock to OpCo Interests

The OpCo Agreement will require that we and WhiteHawk OpCo at all times maintain a one-to-one ratio between the number of shares of Class A common stock issued by us and the number of OpCo Interests owned by us.

Ratio of shares of Class B common stock to OpCo Interests

Our amended and restated certificate of incorporation and the OpCo Agreement will require that we and WhiteHawk OpCo at all times maintain a one-to-one ratio between the number of shares of Class B common stock owned by the Continuing Equity Owners and their respective permitted transferees and the number of OpCo Interests owned by the Continuing Equity Owners and their respective permitted transferees. Immediately after the Transactions, the Continuing Equity Owners will together own % of the outstanding shares of our Class B common stock.

Permitted holders of shares of Class B common stock

Only the Continuing Equity Owners and the permitted transferees of Class B common stock as described in this prospectus will be permitted to hold shares of our Class B common stock. See “Certain Relationships and Related Person Transactions—OpCo Agreement—Agreement in Effect Upon Consummation of the Transactions.”

Voting rights

Holders of shares of our Class A common stock and Class B common stock will vote together as a single class on all matters presented to stockholders for their vote or approval, except as otherwise required by law or our amended and restated certificate of incorporation. Each share of our Class A common stock and Class B common stock entitles its holders to one vote per share on all matters presented to our stockholders generally. See “Description of Capital Stock.”

Redemption rights of holders of OpCo Interests

The Continuing Equity Owners may, subject to certain exceptions, from time to time at each of their options require WhiteHawk OpCo to redeem all or a portion of their OpCo Interests in exchange for, at our election (determined solely by our independent directors (within the meaning of the Exchange rules) who are disinterested), newly-issued shares of our Class A common stock on a one-for-one basis (subject to customary adjustments, including for stock splits, stock dividends, and reclassifications) or a cash payment equal to a volume weighted average market price of one share of our Class A common stock for each OpCo Interest so redeemed, in each case, in accordance with the terms of the OpCo Agreement; provided that, at our election (determined solely by our independent directors (within the meaning of the Exchange rules) who are disinterested), we may effect a direct exchange by us of such Class A common stock or such cash, as applicable, for such OpCo Interests. Simultaneously with the payment of cash or shares of Class A common stock, as applicable, in

connection with a redemption or exchange of OpCo Interests pursuant to the terms of the OpCo Agreement, a number of shares of our Class B common stock registered in the name of the redeeming or exchanging Continuing Equity Owner and permitted transferees will automatically be transferred to us for no consideration on a one-for-one basis with the number of OpCo Interests so redeemed or exchanged and such shares of Class B common stock will be canceled. See “Certain Relationships and Related Person Transactions—OpCo Agreement—Agreement in Effect Upon Consummation of the Transactions.”

Use of proceeds

We estimate that the net proceeds from the sale of our Class A common stock in this offering, after deducting the underwriting discount and estimated offering expenses payable by us, will be approximately $ (or $ if the underwriters exercise their option to purchase additional shares of Class A common stock in full) based on an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this prospectus).

We intend to use the net proceeds from this offering, as well as cash on hand, as follows: (i) approximately $ million to prepay, in whole or in part, the outstanding principal of our Senior Notes, (ii) approximately $ million for the redemption of all of the outstanding shares of our Series D preferred stock, (iii) approximately $ million for the redemption of a portion of our outstanding Series B preferred stock, and (iv) the remainder for other general corporate purposes, including payment of a Liquidity Incentive Fee (as defined herein).

We are a holding company and our only assets after consummation of this offering will be our ownership of OpCo Interests and membership units in OP GP. Accordingly, we intend to use the net proceeds from this offering to purchase newly issued OpCo Interests from WhiteHawk OpCo at a price per unit equal to the initial public offering price per share of Class A common stock, less estimated underwriting discounts and commissions. In the event the underwriters exercise their option to purchase additional shares of Class A common stock, we intend to use any such additional proceeds in the same manner. See “Use of Proceeds.”

Dividend Policy

We expect to pay quarterly dividends on our Class A common stock in amounts determined from time to time by our board of directors. However, the declaration and payment of any dividends will be at the sole discretion of our board of directors, which may change our dividend policy at any time. Holders of our Class B common stock are not entitled to participate in any dividends declared by our board of directors. Because we are a holding company, our ability to pay cash dividends on our Class A common stock depends on our receipt of cash distributions from WhiteHawk OpCo and our operating

subsidiaries. Our ability to pay dividends may be restricted by the terms of any future credit agreement or any future debt or preferred equity securities of us. Our ability to pay dividends is also restricted by covenants governing our Senior Notes and Revolving Credit Facility. Our payment of dividends may vary from quarter to quarter, may be significantly reduced or may be eliminated entirely. Future dividend levels will depend on the requirements, regulatory restrictions, any restrictions in financing agreements and other factors deemed relevant by the board. See “Risk Factors—Risks Related to this Offering and Ownership of Our Class A Common Stock—We intend to pay regular dividends to our stockholders, but our ability to do so is subject to the discretion of our board of directors and may be limited…” for additional discussion of factors that could impact our ability to pay dividends. Please read “Dividend Policy.”

Directed Share Program

The underwriters have reserved for sale at the initial public offering price up to % of the Class A common stock being offered by this prospectus for sale to our employees, executive officers, directors, business associates and related persons who have expressed an interest in purchasing Class A common stock in this offering. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. The sales of shares pursuant to the directed share program will be made by Raymond James & Associates, Inc., an underwriter of this offering. Please read “Underwriting.”

Registration Rights Agreement

Pursuant to the Registration Rights Agreement, we will, subject to the terms and conditions thereof, agree to register the resale of the shares of our Class A common stock that are issuable to certain Continuing Equity Owners in connection with the Transactions. See “Certain Relationships and Related Person Transactions—Registration Rights Agreement” for a discussion of the Registration Rights Agreement.

Risk Factors

Investing in our Class A common stock involves risks. See the “Risk Factors” section of this prospectus beginning on page 34 for a discussion of factors you should carefully consider before investing in our Class A common stock.

Listing

We intend to apply to have our Class A common stock listed on the NYSE under the symbol “WHK.”

The number of shares of our Class A common stock that will be outstanding upon the completion of the offering excludes:

•

shares of Class A common stock issuable upon exercise of the underwriters’ option to purchase additional shares;

•

shares of Class A common stock issuable upon the vesting and settlement of restricted stock units outstanding as of ; and

•

additional shares of Class A common stock reserved for future issuance under our Amended and Restated WhiteHawk Income Corporation 2026 Equity Incentive Plan (the “A&R 2026

Plan”) that will become effective on the date our registration statement of which this prospectus forms a part becomes effective, as well as any shares that become issuable pursuant to provisions in the A&R 2026 Plan that automatically increase the share reserve under the A&R 2026 Plan as set forth in “Executive and Director Compensation—Anticipated Changes to our Compensation Program Following This Offering —A&R 2026 Equity Incentive Plan.”

Except as otherwise indicated, all information in this prospectus assumes or gives effect to:

•

the amendment and restatement of the OpCo Agreement that converts all existing ownership interests in WhiteHawk OpCo into OpCo Interests, as well as the filing of our amended and restated certificate of incorporation;

•

the completion of the Transactions;

•

no exercise of the underwriters’ option to purchase up to additional shares of Class A common stock;

•

an initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this prospectus);

•

that no shares are purchased under the directed share program; and

•

our amended and restated certificate of incorporation and our amended and restated bylaws, which will become effective prior to or upon the closing of this offering.

SUMMARY HISTORICAL AND PRO FORMA CONDENSED CONSOLIDATED FINANCIAL

AND OTHER DATA

The following tables present (i) summary historical consolidated financial and other data of the Company and its consolidated subsidiaries and (ii) summary unaudited pro forma condensed consolidated combined financial data for the Company and its subsidiaries.

We derived the summary consolidated balance sheet data as of December 31, 2025 and 2024 and the summary consolidated statements of operations data for the years ended December 31, 2025 and 2024 from our audited consolidated financial statements and related notes thereto included elsewhere in this prospectus (in the case of financial data as of and for the year ended December 31, 2025 as restated in the Restatement). You should read this data together with our consolidated financial statements and related notes included elsewhere in this prospectus and the sections titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our historical results for any prior period are not necessarily indicative of the results of future operations and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and notes thereto included elsewhere in this prospectus.

We derived the summary unaudited pro forma condensed consolidated combined balance sheet as of December 31, 2025 and the summary unaudited pro forma condensed consolidated combined statements of operations for the year ended December 31, 2025 from the unaudited pro forma consolidated financial data included elsewhere in this prospectus. The unaudited pro forma consolidated financial information gives pro forma effect to the transactions described under “Unaudited Pro Forma Condensed Consolidated Combined Financial Information.” The unaudited pro forma condensed consolidated financial data includes various estimates that are subject to material change and may not be indicative of what our operations or financial position would have been had this offering and related transactions taken place on the dates indicated, or that may be expected to occur in the future. See “Unaudited Pro Forma Condensed Consolidated Combined Financial Information” for a complete description of the adjustments and assumptions underlying the summary unaudited pro forma condensed consolidated financial data.

Condensed Consolidated Statements of Operations:


	Historical					Pro Forma⁽¹⁾
	Years Ended December 31,
	2025		2024			2025
	(As Restated)
	(in thousands)
Revenues:
Royalty revenue	$	50,075	$	12,702		$
Gain (loss) on commodity derivative instruments		16,648		(4,418	)
Lease bonus revenue		872		1,166

Total revenue	$	67,595		9,450

Operating expenses:
General and administrative		16,585		2,792
Management fees		9,966		4,681
Depletion, depreciation and accretion		24,237		10,827

Total operating expenses	$	50,788		18,300


	Historical						Pro Forma⁽¹⁾
	Years Ended December 31,
	2025			2024			2025
	(As Restated)
	(in thousands)
Operating income (loss)	$	16,807			(8,850	)
Other expense:
Loss on extinguishment of debt		3,839			359
Loss on sale of assets		123			—
Interest expense, net		19,070			3,939

Income (loss) before income taxes	$	(6,225	)		(13,148	)

Provision for (benefit from) income taxes		(2,640	)		(1,587	)

Net income (loss)	$	(3,585	)	$	(11,561	)	$

(1)	See unaudited pro forma condensed consolidated combined statement of operations for the year ended December 31, 2025 in “Unaudited Pro Forma Condensed Consolidated Combined Financial Information” for more information.

Condensed Consolidated Balance Sheet Data:


	Historical				Pro Forma⁽¹⁾
	As of December 31,
	2025		2024		2025
	(As Restated)
	(in thousands)
Cash and cash equivalents	$	28,989	$	5,330	$
Total assets	$	507,138	$	165,920	$

Total liabilities		270,722		74,128
Total mezzanine equity		27,662		21,225
Total shareholders’ equity	$	208,754	$	70,567	$

(1)	See unaudited pro forma condensed consolidated combined balance sheet as of December 31, 2025 in “Unaudited Pro Forma Condensed Consolidated Combined Financial Information” for more information.

Non-GAAP Financial Measures

Adjusted EBITDA and Cash Available for Distribution (and their pro forma counterparts) are supplemental non-GAAP financial measures used by our management and by external users of our financial statements such as investors, research analysts and others that our management believes are useful to assess the financial performance of our assets and their ability to sustain dividends and/or share repurchases over the long term without regard to financing methods, capital structure or historical cost basis.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion and amortization adjusted for unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, if any, accretion of asset retirement obligations, impairment of oil and natural gas properties, if any, gains and losses on sales of assets, if any, loss on extinguishment of debt, transaction costs and other non-cash or non-recurring operating expenses, if any. We reconcile Adjusted EBITDA to net income (loss), its most directly comparable GAAP measure.

We define Cash Available for Distribution as net cash provided by operating activities excluding amortization of debt issuance costs, interest expense, net, transaction costs, deferred taxes, provision for income taxes,

management fees, and changes in operating assets and liabilities, plus or minus amounts for certain non-cash operating activities, cash interest expense, cash taxes and cash preferred dividends. We reconcile Cash Available for Distribution to net cash provided by operating activities, its most directly comparable GAAP measure.

We define Pro Forma Adjusted EBITDA as Adjusted EBITDA as adjusted for management fees and the effects of the TRR Acquisition and the PHX Acquisition. We define Pro Forma Cash Available for Distribution as Cash Available for Distribution as adjusted for management fees and the effects of the TRR Acquisition and the PHX Acquisition. While these measures do adjust for management fees that we will no longer incur after the Transactions, they do not reflect the full pro forma effects of the Transactions, which are not known as of the date of this registration statement. These measures will be updated to reflect the full pro forma effects of the Transactions in a subsequent amendment to this registration statement.

Adjusted EBITDA and Cash Available for Distribution (and their pro forma counterparts) do not represent and should not be considered alternatives to, or more meaningful than, their most directly comparable GAAP financial measures or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Our non-GAAP financial measures have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP financial measure. Our computations of Adjusted EBITDA and Cash Available for Distribution (and their pro forma counterparts) may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA and Cash Available for Distribution (and their pro forma counterparts) to the most directly comparable GAAP financial measures for the periods indicated:


	Historical						Pro Forma⁽¹⁾
	Years Ended December 31,
	2025			2024			2025
	(As Restated)
	(in thousands)
Net income (loss)	$	(3,585	)		$(11,561	)		$(541)
Interest expense, net		19,070			3,939			19,729
Depletion, depreciation and accretion		24,237			10,827			36,451
Income tax expense (benefit)		(2,640	)		(1,587	)		(1,343	)
Unrealized loss (gain) on commodity derivative instruments		(8,121	)		13,134			(8,121	)
Management fees		—			—			9,966	⁽²⁾
Loss on extinguishment of debt		3,839			359			3,839
Stock-based compensation		179			—			861	⁽³⁾
Transaction costs		7,396			300			11,596	⁽⁴⁾
Loss on the sale of assets		123			—			(6,306	)

Adjusted EBITDA	$	40,498		$	15,411		$	66,131

⁽¹⁾

See our Unaudited Pro Forma Condensed Consolidated Combined Financial Information included elsewhere in this prospectus for more information about our pro forma financial measures. Unless otherwise indicated, these measures reflect adjustments for management fees and the effects of the TRR Acquisition and the PHX Acquisition, but do not reflect the full pro forma effects of the Transactions, which are not known as of the date of this registration statement. These measures will be updated to reflect the Transactions in a subsequent amendment to this registration statement.

⁽²⁾	Reflects inclusion of $6.2 million of Base Management Fees and $3.7 million of Dividend Incentive Fees. After the completion of the Transactions, the Company will no longer incur the Base Management Fees or the Dividend Incentive Fees.

⁽³⁾	Reflects inclusion of $0.7 million of stock-based compensation expense from the historical statement of operations of PHX Minerals incurred during the period from January 1, 2025 through June 23, 2025 (date of acquisition).

⁽⁴⁾	Reflects inclusion of $4.2 million of non-recurring transaction expenses from the historical statement of operations of PHX Minerals incurred during the period from January 1, 2025 through June 23, 2025 (date of acquisition).

The following table presents a reconciliation of Cash Available for Distribution to the most directly comparable GAAP financial measure for the period indicated:


	Historical						Pro Forma⁽¹⁾
	Years Ended December 31,
	2025			2024			2025⁽¹⁾
	(As Restated)
	(in thousands)
Net cash provided by operating activities	$	13,577		$	9,447			23,088	⁽²⁾
Amortization of debt issuance costs		(744	)		(316	)		(744	)
Interest expense, net		19,070			3,939			19,729
Transaction costs		7,396			300			11,596	⁽³⁾
Deferred taxes		3,508			1,587			3,508
Provision for income taxes		(2,640	)		(1,587	)		(1,343	)
Management fees		—			—			9,966	⁽⁴⁾
Changes in operating assets and liabilities		331			2,041			331
Cash interest expense		(19,117	)		(3,780	)		(19,978	)⁽⁵⁾
Cash income taxes		(745	)		(877	)		(1,034	)⁽⁶⁾
Preferred dividends		(7,076	)		(5,114	)		(7,076	)

Cash Available for Distribution	$	13,560		$	5,640			38,043

⁽¹⁾

⁽²⁾	Reflects inclusion of pro forma income statements changes related to the TRR Acquisition and PHX Acquisition.

⁽³⁾	Reflects inclusion of $4.2 million of non-recurring transaction expenses from the historical statement of operations of PHX Minerals incurred during the period from January 1, 2025 through June 23, 2025 (date of acquisition).

⁽⁴⁾	Reflects inclusion of $6.2 million of Base Management Fees and $3.7 million of Dividend Incentive Fees. After the completion of the Transactions, the Company will no longer incur the Base Management Fees or the Dividend Incentive Fees.

⁽⁵⁾	Reflects inclusion of $0.8 million of cash interest expense from the historical statement of operations of PHX Minerals incurred during the period from January 1, 2025 through June 23, 2025 (date of acquisition).

⁽⁶⁾	Reflects inclusion of $0.3 million of cash income taxes from the historical statement of operations of PHX Minerals incurred during the period from January 1, 2025 through June 23, 2025 (date of acquisition).

SUMMARY RESERVE DATA

The following table sets forth (i) estimates of our net proved natural gas, NGL and oil reserves as of December 31, 2025 based on the reserve report prepared by CG&A, (ii) estimates of our net proved natural gas, NGL and oil reserves as of December 31, 2024 based on the reserve report prepared by Schaper Energy, (iii) estimates of the PHX net proved natural gas, NGL and oil reserves as of December 31, 2024 based on the reserve report prepared by CG&A and (iv) estimates of the TRR Seller’s net proved natural gas and oil reserves as of December 31, 2024 based on the reserve report prepared by Ryder Scott. The reserve reports were prepared in accordance with the rules and regulations of the SEC. You should refer to “Risk Factors,” “Business—Our Natural Gas, NGL and Oil Data,” “Business—Our Natural Gas, NGL and Oil Production Prices and Costs,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto included elsewhere in this prospectus in evaluating the material presented below. The following table provides (a) our estimated proved reserves as of December 31, 2025 and (b) our, PHX’s and the TRR Seller’s estimated

proved reserves, as of December 31, 2024, as applicable, using the provisions of the SEC rules regarding reserve estimation regarding a historical twelve-month pricing average applied prospectively. WhiteHawk’s estimates as of December 31, 2024 do not give effect to the PHX Acquisition and the Three Rivers Royalty Acquisition.


	WhiteHawk⁽¹⁾		PHX⁽²⁾		TRR Seller⁽³⁾		Combined WhiteHawk, PHX and TRR Seller⁽⁴⁾		WhiteHawk⁽⁵⁾
	December 31, 2024 (dollars in thousands)								December 31, 2025
Estimated proved developed producing reserves:
Natural gas (MMcf)		64,783		41,648		47,103		153,534		154,137
NGLs (MBbls)		690		1,320		653		2,663		2,914
Oil (MBbls)		23		943		14		980		1,154
Total (MMcfe)⁽⁶⁾		69,061		55,227		51,105		175,393		178,544
Estimated proved developed non-producing reserves:
Natural gas (MMcf)		469		901		2,424		3,794		19,094
NGLs (MBbls)		11		2		61		74		459
Oil (MBbls)		0		5		4		9		203
Total (MMcfe)⁽⁶⁾		535		944		2,814		4,293		23,066
Estimated proved undeveloped reserves:
Natural gas (MMcf)		16,469		6,758		0		23,227		4,149
NGLs (MBbls)		176		26		0		202		84
Oil (MBbls)		16		99		0		115		35
Total (MMcfe)⁽⁶⁾		17,619		7,506		0		25,125		4,864
Estimated proved reserves:
Natural gas (MMcf)		81,721		49,307		49,527		180,555		177,380
NGLs (MBbls)		877		1,348		714		2,939		3,457
Oil (MBbls)		39		1,047		18		1,104		1,392
Total (MMcfe)⁽⁶⁾		87,213		63,677		53,919		204,809		206,473
Standardized Measure ($)	$	61,933	$	76,255	$	45,088	$	183,276	$	266,326
PV-10 ($)⁽⁷⁾	$	72,153	$	79,642	$	45,088	$	196,883	$	293,690

(1)

Our estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For gas volumes, the average Henry Hub spot price calculated in accordance with SEC guidance of $2.13 per MMBtu was adjusted for local basis differential, treating cost, transportation, gas shrinkage and gas heating value (BTU content). For NGLs and oil volumes, the average West Texas Intermediate price calculated in accordance with SEC guidance of $75.48 per barrel as of December 31, 2024 was adjusted for local basis differential, treating cost, transportation and/or crude quality and gravity corrections. All economic factors were held constant throughout the lives of the properties in accordance with SEC guidelines. The average adjusted product prices weighted by production over the remaining lives of the proved properties were $1.788 per Mcf of gas, $26.32 per barrel of NGLs and $65.26 per barrel of oil as of December 31, 2024.

(2)

PHX’s estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For gas volumes, the average Henry Hub spot price calculated in accordance with SEC guidance of $2.13 per MMBtu was adjusted for local basis differential, treating cost, transportation, gas shrinkage and gas heating value (BTU content). For NGLs and oil volumes, the average West Texas Intermediate price calculated in accordance with SEC guidance of $75.48 per barrel as of December 31, 2024 was adjusted for local basis differential, treating cost, transportation and/or crude quality and gravity corrections. All economic factors were held constant throughout the lives of the properties in accordance with SEC guidelines. The average adjusted product prices weighted by production over the remaining lives of the proved properties were $2.051 per Mcf of gas, $20.968 per barrel of NGLs and $73.477 per barrel of oil as of December 31, 2024.

(3)	The TRR Seller’s estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For gas volumes, the average Henry Hub spot price calculated in accordance with SEC guidance of $2.13 per

MMBtu was adjusted for local basis differential, treating cost, transportation, gas shrinkage and gas heating value (BTU content). For NGLs and oil volumes, the average West Texas Intermediate price calculated in accordance with SEC guidance of $75.48 per barrel as of December 31, 2024 was adjusted for local basis differential, treating cost, transportation and/or crude quality and gravity corrections. All economic factors were held constant throughout the lives of the properties in accordance with SEC guidelines. The average adjusted product prices weighted by production over the remaining lives of the proved properties were $1.44 per Mcf of gas, $23.67 per barrel of NGLs and $71.51 per barrel of oil as of December 31, 2024.

(4)

Combined reserve data generally represents the arithmetic sum of the proved reserves attributable to the Company, PHX and the TRR Seller. The proved reserves of PHX and the TRR Seller are based on their respective reserve engineers’ reserve estimation methodologies. Because we will estimate proved reserves in accordance with our own methodologies, the estimates presented herein for PHX and the TRR Seller may not be representative of our future reserve estimates with respect to these properties or the reserve estimates we would have reported if we had owned such properties as of December 31, 2024.

(5)

Our estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For gas volumes, the average Henry Hub spot price calculated in accordance with SEC guidance of $3.387 per MMBtu was adjusted for local basis differential, treating cost, transportation, gas shrinkage and gas heating value (BTU content). For NGLs and oil volumes, the average West Texas Intermediate price calculated in accordance with SEC guidance of $65.34 per barrel as of December 31, 2025 was adjusted for local basis differential, treating cost, transportation and/or crude quality and gravity corrections. All economic factors were held constant throughout the lives of the properties in accordance with SEC guidelines. The average adjusted product prices weighted by production over the remaining lives of the proved properties were $3.03 per Mcf of gas, $22.03 per barrel of NGLs and $62.99 per barrel of oil as of December 31, 2025.

(6)	Natural gas equivalents are calculated using a ratio of six thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs, based on approximate relative energy content. This ratio does not represent the current or historical price relationship between natural gas and oil or NGLs.

(7)

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10% using SEC rules. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize PV-10 as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use PV-10 when assessing the potential return on investment related to our oil and natural gas properties; however, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. PV-10 and the standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves. See “Business—Natural Gas, NGL and Oil Data—Proved Reserves—Reconciliation of Standardized Measure to PV-10.”

RISK FACTORS

Investing in our Class A common stock involves a high degree of risk. You should carefully consider each of the following risk factors, as well as other information contained in this prospectus, including the matters addressed under “Cautionary Note Regarding Forward-Looking Statements,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated financial statements and related notes, before investing in our Class A common stock. The occurrence of any of the following risks could have a material adverse effect on our business, financial condition and results of operations, in which case the trading price of our Class A common stock could decline and you could lose all or part of your investment. Some statements in this prospectus, including statements in the following risk factors, constitute forward-looking statements. See the section of this prospectus captioned “Cautionary Note Regarding Forward-Looking Statements.”

Risks Related to Our Business

Our revenues are primarily derived from mineral and royalty payments that are based on the price at which natural gas, NGLs and oil produced by our third-party operators from the acreage underlying our interests are sold. The volatility of these prices due to factors beyond our control could have a material adverse effect on our business, financial condition and results of operations.

The supply of and demand for natural gas, NGLs and oil impact the revenues we realize and, in turn, could materially affect our financial results. Our revenues, operating results, Cash Available for Distribution and the carrying value of our natural gas, NGL and oil properties depend significantly upon the prevailing prices for natural gas, NGLs and oil. Natural gas, NGL and oil prices have historically been, and will likely continue to be, volatile. The prices for natural gas, NGLs and oil are subject to wide fluctuation in response to a number of factors beyond our control, including:

•

global economic conditions and market uncertainty;

•

changes in the supply of and demand for natural gas, NGLs and oil, both domestically and abroad;

•

the level of global natural gas and oil exploration and production;

•

commodity futures trading and the level of prices and expectations about future prices of natural gas and oil;

•

regional price differentials and differing quality and NGL content of natural gas produced;

•

the price and quantity of imports and the level of U.S. exports of natural gas, NGLs and oil, including the export of natural gas as LNG;

•

availability and development of liquefication facilities to support LNG export demand;

•

actions taken by the Organization of Petroleum Exporting Countries Plus (“OPEC+”) or other major natural gas, NGL and oil producing or consuming countries and the ability of members of OPEC+ to agree to and maintain oil price and production controls;

•

technological advancements affecting energy consumption and energy supply, including the development of AI data centers and related demand for natural gas power generation;

•

the impact of ongoing conflict and changing sanctions regimes in oil or natural gas producing regions, such as Iran, Russia and Venezuela;

•

disruptions to global oil supply and transportation through critical maritime chokepoints, including the Strait of Hormuz, through which a substantial portion of the world’s oil supply transits, due to military conflict, naval blockades, mine deployment, or other hostile actions by state or non-state actors, which could cause significant and rapid fluctuations in global oil prices;

•

risks associated with operating drilling rights;

•

the cost of exploring for, developing, producing and delivering natural gas and oil;

•

the proximity, cost, availability and capacity of natural gas, NGLs and oil pipelines and other transportation and processing facilities;

•

speculative trading in natural gas and crude oil derivative contracts;

•

conservation and environmental protection efforts and the price and availability of, and competition from, alternative fuels;

•

events outside of our control such as weather conditions and other natural disasters, the impacts and effects of public health crises, pandemics and epidemics;

•

changes in U.S. energy policy and other domestic and foreign governmental regulations, taxes, duties and tariffs; and

•

the continued threat of terrorism, social unrest, and political instability or armed conflict in major natural gas and oil producing regions outside the United States and the impact of military and other actions, including, but not limited to, U.S. military operations in the Middle East and Venezuela.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty. Natural gas and oil prices continued to fluctuate in fiscal year 2025, with the benchmark Henry Hub natural gas spot price increasing approximately 58% in 2025 compared to 2024, while the WTI crude oil benchmark declined approximately 15% over the same period. If the prices of natural gas, NGLs and oil decline, our operations, financial condition and level of expenditures for the development of our natural gas, NGL and oil reserves may be materially and adversely affected, and can include other material negative effects including, but not limited to, the following:

•

significantly decrease the number of wells operators drill on our acreage, or the development of pipelines to transport production, thereby reducing our production and cash flows;

•

cash flows would be reduced, decreasing cash available for distribution and/or acquisitions to replace reserves and maintain or increase production;

•

certain reserves may no longer be economic for our operators to produce, leading to lower proved reserves, production and cash flows;

•

future undiscounted and discounted net cash flows from producing properties would decrease, possibly resulting in recognition of impairment expense;

•

access to sources of capital, such as equity and debt markets, could be severely limited or unavailable; and

•

could limit our ability to make scheduled payments on our First Lien Senior Secured Notes (our “Senior Notes”) and our Revolving Credit Facility (our “Revolving Credit Facility”).

Lower natural gas, NGL and oil prices or negative adjustments to natural gas, NGL and oil reserves may result in significant impairment charges.

The Company follows the successful efforts method of accounting for our natural mineral operations. Under this method, costs to acquire mineral and royalty interests in natural gas mineral properties are capitalized when incurred. We review and evaluate our mineral and royalty interests in natural gas mineral properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Proved natural gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and a discount rate commensurate with the risk reflective of the lives remaining for the respective natural gas properties. Because of

the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded. If an impairment charge is recognized, cash flows from operating activities is not impacted, but net income and, consequently, stockholders’ equity are reduced. In periods when impairment charges are incurred, it could have a material adverse effect on our results of operations.

Historically, natural gas, NGLs and oil prices have been volatile and may continue to be volatile in the future. During the past five years, the Henry Hub spot market price for natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $23.86 per MMBtu in February 2021. The posted price for WTI has ranged from a low of negative $36.98 per barrel in April 2020 to a high of $123.64 per barrel in March 2022. As of December 31, 2025, the posted price for WTI was $57.26 per barrel and the Henry Hub spot market price of natural gas was $4.00 per MMBtu. Lower prices not only decrease our revenues, but also potentially impact the amount of natural gas, NGLs and oil that our operators can produce economically. This, in turn, can impact the capital budgets for our operators and their development pace of our properties. We expect commodity price volatility will continue in the future. If these pricing trends persist, our revenues and cash flows could be materially reduced, which could adversely affect our ability to pay dividends, service our debt obligations, and pursue our acquisition strategy. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional discussion of the impact of commodity prices on our business.

See “Note 2, Summary of Significant Accounting Policies—Mineral Interests in Natural Gas Properties” to the audited consolidated financial statements included elsewhere in this prospectus for further discussion.

Our derivative activities may reduce the cash flows received for natural gas and oil sales.

In order to manage exposure to price volatility on our natural gas and oil production, we currently, and may in the future, enter into natural gas and oil derivative contracts for a portion of our expected production. Natural gas and oil price derivatives may limit the cash flows we actually realize and therefore reduce our ability to fund future projects. None of our natural gas and oil price derivative contracts are designated as hedges for accounting purposes; therefore, all changes in fair value of derivative contracts are reflected in earnings. Accordingly, these fair values may vary significantly from period to period, materially affecting reported earnings. In addition, this type of derivative contract can limit the benefit we would receive from increases in the prices for natural gas and oil. The fair value of our natural gas and oil derivative instruments outstanding as of December 31, 2025 was approximately a net asset of $0.7 million.

There is risk associated with derivative contracts that involves the possibility that counterparties may be unable to satisfy contractual obligations to us. If any counterparty to our derivative instruments were to default or seek bankruptcy protection, it could subject a larger percentage of our future natural gas and oil production to commodity price changes, could adversely affect our cash flows and could have a negative effect on our ability to fund future acquisitions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.”

The development of our properties in which we own mineral and royalty interests relies exclusively on our various third-party operators. Our third-party operators’ failure to develop our existing inventory of mineral and royalty acreage could have a material adverse effect on our business, financial condition and results of operations.

We depend exclusively on various unaffiliated third-party operators for all of the exploration, development and production of our mineral and royalty interests and a substantial amount of our revenue is derived from royalty payments made by these third-party operators. We are unable to determine with certainty which third-party operators will ultimately operate our properties and there is no guarantee that any particular third-party operator will become or remain the operator on the properties associated with our mineral and royalty interests, and such third-party operators may identify, and subsequently focus their efforts and development on, prospects in which we do not maintain mineral or royalty interests. A reduction in the expected number of wells to be drilled on our

acreage by these operators or the failure of our third-party operators to adequately and efficiently develop and operate the wells on our acreage could have a material adverse effect on our business, financial conditions and results of operations. The success and timing of drilling and development activities and whether the operators elect to drill any additional wells on our acreage depends on a number of factors that are largely outside of our control, including:

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the capital costs required for drilling activities by our third-party operators, which could be significantly more than anticipated;

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the ability of our third-party operators to access capital;

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prevailing commodity prices;

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

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the availability of storage for hydrocarbons;

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the operators’ expertise, operating efficiency and financial resources;

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approval of other participants in drilling wells;

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the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;

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the selection of technology;

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the selection of counterparties for the marketing and sale of production; and

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the rate of production of the reserves.

Our proved undeveloped reserves may not be developed or produced as a result of any number of these factors. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue development of a proved undeveloped drilling location will be made by our third-party operators and not by us. Our third-party operators may elect not to undertake development activities or may undertake to develop these activities in a delayed or an unanticipated fashion, which may result in significant fluctuations in the revenues generated by our mineral and royalty interests. Third-party operators will make decisions in connection with their operations, which may not be in our best interests and our third-party operators may also reduce capital expenditures devoted to exploration, development and production on our properties in the future, which could negatively impact the revenues we receive. We have limited ability to exercise influence over the operational decisions of our third-party operators, including the setting of capital expenditure budgets and drilling locations and schedules.

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

Drilling for natural gas and oil invariably involves unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient reserves to return a profit after deducting drilling, completion, operating and other costs. In addition, wells that are profitable may not achieve a targeted rate of return. We rely on third-party operators for substantially all of the exploration, development, and production activities on our acreage. Nevertheless, prior to drilling a well, the exploration and development activities used do not allow operators to know conclusively whether natural gas, NGLs and oil are present in commercial quantities.

Cost factors can adversely affect the economics of any project, and the eventual cost of drilling, completing and operating a well is controlled by well operators and existing market conditions. Further, drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

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unexpected drilling conditions;

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title problems;

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pressure or irregularities in formations;

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equipment failures or accidents;

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fires, explosions, blowouts and surface cratering;

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lack of availability to market production via pipelines or other transportation;

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adverse weather conditions;

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environmental, health or safety hazards or liabilities;

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lack of water disposal facilities;

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environmental and other governmental regulations;

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cost and availability of drilling rigs, equipment, materials and services; and

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expected sales price to be received for natural gas, NGLs and oil produced from the wells.

Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our third-party operators’ failure to drill sufficient wells to hold acreage may result in loss of the lease and prospective drilling opportunities.

Leases on natural gas and oil properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. Any reduction in our third-party operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations which may terminate our overriding royalty interests derived from such leases. Since our royalties are derived from mineral interests, if production or drilling ceases on the leased property, the lease is typically terminated, subject to certain exceptions, and all mineral rights revert back to us, and we will have to seek new lessees to explore and develop our acreage. There can be no assurance that we will be able to re-lease such properties following termination on favorable terms, or at all. Any such losses of our third-party operators or lessees could materially and adversely affect the growth of our business, financial condition and results of operations.

We may experience delays in the receipt of royalty payments and be unable to replace our third-party operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of such operators on those leases declare bankruptcy.

We may experience delays in receiving royalty payments from our third-party operators, including as a result of delayed division orders received from our third-party operators. Additionally, most of our operators are also dependent on the availability of external debt and equity financing sources to maintain their drilling programs. If those financing sources are not available to the operators on favorable terms or at all, or if an operator were to otherwise experience financial difficulty, the operator might not be able to make its royalty payments or continue its operations, which could have a material adverse impact on our business. A failure on the part of our third-party operators to make royalty payments typically gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. If the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell natural gas or oil at the same price as the operator we replaced.

We may incur losses as a result of title defects or other issues in the properties we own which could have a material adverse effect on our business, financial condition and results of operations.

We depend in part on acquisitions to grow our reserves, production and cash generated from operations. In connection with these acquisitions, record title to mineral and royalty interests are conveyed to us or our subsidiaries by asset assignment, and we or our subsidiaries become the record owner of these interests. Upon such a change in ownership of mineral and royalty interests, and at regular intervals pursuant to routine audit procedures at each of our third-party operator’s discretion, such third-party operator of the underlying property has the right to investigate and verify the title and ownership of mineral and royalty interests with respect to the properties it operates. Consistent with industry practice, we do not have current abstracts or title opinions on all of our mineral acreage and, therefore, cannot be certain that we have unencumbered title to all of these properties. The third-party operators of our properties could suspend our right to receive royalty payments due to title or other issues and we are not required to, and under certain circumstances we may elect not to, incur the expense of retaining lawyers to examine the title to our mineral and royalty interests. If any title or ownership issues are not resolved to the third-party operator’s reasonable satisfaction in accordance with customary industry standards, the third-party operator may suspend payment of the related royalty. Our failure to cure any title defects that may exist may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. At any time that a third-party operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying natural gas, NGLs and oil related to such mineral interest. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. Leases in the Appalachian Basin, and particularly leases involving gas and oil properties, are particularly vulnerable to title deficiencies due to the nature of the history of land ownership in the area, resulting in extensive and complex chains of title. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our business, financial condition and results of operations. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we may suffer a financial loss and it could have a material adverse effect on our business, financial condition and results of operations.

A limited number of operators currently generate a significant portion of our revenue and accounts receivable.

A large portion of our current mineral and royalty interests and lease holdings are serviced by a limited number of third-party operators and, as a result, we generate a significant portion of our revenue and accounts receivable from a limited number of third-party operators. In the year ended December 31, 2025, we received revenue from 365 third-party operators, with approximately 54% of our consolidated revenue coming from the top three third-party operators. Our revenue is generally derived from our diverse holdings of mineral and royalty interests and lease holdings and these mineral and royalty interests generate revenue from the sale of natural gas and crude oil, which is paid monthly to us by various third-party operators once any extracted natural gas and crude oil is delivered by such operators to purchasers.

While our revenue and accounts receivable relating to our mineral rights and lease holdings are derived from a significant number of different units that are subject to different leases and pooling orders from various state oil and gas commissions, the incapacity or loss of one of the operators that generate a significant portion of our revenue and accounts receivable could negatively impact our revenue and accounts receivable and could result in a reduction or delay in revenue generated from the related mineral rights and lease holdings while a replacement operator is selected and designated. Further, we do not always determine or control the rights, payments, discounts or other terms related to leases or the extraction and sale of assets from our mineral rights and lease holdings.

Various factors could adversely impact our third-party operators’ ability to control costs, including their operating expenses and capital costs.

Our third-party operators are dependent on various supplies and equipment, as well as qualified personnel, to carry out their extraction operations. An increase in natural gas and oil prices may cause the costs of such materials and services to rise. Furthermore, any shortage, unavailability, or increase in the cost of such supplies, personnel, equipment, and parts could have a material adverse effect on their ability to carry out operations. We cannot predict any future trends in the rate of inflation or interest rates and a significant increase in inflation or interest rates, to the extent we or our third-party operators are unable to recover higher costs through higher commodity prices and revenues or otherwise mitigate the impact of such costs on our or their business, could have a material adverse effect on our business, financial condition and results of operations.

The substantial majority of our business is concentrated in the Appalachian and Haynesville Basins, making us vulnerable to risks associated with concentration of our assets in limited geographic areas.

The substantial majority of our business is concentrated in the Appalachian and Haynesville Basins. As a result, we may be disproportionately exposed to various factors, including, among others:

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the impact of regional supply and demand factors;

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delays or interruptions of production from wells in such areas caused by governmental regulation, including changes to field wide rules;

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gathering, processing or transportation capacity constraints;

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availability of equipment, facilities, personnel or services market limitations;

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adverse weather conditions and natural disasters;

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plant closures for scheduled maintenance, resulting in reduced demand for natural gas; and/or

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interruption of the processing or transportation of natural gas, NGLs and/or oil.

This concentration in limited geographic areas also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the region, such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these factors has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs, and prevent development of leases before expirations. Any of the risks described above could have a material adverse effect on our business, financial condition and results of operations.

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic areas, which may cause these conditions to occur with greater frequency to our properties or magnify the effects of these conditions. Due to the concentrated nature of our 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. In addition, we have limited to no control over the marketability of our hydrocarbon sales and rely on third-party operators to market our hydrocarbons which limits our ability to optimize the pricing we receive, especially in instances of regional bottlenecks. As a result of our focus on the Appalachian and Haynesville Basins, we may be less competitive than other companies in bidding to acquire assets that include properties both within and outside of those areas.

We may be subject to risks related to our wells where we are a non-operating working interest owner which could have a material adverse effect on our business, financial condition and results of operations.

Like our mineral and royalty interests, we are dependent upon third-party operators to develop the properties in which we own non-operating working interests. In addition, financial risks are inherent in any operation where

we have a non-operating working interest and the cost of drilling, equipping, completing and operating wells is shared by more than one party. We could be responsible for joint activity obligations of a working interest owner, such as nonpayment of expended costs, including costs of regulatory compliance. We may also be liable for damage to the environment caused by our third-party operators. Additionally, if another non-operator fails to pay its share of costs because of its insolvency or otherwise, the third-party operator could require us to pay the proportionate share of the defaulting party’s share of costs. We are also responsible for our proportionate share of the costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that we own (or own in part) for production of natural gas and oil reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “asset retirement.” We accrue a liability for asset retirement costs associated with these wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. It may be difficult for us to predict such asset retirement costs. If asset retirement is required before economic depletion of our properties or if our estimates of the costs of asset retirement exceed the value of the reserves remaining at any particular time to cover such asset retirement costs, we may have to draw on funds from other sources to satisfy such costs, which may be substantial. The use of other funds to satisfy such asset retirement costs could impair our ability to dedicate our capital to other areas of our business.

Our future success depends on replacing reserves through acquisitions and the exploration and development activities of our operators.

Producing natural gas and oil wells, and associated NGLs, are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our natural gas, NGLs and oil reserves and our third-party operators’ production thereof and our cash flows are highly dependent on the successful development and exploitation of our current reserves and our ability to successfully acquire additional reserves that are economically recoverable. We have little to no control over the exploration and development of our properties and the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find or acquire additional reserves to replace the current and future production of our properties at economically acceptable terms and we may not have sufficient resources to acquire such reserves.

There is intense competition for acquisition opportunities in our industry which may increase the cost of, or cause us to refrain from, completing acquisitions. The successful acquisition of producing properties requires an assessment of several factors, including recoverable reserves, future oil and natural gas prices and their applicable differentials, operating costs and potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. If we are not able to adequately replace or grow our natural gas, NGLs and oil reserves, our business, financial condition and results of operations would be adversely affected.

Constraints in financing mineral and royalty asset acquisitions, and the risks associated with entering new geographic markets, may adversely affect our business, financial condition, and results of operations.

Our ability to complete acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Furthermore, we cannot assure you that we will be able to access the capital markets after this offering or obtain other external capital on terms favorable to us or at all. Additionally, our ability to secure financing or access the capital markets could be adversely affected if financial institutions and institutional lenders elect not to provide funding for fossil fuel energy companies in connection with the adoption of sustainable lending initiatives or are required to adopt policies that have the effect of reducing the funding available to the fossil fuel sector. If we are unable to access capital, we may be unable to complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on business, financial condition and results of operations.

In addition, if we determine to enter into new geographic markets, such entry into new geographic markets may result in the dilution of our resources dedicated to our current geographic focus and we may be subject to

additional and unfamiliar legal and regulatory requirements. Compliance with added regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. 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 suitable mineral and royalty interest acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.

We have experienced significant business and portfolio growth in a short time, which may make it difficult for you to evaluate our business and prospects. Our previous growth rates and performance may not be sustainable or indicative of our future growth and financial results, and there can be no assurance that we will be able to achieve the same level of financial performance in the future. If we are unable to manage our business and growth effectively, our business could be materially and adversely affected.

Our business has grown considerably since our founding in 2022. The significant growth in the size and diversity of our mineral and royalty interests and revenue we have experienced since our founding makes evaluation of our business and prospects difficult. There can be no assurance that our growth will continue at a similar pace, or that we will be able to manage our growth effectively. Furthermore, the growth of our business places significant demands on our key personnel, including managing increased numbers of interests, revenue streams, operator relationships, and title administration responsibilities. If we do not effectively manage the increased obligations brought by the growth of our business, we may not be able to execute on our business plan, respond to competitive pressures or take advantage of market opportunities, which could have a material adverse effect on our business, financial condition and results of operations.

Our historical results, including our historical cash-on-cash returns, may not be sustainable, and we cannot assure you that we will achieve similar cash-on-cash returns or continue to pay cash or stock dividends. The historical returns to our investors should not be considered as indicative of the future results of our operations or any returns expected on an investment in our Class A common stock. In addition, we expect our overall general and administrative expenses to continue to increase in the foreseeable future, as we may be required to hire additional personnel and incur additional expenses as a newly public company. These efforts and additional expenses may be more costly than we currently expect, and there is no assurance that we will be able to maintain sufficient operating revenue to offset our operating expenses. Any failure to increase revenue or to manage our costs would adversely impact our business and could prevent us from maintaining positive operating cash flow at all, or on a consistent basis, which would cause our business, financial condition, and results of operations to suffer.

In addition, we may encounter risks and difficulties experienced by companies whose performance is dependent upon newly acquired mineral and royalty interests, such as failing to integrate, or realizing the expected benefits of, such assets. As a result of the foregoing, we may be less successful in achieving consistent results and sustaining the growth of our business, as compared with companies that have longer histories of operations and more stable portfolios of mineral and royalty assets. In addition, we may be less equipped to identify and address risks and hazards in the conduct of our business than those companies that have longer operating histories.

Any acquisition of additional mineral and royalty interests that we complete will be subject to substantial risks.

Any acquisition of mineral and royalty interests involves substantial risks, all of which could have a material adverse effect on our business, financial condition and results of operations. Even if we identify attractive acquisition opportunities, we may not be able to complete such acquisitions or do so on commercially acceptable terms. We also typically bear certain transactional expenses (including professional fees, legal fees and other due diligence-related items) and the costs of investments that are not consummated (i.e. broken deal costs). Any

acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks and we may acquire interests in properties that do not produce as projected. Such risks include, but are not limited to:

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the validity of our assumptions about estimated reserves, future production, prices, revenues, operating expenses and costs;

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a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;

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a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

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the inability to effectively manage the integration of acquisitions could adversely impact our ability to achieve the anticipated benefits of our acquisitions and reduce our focus on subsequent acquisitions and current operations;

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the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

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mistaken assumptions about the overall cost of equity or debt;

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our ability to obtain satisfactory title to the assets we acquire;

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an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

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the occurrence of other significant changes, such as impairment of natural gas and oil properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

In addition, the due diligence required with respect to a potential natural gas and oil royalty investment may not reveal or highlight all relevant facts that may be necessary or helpful in evaluating such an investment opportunity and its potential risks. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The accuracy of these assessments is inherently uncertain and, as a result, we may assume unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate. We may base our decisions on mistaken assumptions about estimated reserves, future production, prices, revenues, the operating expenses and costs our third-party operators would incur to develop the minerals. Our review will not reveal all existing or potential problems including title defects or environmental issues, which, if material, can render an interest worthless, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Environmental or other regulatory issues may arise with respect to acquired entities or operations years after the acquisitions. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of such problems. Significant acquisitions and other strategic transactions may involve other risks that may cause our business to be adversely impacted, including diversion of our management’s attention to evaluating and negotiating such transactions. As a result of the foregoing, any acquisition of mineral and royalty interests involves both foreseen and unforeseen risks, all of which could have a material adverse effect on our business, financial condition and results of operations.

We expect to distribute a substantial majority of the cash we generate from operations, which could limit our ability to grow and make acquisitions.

We expect to distribute a substantial majority of the cash we generate from operations each quarter. As a result, we will have limited cash generated from operations to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. If we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

If we issue additional shares of Class A common stock in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional shares of Class A common stock may increase the risk that we will be unable to maintain or increase our per unit distribution level. The incurrence of additional commercial borrowings or other debt to finance our growth would result in increased interest expense and required principal repayments, which, in turn, may reduce the cash that we have available to distribute to our shareholders. See “Dividend Policy” for more information.

While we expect to distribute a substantial majority of the cash we generate from operations each quarter, there can be no assurance that we will be able to pay dividends at the levels we currently anticipate, or at all. Our ability to pay dividends is subject to significant restrictions and limitations, including:

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Covenants under our Revolving Credit Facility. Under the Revolving Credit Facility, we may not declare or make any restricted payment (including dividends, distributions in respect of, or redemptions of, our equity interests) except as specifically permitted. Permitted restricted payments include, among others, cash dividends and distributions to holders of our equity interests so long as, both before and immediately after giving pro forma effect to any such restricted payment, (i) no default, event of default or borrowing base deficiency exists or would result therefrom, (ii) Unused Availability (as defined in the Revolving Credit Facility) is at least 10% of the Loan Limit (as defined in the Revolving Credit Facility) and (iii) the Consolidated Net Leverage Ratio (as defined in the Revolving Credit Facility), recomputed on a Pro Forma Basis (as defined in the Revolving Credit Facility), is less than or equal to 3.00 to 1.00; provided that, prior to the discharge of the obligations under the Note Purchase Agreement, such restricted payments are also permitted under the Note Purchase Agreement, as in effect immediately following the amendment to the Note Purchase Agreement. See “Description of Material Indebtedness.” The Revolving Credit Facility also permits Permitted Tax Distributions (as defined in the Revolving Credit Facility), distributions to our parent to fund Public Company Compliance costs and ordinary-course corporate overhead in an aggregate amount not to exceed $3,000,000 per fiscal year, distributions and repurchases pursuant to management or employee equity plans (capped at $1,000,000 per fiscal year), stock-settled dividends, cash payments in lieu of fractional shares and certain other limited exceptions. In addition, the Revolving Credit Facility requires us to maintain, as of the last day of each fiscal quarter (commencing with the first full fiscal quarter ending after the effective date thereof), (i) a Consolidated Net Leverage Ratio for the rolling period then ending of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Revolving Credit Facility) of not less than 1.0 to 1.0, and to satisfy minimum hedging requirements that vary based on the Consolidated Net Leverage Ratio, each of which may limit our flexibility to make distributions or otherwise reduce cash that would otherwise be available for dividends. The Revolving Credit Facility also contains a “most favored term” provision pursuant to which any representation, warranty, covenant (including financial covenants), event of default or other term (excluding applicable margin for determining interest rates) in the Note Purchase Agreement that is more restrictive than the corresponding term of the Revolving Credit Facility will be automatically incorporated into the Revolving Credit Facility, with the result that the Revolving Credit Facility will at all times contain restrictions on restricted payments, negative covenants and other matters that are at least as restrictive as those in the Note Purchase Agreement governing our Senior Notes.

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Covenants under our Senior Notes. We are currently in negotiations with the lenders under our Note Purchase Agreement and expect to enter into an amendment providing, among other things, more favorable restricted payment covenants in connection with the completion of this offering. However, there can be no guarantee that we will enter into such amendment on terms satisfactory to us or at all. See “—Risks Related to Our Indebtedness—The Revolving Credit Facility and the Note Purchase Agreement restrict our ability to pay cash dividends and make other distributions to our stockholders.” Under the Note Purchase Agreement (prior to effect to the amendment to the Note Purchase Agreement (as described under “Description of Material Indebtedness”)) governing our Senior Notes, we may not make restricted payments (such as dividends or stock redemptions) except as specifically permitted thereby. See “Description of Material Indebtedness.”

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Delaware law limitations. Under the Delaware General Corporation Law, we may only pay dividends out of surplus (the excess of net assets over capital) or, if there is no surplus, out of net profits for the current and/or immediately preceding fiscal year.

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Business and liquidity needs. Our board of directors may determine to reduce or eliminate dividends to fund acquisitions, repay debt, satisfy working capital needs, or address other business requirements.

Additionally, our ability to pay dividends may be restricted by the terms of any future credit agreement or any future debt or preferred equity securities of us. See “Risk Factors—We intend to pay regular dividends to our stockholders, but our ability to do so is subject to the discretion of our board of directors and may be limited…” and “Description of Material Indebtedness” for additional information regarding restrictions on our ability to pay dividends.

If we fail to retain our key personnel or attract additional qualified personnel, we may not be able to achieve our business strategy which could have a material adverse effect on our business, financial condition and results of operations.

Our future success and ability to implement our business strategy depends, in part, on our ability to attract, train, compensate, motivate and retain key personnel and service providers, and on the continued contributions of members of our management team and key employees or service providers, each of whom would be difficult to replace. We are a relatively new company and rely heavily on our executives and management team for their knowledge of the natural gas and crude oil industry and experience identifying, evaluating and completing acquisitions. The departure of executives or other members of our management or key personnel or key service providers could disrupt our business, as competition for highly skilled individuals with technical expertise is extremely intense within and outside of our markets, and we face challenges identifying, hiring, training and retaining qualified personnel and service providers in many areas of our business. Integrating new key personnel into our team and identifying and coordinating with key service providers could prove disruptive to our operations, require substantial resources and management attention and ultimately prove unsuccessful. The ability to remain competitive by offering competitive compensation packages and programs for growth and development of personnel, with a view to retaining existing talent and attracting new talent, and attracting key service providers, has become increasingly important to our business and its operations in the current climate. We cannot be certain that our labor costs will not increase as a result of a shortage in the supply of skilled, unskilled and technical personnel or any related governmental regulations, or due to the need to recruit and retain key personnel and service providers. Labor shortages and/or an inability to retain our executives, other senior management, and other key personnel, service providers, and talent or to attract and train additional qualified personnel and service providers could limit or delay our ability to implement our business strategy, all of which could have a material adverse effect on our business, financial condition and results of operations.

Our management team and board of directors may also perform similar services for other businesses and thus are not solely focused on our business.

Our officers and directors are not required to, and may not, commit their full time to our affairs, which may result in challenges allocating their time between our operations and the other businesses at which they may serve in similar or other roles. Certain of our officers are engaged in other business endeavors for which he or she may be obligated to contribute significant time and attention. Additionally, certain of our directors may also serve as officers or board members for other entities. For example, prior to this offering, our executive officers served in similar capacities with the manager. If our officers’ and directors’ other business affairs require them to devote substantial amounts of time to such affairs in excess of their current commitment levels, it could limit their ability to devote time to our affairs which may have a negative impact on our business. The other business activities of our officers and directors may create potential conflicts of interest, including situations where they may be presented with investment or business opportunities that could benefit both the Company and another entity with which they are affiliated. In such cases, our officers or directors may be required to determine how to allocate such opportunities, and there can be no assurance that any such determination will be made in our favor. Additionally, our officers and directors may have fiduciary duties to other entities that could conflict with their

duties to us. For a complete discussion of our officers’ and directors’ other business affairs, please see the section of this prospectus entitled “Management.”

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves, business, financial condition and results of operations.

It is not possible to measure underground accumulations of natural gas, NGLs and oil with precision. Natural gas, NGL and oil reserve engineering requires subjective estimates of underground accumulations of natural gas, NGLs and oil using assumptions concerning future prices of these commodities, future production levels and operating and development costs. In estimating our reserves, we and our independent petroleum engineer must make various assumptions with respect to many matters that may prove to be incorrect, including:

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future natural gas, NGL and oil prices;

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unexpected complications from offset well development;

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production rates;

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reservoir pressures, decline rates, drainage areas and reservoir limits;

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interpretation of subsurface conditions including geological and geophysical data;

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potential for water encroachment or mechanical failures;

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levels and timing of capital expenditures, lease operating expenses, production taxes and income taxes, and availability of funds for such expenditures; and

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effects of government regulation.

As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may turn out to be incorrect. If any of these assumptions prove to be incorrect, our estimates of reserves, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

Our standardized measure of natural gas and oil reserves is calculated using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month individual product prices for each month within the 12-month period prior to fiscal year end. These prices and the operating costs in effect as of the date of estimation are held flat over the life of the properties. Production and income tax expenses are deducted from this calculation of future estimated development, with the result discounted at 10% per annum to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. Since forward-looking prices and costs are not used to estimate discounted future net cash flows from our estimated reserves, the standardized measure of our estimated reserves is not necessarily the same as the current market value of our estimated proved natural gas, NGL and oil reserves. The timing of the development and production on our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production. In addition, the 10% discount factor used when calculating discounted future net cash flows, in compliance with the FASB statement on natural gas and oil producing activities disclosures, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company, or the natural gas and oil industry in general.

The reserve estimates made for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy records. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures. Further, our lack of knowledge of all individual well information known to the well operators such as incomplete well stimulation efforts, restricted production rates for various reasons and up-to-date well production data, etc. may cause differences in our reserve estimates.

In addition, the reserve data included in our reserve reports assume that substantial capital expenditures are required to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves, or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. Because PUD reserves, under SEC reporting rules, may only be recorded if the wells they relate to are scheduled to be drilled within five years of the date of recording, the removal of PUD reserves that are not developed within this five-year period may be required.

Our identified drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. Further, our estimates of these locations are based on assumptions derived from the publicly available disclosure of our third-party operators and industry-wide results of operations, which may not be accurate or ultimately come to fruition. As a result, there is no guarantee that our estimates will be consistent with potential drilling locations that our third-party operators have identified or that the actual drilling activities of our third-party operators will be materially consistent with those presently identified.

Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. The potential drilling locations we have identified are based on geologic and other data available to us and our interpretation of such data through our specialized software. Our third-party operators may have reached different conclusions about the potential drilling locations on our properties, and our third-party operators control the ultimate decision as to where and when a well is drilled. As result, such estimates may not be accurate and the ultimate number of wells drilled on our properties may be lower than expected. Whether these locations are ultimately drilled and developed depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms, seasonal conditions and the actions of other operators. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if our third-party operators will be able to economically produce hydrocarbons from these or any other potential drilling locations. The actual drilling activities on our acreage may be materially different from our current expectations, which could adversely affect our business, financial condition and results of operations.

We rely on our third-party operators, other third parties and government databases for information regarding our assets and, to the extent that information is incorrect, incomplete or lost, our financial and operational information and projections may be incorrect.

As an owner of mineral and royalty interests, we rely on our third-party operators to notify us of information regarding production on our properties in a timely and complete manner, as well as the accuracy of information obtained from third parties and government databases. We use this information to evaluate our operations and cash flows, as well as to predict our expected production and possible future locations. To the extent we do not timely receive this information or the information is incomplete or incorrect, our results may be incorrect and our ability to project potential growth may be materially adversely affected. Furthermore, to the extent that we have to update any publicly disclosed results or projections made in reliance on this incorrect or incomplete information, investors could lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock. If any of such third-party or government databases or systems were to fail for any reason, including as a result of a cyber-attack, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any of the foregoing consequences could materially adversely affect our business, financial condition and results of operations.

We may be subject to information technology system failures, network disruptions, cyber-attacks or other breaches in data security.

The natural gas and oil industry has generally become increasingly dependent upon digital technologies to conduct day-to-day operations. As such reliance on technology has increased, so have the risks posed to both us

and our third-party operators. Our third-party operators are likely dependent on digital technologies to conduct certain exploration, development, production and processing activities, including interpreting seismic data, managing drilling rigs, production activities and gathering systems, conducting reservoir modeling and estimating reserves. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. If our third-party operators become the target of cyber-attacks with security breaches of information, their business operations may be substantially disrupted, which could have an adverse effect on our business, financial condition and results of operations. Cyber incidents could also cause operational interruption, compromise our confidential information and damage our reputation.

We and our third-party operators also face increased risk with the growing sophistication of generative AI capabilities, which may improve or expand the existing capabilities of cybercriminals described above in a manner we cannot predict at this time. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

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

We may from time to time be involved in various legal and other proceedings, including, without limitation, title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters in the ordinary course of our business. Such legal 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, and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in 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 and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. 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.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries (including the war in Ukraine, ongoing conflict in Iran and the Israel-Hamas conflict) may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for natural gas, NGLs and oil, potentially putting downward pressure on demand for our third-party operators’ services and causing a reduction in our revenues. Natural gas, NGL and oil-related facilities, including those of our third-party operators, could be direct targets of terrorist attacks, and, if infrastructure integral to our third-party operators or the purchasers of their production is destroyed or damaged, they may experience a significant disruption in their operations which, in turn, could materially adversely affect our business, financial condition and results of operations. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, cash flows and financial position.

Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages, the imposition of new tariffs, geopolitical issues, high levels of inflation, the availability and cost of credit and the U.S. financial market and other factors have contributed to increased global economic uncertainty. The United States experienced a significant increase in inflation beginning in the second half of 2021, and, although inflation has moderated throughout 2024 and 2025, higher interest rates have generally persisted. To the extent elevated inflation and interest rates remain or increase, our third-party operators may experience further cost increases for their labor and operations, including oil field services and equipment. Our third-party operators

may also experience supply chain constraints, due to international trade policies or otherwise, and inflationary pressure on their cost structures, which could impact the revenues we receive from them. Our third-party operators also may face shortages of equipment, raw materials, supplies, commodities, labor and services, which may prevent them from executing their development plans on or around our land. These supply chain constraints, trade policies and inflationary pressures may continue to adversely impact our third-party operators’ operating costs and, if they are unable to manage their supply chain, it may impact their ability to procure materials and equipment in a timely and cost-effective manner, if at all, which could materially and adversely affect our business, financial condition and results of operations.

We recently restated our audited consolidated financial statements as of and for the fiscal year ended December 31, 2025 to correct material accounting errors and have identified material weaknesses in our internal control over financial reporting. As a result of the material weaknesses in internal control over financial reporting, our disclosure controls and procedures were not effective at a reasonable assurance level as of December 31, 2025. A failure to maintain effective internal control over financial reporting or disclosure controls and procedures could impact our ability to accurately and timely report our financial results and other material disclosures or otherwise cause us to fail to meet our reporting obligations, which could have a material adverse effect on our operations and investor confidence in our business.

On April 22, 2026, we concluded that our audited consolidated financial statements as of and for the fiscal year ended December 31, 2025 could no longer be relied upon as a result of material accounting errors identified by management subsequent to the issuance of our audited consolidated financial statements for the fiscal year ended December 31, 2025. Accordingly, the audited consolidated financial statements for the fiscal year ended December 31, 2025 included elsewhere in this prospectus were restated by the Company in order to reflect the correction of the identified errors related to (i) the recording of management fees and (ii) the misclassification of pre-closing date and post-effective date monies received related to acquisitions. For additional information, see “Note 3, Restatement of Financial Statements” to our audited consolidated financial statements for the fiscal year ended December 31, 2025 included elsewhere in this prospectus. As a result of the Restatement, we are subject to additional risks and uncertainties, including unanticipated legal and accounting costs, litigation, governmental proceedings or investigations and loss of investor confidence or reputational harm to our business.

Although management did not, and was not required to, conduct a formal assessment of internal control over financial reporting as of December 31, 2025, as a result of the Misstatement and the Restatement, the Company identified certain material weaknesses in its internal control over financial reporting. As a result of the material weaknesses in internal control over financial reporting, our disclosure controls and procedures were not effective at a reasonable assurance level as of December 31, 2025. Management will be implementing changes to strengthen our internal controls and remediate the material weaknesses. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Internal Controls and Procedures—Material Weaknesses in Internal Control over Financial Reporting” for additional information related to the material weaknesses in internal control over financial reporting and our related remediation activities.

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 a company’s consolidated interim or annual financial statements will not be prevented or detected on a timely basis. As such, if we do not remediate these material weaknesses in a timely manner, or if additional material weaknesses in our internal control over financial reporting are discovered, they may adversely affect our ability to record, process, summarize and report financial information timely and accurately and, as a result, our consolidated interim or annual financial statements may contain material misstatements or omissions. Additionally, because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Risks Related to Our Organizational Structure

We are a holding company. Our sole material asset after completion of this offering will be our equity interests in WhiteHawk OpCo and OpCo GP, and we are accordingly dependent upon distributions from WhiteHawk OpCo and our operating subsidiaries to pay taxes and cover our corporate and other overhead expenses.

We are a holding company and will have no material assets other than our equity interests in WhiteHawk OpCo and OpCo GP. We have no independent means of generating revenue or cash flow, and our ability to pay our taxes and operating expenses or declare and pay dividends in the future, if any, will be dependent upon the financial results and cash flows of WhiteHawk OpCo and distributions we receive from WhiteHawk OpCo and our operating subsidiaries. WhiteHawk OpCo 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 WhiteHawk OpCo will be allocated to holders of OpCo Interests, including us. Accordingly, we will incur income taxes on our allocable share of any net taxable income of WhiteHawk OpCo. Under the terms of the OpCo Agreement, WhiteHawk OpCo will be obligated, subject to various limitations and restrictions, including with respect to our debt agreements, to make tax distributions to holders of OpCo Interests, including us. To the extent WhiteHawk OpCo has available cash, we intend to cause WhiteHawk OpCo (a) to generally make pro rata distributions to its unitholders, including us, in an amount at least sufficient to allow unitholders to pay taxes imposed on their allocable share of taxable income of WhiteHawk OpCo to the extent unitholders, including us, do not otherwise receive non-tax distributions from WhiteHawk OpCo in amounts at least sufficient to allow unitholders, including us, to pay such taxes 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 OpCo Agreement. We are limited, however, in our ability to cause WhiteHawk OpCo and our operating subsidiaries to make these and other distributions to us due to the restrictions under the agreements governing our indebtedness. To the extent that we need funds and WhiteHawk OpCo or our operating subsidiaries are restricted from making such distributions 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.

As mentioned above, under the OpCo Agreement, we intend to cause WhiteHawk OpCo, from time to time, to make distributions in cash to its unitholders (including us) in amounts at least sufficient to cover the taxes imposed on their allocable share of taxable income of WhiteHawk OpCo to the extent unitholders, including us, do not otherwise receive non-tax distributions from WhiteHawk OpCo in amounts at least sufficient to allow unitholders, including us, to pay such taxes. As a result of (i) potential differences in the amount of net taxable income allocable to us and to the Continuing Equity Owners, (ii) the lower tax rate under current law applicable to corporations as compared to individuals, and (iii) that tax distributions are required to be paid by WhiteHawk OpCo to its common unit holders pro rata in accordance with each common unitholder’s economic interests in WhiteHawk OpCo, these tax distributions may be in amounts that exceed our tax liabilities. Our board of directors will determine the appropriate uses for any excess cash so accumulated, which may include, among other uses, the payment of distributions to our stockholders and the payment of other expenses. However, we will have no obligation to distribute such cash (or other available cash) to our stockholders. In addition, no adjustments to the exchange ratio for common units and corresponding shares of Class A common stock will be made as a result of any cash distribution by us or any retention of cash by us. To the extent we do not distribute such excess cash as distributions on our Class A common stock we may take other actions with respect to such excess cash, for example, holding such excess cash, contributing such cash to WhiteHawk OpCo in exchange for additional common units (or contributing such cash to WhiteHawk OpCo and making corresponding adjustments to the Continuing Equity Owners common units), lending it (or a portion thereof) to WhiteHawk OpCo, or repurchasing outstanding shares of our Class A common stock, some of which may result in shares of our Class A common stock increasing in value relative to the value of common units. The holders of common units may benefit from any value attributable to such cash balances if they acquire shares of Class A common stock in exchange for their common units, notwithstanding that such holders may have participated previously as holders of common units in distributions that resulted in such excess cash balances to us.

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

We are subject to taxation by U.S. federal, state, and local tax authorities. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

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allocation of expenses to and among different jurisdictions;

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changes to our assessment about our ability to realize, or in the valuation of, our deferred tax assets that are based on estimates of our future results, the prudence and feasibility of possible tax planning strategies, and the economic and political environments in which we do business;

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

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tax effects of stock-based compensation;

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costs related to intercompany restructurings;

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changes in tax laws, regulations, or interpretations thereof;

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the outcome of current and future tax audits, examinations, or administrative appeals;

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lower than anticipated future earnings in jurisdictions where we have lower statutory tax rates and higher than anticipated future earnings in jurisdictions where we have higher statutory tax rates; and

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limitations or adverse findings regarding our ability to do business in some jurisdictions.

Any changes in U.S. taxation may increase our effective tax rate and harm our business, financial condition, and results of operations. In particular, new income or other tax laws or regulations could be enacted at any time, which could adversely affect our business operations and financial performance. Further, existing tax laws and regulations could be interpreted, modified, or applied adversely to us.

If we were deemed to be an investment company under the Investment Company Act of 1940, as amended (the “1940 Act”), including as a result of our ownership of WhiteHawk OpCo, applicable restrictions could make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business.

Under Sections 3(a)(1)(A) and (C) of the 1940 Act, a company generally will be deemed to be an “investment company” for purposes of the 1940 Act if (i) it is, or holds itself out as being, engaged primarily, or proposes to engage primarily, in the business of investing, reinvesting or trading in securities, or (ii) it engages, or proposes to engage, in the business of investing, reinvesting, owning, holding, or trading in securities and it owns or proposes to acquire investment securities having a value exceeding 40% of the value of its total assets (exclusive of U.S. government securities and cash items) on an unconsolidated basis. We do not believe that we are an “investment company,” as such term is defined in either of those sections of the 1940 Act.

We and WhiteHawk OpCo intend to conduct our operations so that we will not be deemed an investment company. As the sole managing member of WhiteHawk OpCo, we will control and operate WhiteHawk OpCo. On that basis, we believe that our interest in WhiteHawk OpCo is not an “investment security” as that term is used in the 1940 Act. However, if we were to cease participation in the management of WhiteHawk OpCo, or if WhiteHawk OpCo itself becomes an investment company, our interest in WhiteHawk OpCo could be deemed an “investment security” for purposes of the 1940 Act.

We and WhiteHawk OpCo intend to conduct our operations so that we will not be deemed an investment company. If it were established that we were an unregistered investment company, there would be a risk that we would be subject to monetary penalties and injunctive relief in an action brought by the U.S. Securities and Exchange Commission (the “SEC”), that we would be unable to enforce contracts with third parties and that third parties could seek to obtain rescission of transactions undertaken during the period it was established that we were an unregistered investment company. If we were required to register as an investment company, restrictions

imposed by the 1940 Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business.

Risks Related to Our Industry

Our industry is highly competitive, and competitive pressures could negatively affect our business.

Competition in the natural gas, NGL and oil industry is intense, which may adversely affect our and our third-party operators’ ability to succeed. Many of these companies explore for and produce natural gas, NGLs and crude oil, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. Competition for acquisitions of mineral and royalty interests may increase the cost of, or cause us to refrain from, completing acquisitions. In addition, some of our competitors have significant financial, technical and marketing resources and may also have lower overhead cost structures, and therefore may be able operate at lower costs than us. Our third-party operators’ larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our third-party operators can, which would adversely affect our third-party operators’ competitive position. Our third-party operators may have fewer financial and human resources than many companies in our third-party operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Furthermore, the natural gas and oil industry has experienced recent consolidation amongst some operators, which has resulted in certain instances of combined companies with larger resources. Such combined companies may compete against our third-party operators or, in the case of consolidation amongst our third-party operators, may choose to focus their operations on areas outside of our properties.

Furthermore, a substantial portion of our revenues is directly or indirectly dependent upon our ability to acquire additional properties which is dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. As a result of the factors described above, the competitive environment we operate in could have a material adverse effect on our business, financial condition and results of operations.

Failure of exported liquid natural gas to be a competitive source of energy for the United States or international markets could adversely affect our third-party operators and could have a material adverse effect on our business, financial condition and results of operations.

Operations of LNG projects are dependent upon the ability of our third-party operators to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets. Additionally, insufficient receiving capacity, LNG tanker capacity or political instability in foreign countries that import natural gas may also impede the willingness or ability of LNG purchasers and merchants in such countries to export LNG from the United States. In the United States, due mainly to a historically abundant supply of natural gas and discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source making LNG a competitive source of energy within the United States. However, in addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. Some of these sources of energy may be available at a lower cost than LNG in certain markets including in the United States.

As a result of these and other factors, LNG may not be a competitive source of energy in the United States or internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our third-party operators could adversely affect the ability of

our third-party operators to deliver LNG from the United States or to the United States on a commercial basis. Any significant impediment to the ability to deliver LNG to or from the United States generally could have a material adverse effect on our third-party operators, or the purchasers of their production, and on our business, financial condition and results of operations.

Our growth strategy is partly dependent upon the continued expansion of electricity demand driven by AI data center development. Expectations regarding increased demand for natural gas related to data centers and AI may not materialize, and our business prospects could be harmed if demand for natural gas does not develop as expected or takes longer to develop than we anticipate.

Our growth and success are partly dependent on continued expansion of electricity demand driven by the rapid increase in AI data center development, which has contributed to record power consumption and is expected to continue to drive increased demand for electricity. However, there is no assurance that these forecasts of load growth will be accurate or that the anticipated load growth will occur as projected. Factors such as evolving technology, improvements in energy efficiency, changes in economic conditions, shifts in government policy, regulation or consumer sentiment related to AI usage and development, or project delays or cancellations by data center developers could reduce or slow demand for electricity relative to current expectations. Further, there is no assurance that natural gas will be used to meet such demand. If the anticipated load growth and related increase in demand for natural gas fails to materialize in areas in which we maintain mineral and royalty interests, it could have a material adverse effect on our business, financial condition and results of operations.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for our third-party operators related to developing and operating our properties.

The natural gas, NGL and crude oil industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, our third-party operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our third-party operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. In addition, they may not have long-term contracts securing the use of their rigs. Shortages of drilling rigs, equipment, raw materials, supplies, personnel, trucking services, tubulars, hydraulic fracturing and completion services and production equipment could delay or restrict our third-party operators’ exploration and development operations, which in turn could have a material adverse effect on our business, financial condition and results of operations.

The marketability of natural gas, NGLs and crude oil is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our third-party operators control. Any limitation in the availability of those facilities or our third-party operators’ inability to obtain access to such facilities on commercially reasonable terms or otherwise could interfere with our third-party operators’ ability to store, process, transmit and market our third-party operators’ production as well as their plans to develop and sell our reserves, and could harm our business.

The marketability of our third-party operators’ production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods, and processing and refining facilities developed and owned by third parties. Our third-party operators rely, and expect to rely in the future, on these third-party facilities in order to store, process, transmit and sell their production. Neither we nor the majority of our third-party operators control these third-party transportation facilities and our third-party operators’ access to them may be limited or denied. The inability or unwillingness of third parties to provide sufficient facilities and services to our third-party operators on commercially reasonable terms or otherwise could have a material and adverse effect on our third-party operators’ plans to develop and sell our reserves. Additionally, insufficient production from the wells

on our acreage or a significant disruption in the availability of third-party transportation facilities or other production facilities could adversely impact our third-party operators’ ability to deliver, to market or produce natural gas, NGLs and crude oil and thereby cause a significant interruption in our third-party operators’ operations. If these facilities are unavailable to our third-party operators on commercially reasonable terms or otherwise, our third-party operators could be forced to shut in some production or delay or discontinue drilling plans and commercial production on our properties following a discovery of hydrocarbons. If these facilities are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production-related difficulties, they may also be required to shut in or curtail production. In addition, the amount of natural gas, NGLs and oil that can be produced and sold is subject to curtailment in certain other circumstances outside of our or our third-party operators’ control, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, downstream processing facilities’ failure to accept unprocessed natural gas, tanker truck availability and extreme weather conditions. Also, production from our wells may be insufficient to support the construction of pipeline facilities, and the shipment of our third-party operators’ natural gas, NGLs and crude oil on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last for an extended period of time. In many cases, we and our third-party operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity, or an inability to obtain favorable terms for delivery of the natural gas, NGLs and crude oil produced from our acreage, could reduce our third-party operators’ ability to market the production from our properties and have a material adverse effect on our financial condition, results of operations and cash flows. Our third-party operators’ access to transportation options and the prices our third-party operators receive can also be affected by U.S. federal and state regulation—including regulation of natural gas, NGL and crude oil production, transportation and pipeline safety—as well by general economic conditions and changes in supply and demand. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. Federal and state regulations also govern the price and terms for access to natural gas pipeline transportation. In addition, the third parties on whom our third-party operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

Finally, a decrease in access to midstream and operational infrastructure and bottlenecks in processing and transportation could result in a decline in the price of natural gas, NGLs and crude oil, which could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to Legal, Regulatory and Environmental Matters

The current and future operations of our business and that of the third-party operators on our land are and will be governed by complex and stringent federal, state, local, and other laws and regulations, including but not limited to:

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laws and regulations governing mineral acquisition, development, production, transportation, marketing and sales;

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laws and regulations related to exports, taxes and fees;

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labor standards and regulations related to occupational health and safety; and

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environmental, health or safety standards and regulations related to waste disposal, pollution clean-up, toxic substances, land use, and protection of the environment and natural resources.

Federal, state and local agencies may assert overlapping authority to regulate in these areas. Under these laws and regulations, we (either directly or indirectly through our third-party operators) could be liable for personal injuries, property and natural resource damages and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our business and subject us to administrative, civil and criminal penalties. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

Companies engaged in exploration activities often experience increased costs and delays in production and other schedules as a result of the need to comply with applicable laws, regulations and permits. Costs of compliance may increase, and operational delays or restrictions may occur, as existing laws and regulations are revised or reinterpreted, or as new laws and regulations become applicable to our business and our third-party operators. Government authorities and other organizations continue to study health, safety and environmental aspects of mineral operations, including those related to air, soil and water quality, ground movement or seismicity, and natural resources. Government authorities have also adopted or proposed new or more stringent requirements for permitting well construction, and public disclosure or environmental review of, or restrictions on, mineral operations. Such requirements or associated litigation could result in potentially significant added costs to comply, delay or curtail the exploration, development, disposal or production activities of our third-party operators, which could have a material adverse effect on our business, financial condition and results of operations.

To operate in compliance with these laws and regulations, our third-party operators must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities. These permits are generally subject to protest, appeal or litigation, which could in certain cases delay or halt projects, production of wells and other operations. Failure to comply with laws and regulations, including obtaining and maintaining permits, approvals and certificates, may result in enforcement actions, including the forfeiture of claims, or orders issued by regulatory or judicial authorities requiring operations to cease or be curtailed, the assessment of administrative, civil, and criminal fines and penalties and liability for noncompliance, costs of corrective action, cleanup or restoration, including capital expenditures, installation of additional equipment, or remedial actions, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or limiting their operations.

Our business may also be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Certain of our properties may overlap with the habitat for species listed under the ESA or analogous state laws, and restrictions designed to protect threatened or endangered species or their habitat may limit the abilities of our third-party operators to operate in certain areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. Permanent restrictions could prohibit drilling or emplacement of pipelines in certain areas or require the implementation of expensive mitigation measures. These restrictions could have a material adverse effect on our business, financial condition and results of operations to the extent they impact our properties, our third-party operators or our mineral and royalty interests.

The development and enactment of climate change legislation and regulation regarding emissions of greenhouse gases (“GHGs”) could adversely affect the mineral industry and reduce demand for the natural gas and oil that our third-party operators produce.

The energy industry is affected from time to time in varying degrees by political developments and a wide range of federal, tribal, state and local statutes, rules, orders and regulations that may, in turn, affect the operations and costs of the companies engaged in the energy industry. While Congress has from time to time considered legislation to reduce emissions of GHGs, comprehensive legislation aimed at reducing GHG emissions has not

yet been adopted at the federal level. Notwithstanding the U.S. Environmental Protection Agency’s (“EPA”) recent final rule repealing the “Endangerment Finding” that underlies the majority of its GHG-related regulations, GHG emissions have been regulated by the EPA under previous administrations pursuant to the Clean Air Act of 1970 (as amended, the “CAA”), as well as by state environmental authorities. For example, in December 2023, the EPA finalized stringent emissions control requirements for certain new and existing upstream and midstream natural gas and oil facilities, known as Subparts OOOOb and OOOOc, and failure to comply with these new rules may result in substantial fines and penalties, as well as injunctive relief. However, in March 2025, the EPA announced plans to reconsider Subparts OOOOb and OOOOc and, in November 2025, the EPA finalized an interim final rule extending certain compliance deadlines for certain provisions provided in the rules. Litigation challenging the interim final rule remains pending. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which may include operations on our properties. In September 2025, the EPA proposed to delay the reporting of GHG emissions for the oil and gas sector until 2034. These proposals are still under consideration and are subject to a number of uncertainties and likely could face legal challenges that would further delay the implementation of any rules, and we cannot predict the ultimate outcome. Litigation challenging the rule rescinding the “Endangerment Finding” is ongoing, and as a result, there is significant uncertainty with respect to regulation of GHG emissions. To the extent new laws or regulations are adopted or issued to address GHG emissions, they could increase compliance costs for our third-party operators or restrict the ability to permit GHG emissions from new or modified sources, which in turn could result in a material adverse impact on our business. In addition, substantial limitations on GHG emissions could adversely affect demand for natural gas, NGLs and oil, which may also adversely affect our business and financial results. Further, the Infrastructure Investment and Jobs Act and the Inflation Reduction Act of 2022 (the “IRA”) include billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure, and carbon capture and sequestration. Additionally, the IRA includes a Waste Emissions Charge for methane emissions from specific types of facilities that emit 25,000 metric tons of carbon dioxide equivalent or more per year, and, although the IRA generally provides for a conditional exemption under certain circumstances, the charge applies to emissions that exceed an established emissions threshold for each type of covered facility. In November 2024, the EPA finalized the Waste Emissions Charge rule. However, in February 2025, Congress repealed the Waste Emissions Charge rule using the Congressional Review Act. In addition, the One Big Beautiful Bill Act, enacted in July 2025, delayed implementation of the charge until 2034. While the EPA cannot reissue its rule implementing the Waste Emissions Charge (either in substantially the same form or in a new rule), the underlying requirement in the IRA remains unchanged. We cannot predict if the Trump administration and/or Congress may take action to repeal or revise this requirement in the IRA. However, compliance with this and other air pollution control and permitting requirements has the potential to delay the development of natural gas and oil projects and increase our third-party operators’ costs of development, with possible significant costs, and adversely affect our business.

Additional GHG regulation could also result from the agreement crafted during the United Nations climate change conference in Paris, France, in December 2015 (the “Paris Agreement”). Under the Paris Agreement, the United States committed to reducing its GHG emissions by 26-28% by the year 2025 as compared with 2005 levels. Moreover, in November 2021, at the U.N. Framework Convention on Climate Change Conference of the Parties (the “Conference of the Parties”), the United States and the European Union advanced a Global Methane Pledge to reduce global methane emissions at least 30% from 2020 levels by 2030, which over 100 countries have signed. At the 27th Conference of the Parties, the United States agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane intensity natural gas. A decision from the 28^th Conference of the Parties serving as a meeting of the Parties to the Paris Agreement calls on countries to contribute to a list of global efforts, taking into account the Paris Agreement and their different national circumstances, pathways and approaches. This list includes a tripling of renewable energy capacity and doubling the global average rate of energy efficiency improvements by 2030; phasing out inefficient fossil fuel subsidies that do not address energy poverty or just transitions, as soon as possible; and transitioning away from fossil fuels in energy systems, in a just, orderly and equitable manner, accelerating action in the 2020s, so as to achieve net zero by 2050 in keeping

with the science. However, in January 2025, President Trump announced the United States’ withdrawal from the Paris Agreement, and in January 2026, President Trump announced the United States’ withdrawal from the United Nations Framework Convention on Climate Change. In addition, the Supreme Court’s decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc., thus ending 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. The full impact of these actions remains uncertain at this time but many of these initiatives to address climate change at the international, state and local levels are expected to continue. Consequently, legislation and regulatory programs to address climate change or reduce emissions of GHGs could have a material adverse effect on our business, financial condition and results of operations. In the absence of comprehensive federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap-and-trade programs, and we cannot predict what or whether states may take further action to regulate GHG emissions following the EPA’s rescission of the “Endangerment Finding.”. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact us and our third-party operators, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, such operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations, which could adversely impact our business. In addition, substantial limitations on GHG emissions could adversely affect demand for the natural gas and oil produced from our properties. Restrictions on emissions of methane or carbon dioxide, such as restrictions on venting and flaring of natural gas, that may be imposed in various states, as well as state and local climate change initiatives, such as increased energy efficiency standards or mandates for renewable energy sources, could adversely affect the oil and gas industry. It is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact oil and gas assets. Increasingly, natural gas and oil companies are exposed to litigation risks resulting from climate change. A number of parties have brought suits against natural gas and oil companies in state or federal court, including suits for alleged contributions to, or failure to disclose the impacts of, climate change. While we are not currently party to any such litigation, we or our third-party operators could be named in future actions making similar claims of liability. Moreover, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage. Involvement in any such litigation could have a material adverse impact on our business, financial condition and results of operations.

Finally, climate change may have significant physical effects, such as increased frequency and severity of extreme weather events (including storms, freezes, floods, drought, hurricanes and other climatic events) or changes in meteorological and hydrological patterns, that could adversely impact our third-party operators. Such effects may result from damage to our third-party operators’ facilities, including through restrictions on the use of water due to drought and indirect impacts from supply chain disruption and market volatility. These effects may adversely affect our business, financial condition and results of operations.

Increased attention to sustainability-related matters and conservation measures may impact our business or the business of our third-party operators.

Increased attention to climate change, and sometimes conflicting societal expectations on companies to address climate change and consumer demand for alternative forms of energy, may result in increased costs, reduced demand for natural gas, NGLs and oil, reduced profits, increasing administrative, legislative and judicial scrutiny, reputational damage and negative impacts on us or our third-party operators, which may ultimately have adverse impacts on our business, such as our access to capital markets as well as the price of our Class A common stock. Increased attention to climate change and environmental conservation, for example, may result in demand shifts for natural gas and oil products and governmental investigations, private litigation or activist campaigns against us or our third-party operators.

While we may elect to pursue certain sustainable energy-related strategies in the future, any such goals are aspirational and may not have the intended impact on our business. We may also receive pressure from investors, lenders or other groups to adopt more aggressive climate or other sustainability-related goals, and we cannot guarantee that we will be able to pursue or implement such goals because of potential costs or technical or operational obstacles. Moreover, failure or a perception (whether or not valid) of failure to pursue or implement such strategies or achieve such goals or commitments, including any GHG emission reduction or carbon intensity goals or commitments, could result in private litigation and damage our reputation, cause investors or consumers to lose confidence in us, and negatively impact our third-party operators. Additionally, to the extent sustainability-related matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our business.

Some organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to sustainability concerns. Such ratings are used by some investors to inform their investment and voting decisions. While such ratings do not impact all investors’ decisions, unfavorable ratings and any recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us, our third-party operators and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Additionally, certain public statements with respect to sustainability matters, such as emissions reduction claims, are becoming increasingly subject to heightened scrutiny from public and governmental authorities, as well as other parties, related to the risk of potential “greenwashing”—i.e., misleading information or false claims overstating potential benefits. Any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments.

Our third-party operators’ exploration and development activities are subject to hazardous operating risks, which could expose our third-party operators to significant liability, delay, suspension or termination of their operations.

Our third-party operators are subject to all of the hazards and operating risks associated with drilling for and production of natural gas, NGLs and crude oil, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, NGLs and crude oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as crude oil and NGL spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to our third-party operators due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations, which in turn could have a material adverse effect on our business, financial condition and results of operations.

The exploration and possible future development phases of the business of the third-party operators we work with are and will be subject to federal, state and local environmental, health and safety regulations. These regulations mandate, among other things, the maintenance of air and water quality standards and land reclamation. They also set out limitations on the generation, transportation, storage and disposal of solid and hazardous waste, impose restrictions on activities to protect certain species and regulate worker health and safety. Future environmental legislation may require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments and a heightened degree of responsibility for companies and their officers, directors and employees. Future changes in environmental regulations, if any, may adversely affect our third-party operators, and, as a result, our business. If our third-party operators fail to comply with any applicable environmental laws, regulations or permit requirements, they could face regulatory or judicial sanctions. Penalties imposed by either the courts or administrative bodies could delay or stop their operations to develop our minerals or require considerable capital expenditures. Furthermore, certain groups

opposed to exploration and mining may attempt to interfere with their operations through the legal or regulatory process or by engaging in disruptive protest activities. The occurrence of any of these risks to our third-party operators could in turn have a material adverse effect on our business, financial condition and results of operations.

Environmental hazards unknown to us, which have been caused by previous or existing owners or operators of our properties, may exist on our properties. Our properties could be located on or near the site of a federal cleanup project, and that environmental cleanup or other environmental restoration procedures could remain pending or mandated by law, which may result in unexpected liabilities, with total costs that are difficult to predict.

The Comprehensive Environmental, Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on current and former owners and operators of sites and on persons who disposed of or arranged for the disposal of hazardous substances found at such sites. It is not uncommon for the government to file claims requiring cleanup actions, demands for reimbursement for government-incurred cleanup costs, or natural resource damages, or for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of solid waste and hazardous waste and authorize the imposition of substantial fines and penalties for noncompliance, as well as requirements for corrective actions and financial assurance. CERCLA, RCRA and comparable state statutes can impose liability for clean-up of sites and disposal of substances found on exploration and processing sites long after activities on such sites have been completed.

The CAA restricts the emission of air pollutants from many sources, including drilling and production activities. The drilling and production operations conducted by third parties to develop our minerals may produce air emissions, including fugitive dust and other air pollutants from stationary equipment, storage facilities and the use of mobile sources such as trucks and heavy construction equipment, which are subject to review, monitoring and/or control requirements under the CAA and state air quality laws. In undeveloped properties, our third-party operators may be required to obtain permits before work can begin, and, in properties with existing facilities, our third-party operators may need to incur capital costs in order to remain in compliance. In addition, permitting rules may impose limitations on operators’ production levels or result in additional capital expenditures in order to comply with the rules.

The National Environmental Policy Act requires federal agencies to integrate environmental considerations into their decision-making processes by evaluating the environmental impacts of their proposed actions and assessing alternatives to those actions. If a proposed federal action could significantly affect the environment, the agency must prepare a detailed statement known as an Environmental Impact Statement (“EIS”). The EPA, other federal agencies and any interested third parties will review and comment on the scoping of the EIS and the adequacy of and findings set forth in the draft and final EIS. This process can cause delays in the issuance of required permits, litigation over the adequacy of the EIS or result in changes to a project to mitigate its potential environmental impacts, which can in turn adversely impact the economic feasibility of a proposed project.

The Clean Water Act (the “CWA”) and comparable state statutes impose restrictions and controls on the discharge of pollutants into waters of the United States. 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. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit the discharge of dredged and fill material in certain wetlands and other regulated waters unless authorized by an appropriately issued permit. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for the unauthorized discharge of pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the discharge and for natural resource damages resulting from the discharge.

The Safe Drinking Water Act (the “SDWA”) and the Underground Injection Control (the “UIC”) program promulgated thereunder regulate the drilling and operation of subsurface injection wells. The EPA directly administers the UIC program in some states; in other states, including those in which we own property, the responsibility for the program has been delegated to the state. The UIC program requires that a permit be obtained before drilling a disposal or injection well. Violation of these regulations and/or contamination of groundwater may result in fines, penalties and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third-party claims may be filed by neighboring landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

There can be no assurance that the defense of such claims by us or our third-party operators will be successful and a successful claim against us or any of the third parties we contract with could have an adverse effect on our business, financial condition and results of operations.

Future legislative or regulatory changes may result in increased costs and decreased revenues, cash flows and liquidity, all of which could have a material adverse effect on our business, financial condition and results of operations.

Companies that operate wells in which we own mineral and royalty interests are subject to extensive federal, state and local regulation. We, as a minerals and royalties interest owner, are therefore indirectly subject to these same regulations. In particular, changes in law or regulation related to hydraulic fracturing or GHGs could significantly increase capital, compliance and operating costs, as well as halt or delay the further development of gas and oil reserves on our properties.

Federal Income Taxation

We are subject to U.S. federal income tax, as well as income or capital-based taxes in various states, and our operating cash flows are sensitive to the amount of income taxes we must pay. Income taxes are assessed on our net income as determined for federal income tax purposes, considering allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of items that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flows.

Further revisions to U.S. tax law, such as any increase in corporate income tax rates, the repeal of the percentage depletion allowance, or the repeal of expensing for intangible drilling costs, could have a material adverse effect on our business. Moreover, the U.S. Department of Treasury has broad authority to issue regulations and interpretative guidance that may significantly impact how we apply U.S. tax law, with a corresponding impact on the results of our operations for the periods affected.

Hydraulic Fracturing and Water Disposal

The vast majority of natural gas and oil wells drilled in recent years have been, and future wells are expected to be, hydraulically fractured as a part of the process of completing the wells and putting them on production, including the wells drilled in which we own an interest. Hydraulic fracturing is a process that involves pumping water, sand and additives at high pressure into rock formations to stimulate natural gas and oil production. In developing plays where hydraulic fracturing, which requires large volumes of water, is necessary for successful development, the demand for water may exceed the supply. Over the past several years, parts of the country have experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Such conditions may be exacerbated by climate change. If our third-party operators are unable to obtain water to use in their operations from local sources, or if our third-party operators are unable to effectively utilize flowback water, they may be unable to economically drill for or produce natural gas, NGLs and crude oil from our properties, which could have a material adverse effect on our business, financial condition and results of operations.

In addition to water, hydraulic fracturing fluid contains chemical additives designed to optimize production. Well operators are required in certain states to disclose the components of these additives. Additional states and the federal government may follow with similar requirements or may restrict the use of certain additives. This could result in more costly or less effective development of wells.

The fluid produced from the fractured formation must be either treated for reuse or disposed of by injecting the fluid into disposal wells. Injection well disposal processes have been, and continue to be, studied to determine the extent of correlation between injection well disposal and the occurrence of earthquakes. Certain studies have concluded there is a correlation, and this has resulted in the cessation of or the reduction of injection rates in certain water disposal wells, especially in northern Oklahoma.

Efforts to regulate hydraulic fracturing and fluid disposal continue at the local, state and federal level. For example, the EPA has asserted regulatory authority pursuant to the SDWA UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. New regulations are being considered, including limiting water withdrawals and usage, limiting water disposition, restricting which additives may be used, implementing statewide hydraulic fracturing moratoriums and temporary or permanent bans in certain environmentally sensitive areas. Public sentiment against hydraulic fracturing and fluid disposal and shale production could result in more stringent permitting and compliance requirements. Consequences of any of these regulation efforts could increase capital, compliance and operating costs significantly, as well as delay or halt the further development of gas and oil reserves on our properties.

Any of the above factors could have a material adverse effect on our business, financial condition and results of operations.

Inflation Reduction Act of 2022

The IRA appropriates significant federal funding for renewable energy initiatives. These incentives could accelerate the transition of the U.S. economy towards lower- or zero-carbon emissions alternatives, which could decrease demand for oil and gas. Moreover, the IRA imposes a federal fee on GHG emissions through a Waste Emissions Charge. The IRA amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. However, the One Big Beautiful Bill Act, enacted in July 2025, delays implementation of the charge until 2034. While the EPA cannot reissue its rule implementing the Waste Emissions Charge (either in substantially the same form or in a new rule), the underlying requirement in the IRA remains unchanged. Although we cannot predict if the Trump administration and/or Congress may take action to repeal or revise this requirement of the IRA, compliance with this and other air pollution control and permitting requirements has the potential to delay the development of natural gas projects and increase our third-party operators’ costs of development, which costs could be significant, and in turn have a material adverse effect on our business, financial condition and results of operations.

On January 20, 2025, President Trump issued the “Unleashing American Energy” executive order (EO 14154), which directs federal agencies to suspend the disbursement of funds under the IRA, reassess existing energy policies, and streamline permitting processes for oil and gas development. If fully implemented, EO 14154 is expected to reduce compliance costs, expand development opportunities, and provide more investment certainty. However, while the executive order signals a shift in energy policy, certain provisions of the IRA were enacted through legislation that may require congressional action or judicial review before being fully repealed or modified, and agency actions taken pursuant to EO 14154 have been subject to litigation. We will continue to monitor regulatory developments, potential legal challenges, and legislative actions that may affect the implementation of EO 14154. While the administration’s energy policies appear broadly supportive of the oil and gas industry, ongoing legal and political dynamics may impact the extent to which specific provisions are ultimately enforced or rescinded.

Seismic Activity

In response to concerns related to earthquakes in northern and central Oklahoma and Texas near underground disposal wells used for the injection of flowback and produced water (known as “induced seismicity”), regulators in some states, including Oklahoma and Texas, have imposed, or are considering imposing, certain limits on or requirements related to the permitting or operation of produced water disposal wells in areas with increased instances of induced seismic events. States may, from time to time, develop and implement plans directing certain wells in proximity to where seismic incidents have occurred to restrict or suspend well operations. These legislative and regulatory initiatives may result in additional levels of regulation that could lead to operational delays, litigation concerning, and greater opposition to, natural gas and oil activities using injection wells for waste disposal, and increased operating and compliance costs or otherwise adversely affect operations. Increased restrictions may also have a material adverse effect on our third-party operators and operations on our properties, which could have an indirect adverse effect on our business, financial condition and result of operations.

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on us and our ability to hedge risks associated with our business.

The Dodd-Frank Act required, in part, that the U.S. Commodity Futures Trading Commission (“CFTC”) and the SEC promulgate rules and regulations to establish federal oversight for the over-the-counter (“OTC”) derivatives markets and entities that participate in those markets. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

Effective March 15, 2021, the CFTC implemented its final rule concerning speculative position limits, adopting new and amended federal spot-month limits for 2025 physical commodity derivatives. Under this rule, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions.

The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. With the implementation of the final aggregation rules and upon the adoption and effectiveness of final CFTC position limits rules, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016. This final rule was amended on February 24, 2021 to permit the application of a minimum transfer amount of up to $50,000 for each separately managed account of a legal entity that is a counterparty to a swap dealer or a major swap participant in an uncleared swap transaction and to permit the application of separate minimum transfer amounts for initial margin and variation margin.

In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business.

The Volcker Rule provisions of Dodd-Frank may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.

As a result, Dodd-Frank and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of natural gas, NGL and oil prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to natural gas, NGLs and oil. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, financial condition and results of operations.

Restrictions on the ability of our third-party operators to obtain water may have a material adverse effect on our business, financial condition and results of operations.

Water is an essential component of natural gas, NGL and crude oil production during both the drilling and hydraulic fracturing processes. Over the past several years, parts of the country have experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Such conditions may be exacerbated by climate change. If our third-party operators are unable to obtain water to use in their operations from local sources or at commercially reasonable rates, or if our third-party operators are unable to effectively utilize flowback water, they may be unable to economically drill for or produce natural gas, NGLs and crude oil from our properties, which could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to Our Indebtedness

Our use of borrowings to finance our business exposes us to risks.

We use indebtedness as a means to finance our business strategies, which exposes us to the typical risks associated with using leverage. Upon the closing of this offering, we expect our material indebtedness to consist of (i) our Note Purchase Agreement, which we anticipate assigning to WhiteHawk OpCo, paying down to approximately $75.0 million of principal, and amending to become a second lien obligation, and (ii) our new Revolving Credit Facility, providing for an initial aggregate maximum credit amount of $500 million, an initial aggregate elected commitment amount of $150 million and an initial borrowing base of $150 million. See “Description of Material Indebtedness” for further information regarding our outstanding indebtedness. We may continue to strategically utilize long-term indebtedness in connection with the acquisition of additional assets. There can be no assurance that we will have sufficient cash on hand with which to repay any outstanding borrowings. There can also be no assurance that leveraged financing will continue to be available to us on favorable terms or at all. Our stockholders may bear the burden of any increase in our expenses as a result of our use of leverage, including interest expenses. To the extent that we use leverage to finance our assets, our financing costs will reduce cash available for dividends to our stockholders.

Our failure to comply with the covenants contained in the Note Purchase Agreement and the Revolving Credit Facility, including as a result of events beyond our control, could result in an event of default that could cause repayment of our Senior Notes and borrowings under the Revolving Credit Facility to be accelerated.

The Note Purchase Agreement (as defined herein) governing our Senior Notes and the Revolving Credit Facility impose, and the agreements governing our future indebtedness may impose, material restrictions on us that limit our operating flexibility, which could harm our long-term interests. These restrictions, subject in certain cases to ordinary course of business and other exceptions, may limit our ability to engage in some transactions, including the following:

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incurring or guaranteeing additional indebtedness;

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paying dividends, redeeming capital stock or making other restricted payments;

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making payments in respect of certain second lien/senior notes or junior debt;

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making investments, including acquisitions, loans and advances;

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entering into burdensome agreements with negative pledge clauses or restrictions on subsidiary distributions;

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selling, transferring or otherwise disposing of assets, properties or licenses;

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creating liens on assets and capital stock to secure any indebtedness

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undergoing a change in control;

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merging, consolidating, liquidating, or dissolving;

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entering into new lines of business or materially altering our business and the business conducted by certain of our subsidiaries; and

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entering into transactions with affiliates.

In addition to imposing restrictions on our business and operations, the Note Purchase Agreement includes covenants relating to financial ratios and tests, and the Revolving Credit Facility will require us to maintain, as of the last day of each fiscal quarter (commencing with the first full fiscal quarter ending after the closing of this offering), a consolidated net leverage ratio of no greater than 3.50 to 1.00 and a current ratio of no less than 1.00 to 1.00. Any future debt instruments may also include such covenants. The Note Purchase Agreement also requires us to prepay our Senior Notes on a quarterly basis, an amount equal to the lesser of: (A) the difference between the aggregate outstanding principal amount of our Senior Notes and the Target Debt Balance (as defined in the Note Purchase Agreement) as of the date thereof, and (B) any liquidity (calculated on a Distribution PF Basis (as defined in the Note Purchase Agreement)) in excess of the Minimum Liquidity Amount (as defined in the Note Purchase Agreement).

Any failure to comply with the restrictions of our indebtedness, and any subsequent financing agreements, including as a result of events beyond our control, may result in an event of default under these agreements, which in turn may result in defaults or acceleration of obligations under these agreements and other agreements, giving our lenders and other debt holders the right to terminate any commitments they may have made to provide us with further funds and to require us to repay all amounts then outstanding. Our assets and cash flows may not be sufficient to fully repay borrowings under our outstanding debt instruments. In addition, we may not be able to refinance or restructure the payments on the applicable debt. Even if we were able to secure additional financing, it may not be available on favorable terms.

Our Revolving Credit Facility and our hedging agreements are secured by substantially all of our assets and is subject to an intercreditor agreement, and our Note Purchase Agreement will be a second lien obligation, which could limit our financial and operating flexibility and expose holders of our Senior Notes to increased risk in the event of an enforcement action.

The Revolving Credit Facility and our obligations under our hedging agreements will be secured by liens on substantially all of WhiteHawk OpCo’s properties and assets, the properties and assets of its subsidiaries, and pledges of the equity interests in all of WhiteHawk OpCo’s present and future subsidiaries (subject to certain exceptions), and will be guaranteed by substantially all of WhiteHawk OpCo’s existing and future direct and indirect subsidiaries, with certain customary or agreed upon exceptions. Upon the closing of this offering, the Note Purchase Agreement is expected to be amended to become a second lien obligation on substantially the same collateral, subject to an intercreditor agreement governing the relative rights and priorities of the first lien secured parties under the Revolving Credit Facility and the second lien secured parties under the Note Purchase Agreement. If we are unable to repay our secured obligations when due, the first lien lenders could foreclose on or otherwise exercise remedies with respect to the collateral prior to the second lien secured parties, and the value of the collateral may not be sufficient to repay all amounts owing under the Revolving Credit Facility and the Note Purchase Agreement. The intercreditor agreement may also restrict the ability of the holders of our Senior Notes to exercise remedies, challenge the first lien liens, or otherwise protect their interests during periods of default or insolvency.

The borrowing base under our Revolving Credit Facility is subject to periodic redetermination and other automatic reductions, which could require us to repay outstanding borrowings on short notice.

The borrowing base under the Revolving Credit Facility is subject to semi-annual redeterminations on April 15 and October 15 of each year, commencing October 15, 2026, based on a review of our proved oil and gas reserves, commodity prices and other factors deemed relevant by the administrative agent. In addition, each of WhiteHawk OpCo and the administrative agent (at the direction of the required lenders) may elect to initiate one interim redetermination between scheduled redeterminations, and we may elect an additional interim redetermination in connection with acquisitions of oil and gas properties representing at least 5% of the then-effective borrowing base. The borrowing base will also be automatically reduced (i) by the borrowing base value of any oil and gas properties disposed of or swap agreements terminated if the aggregate value of such dispositions and terminations since the most recent redetermination exceeds 5% of the then-effective borrowing base and (ii) upon the issuance of any permitted senior notes, by 25% of the aggregate stated principal amount of such notes. A decrease in commodity prices, downward revisions to our reserve estimates, asset dispositions, swap terminations, senior note issuances or changes in the lenders’ lending policies could result in a reduction of our borrowing base. If our outstanding borrowings exceed the redetermined borrowing base, we could be required to repay such excess, which we may be unable to do on a timely basis or at all, and any such mandatory repayment could materially and adversely affect our liquidity, financial condition and results of operations.

The Revolving Credit Facility will require us to maintain specified commodity hedges, which may limit our ability to benefit from favorable commodity prices and expose us to counterparty and other hedging risks.

The Revolving Credit Facility will require us, on the last day of each fiscal quarter, to maintain swap agreements hedging a minimum percentage of our reasonably projected production of crude oil and natural gas from proved developed producing reserves, with required percentages and tenors that vary based on our Consolidated Net Leverage Ratio. If our Consolidated Net Leverage Ratio is at least 1.50 to 1.00, we must hedge at least 50% of reasonably projected production for each of the 24 months following such date; if the ratio is at least 1.00 to 1.00 but less than 1.50 to 1.00, we must hedge at least 50% for 12 months and at least 25% for months 13 through 24; and if the ratio is less than 1.00 to 1.00, we must hedge at least 50% for 12 months; provided that if our natural gas production exceeds 90% of our aggregate production, determined on a barrel of oil equivalent basis, we will not be required to hedge our volumes of crude oil. These required hedging levels may prevent us from realizing the full benefit of increases in commodity prices, may require us to enter into or maintain hedges at unfavorable

times or prices, and expose us to counterparty credit risk and mark-to-market volatility. A failure to maintain required hedges would result in an event of default under the Revolving Credit Facility.

The Revolving Credit Facility and the Note Purchase Agreement restrict our ability to pay cash dividends and make other distributions to our stockholders.

The Revolving Credit Facility will permit us to make cash restricted payments to holders of our equity interests only if, both before and immediately after giving effect to any such restricted payment, (i) no default, event of default or borrowing base deficiency exists, (ii) unused availability is at least 10% of the loan limit, (iii) our Consolidated Net Leverage Ratio is less than or equal to 3.00 to 1.00 on a pro forma basis and (iv) such dividends and distributions are permitted by the Note Purchase Agreement, as in effect immediately following the amendment to the Note Purchase Agreement. See “Description of Material Indebtedness.” As a result, our ability to pay cash dividends on, or repurchase, our common stock will depend on our continued compliance with these conditions as well as the other covenants in our debt agreements. If we are unable to satisfy these conditions, we may be unable to pay cash dividends at the levels anticipated at the time of this offering, or at all, which could adversely affect the market price of our common stock.

Despite current indebtedness levels, we may incur substantial additional indebtedness in the future. This could further increase the risks associated with our indebtedness.

We may incur substantial additional indebtedness in the future, which would increase our debt service obligations and could further reduce cash available to invest in additional assets. The terms of our Notes do not fully prohibit us or our subsidiaries from incurring additional indebtedness, subject to limitations. As of December 31, 2025, we had $237.7 million of borrowings outstanding under our Senior Notes. Upon the closing of this offering, we will have borrowing capacity under the Revolving Credit Facility of up to an initial aggregate elected commitment amount of $150 million (with an initial aggregate maximum credit amount of $500 million), subject to borrowing base redeterminations and satisfaction of customary borrowing conditions. The Revolving Credit Facility will also allow us to request that the aggregate elected commitments be increased up to the aggregate maximum credit amount, subject to certain conditions. If new debt is added to our debt levels, or any debt is incurred by our subsidiaries, the related risks that we and our subsidiaries currently face could increase.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Our Notes and borrowings under the Revolving Credit Facility bear interest at variable rates and expose us to interest rate risk. See “Description of Material Indebtedness” for further information regarding our Notes and the Revolving Credit Facility. Borrowings under the Revolving Credit Facility will bear interest, at our option, at a rate equal to either (i) an alternate base rate (the greatest of the Prime Rate, the Federal Funds Rate plus 1/2 of 1.00%, or one-month Term SOFR plus 1.00%) plus an applicable margin ranging from 1.50% to 2.50%, or (ii) Term SOFR plus an applicable margin ranging from 2.50% to 3.50%, in each case based on utilization of the borrowing base, and the unused portion of the Revolving Credit Facility will be subject to a commitment fee ranging from 0.375% to 0.50%. Term SOFR will be subject to a floor of 2.50% while the Senior Notes are in effect and 0.00% thereafter. If interest rates increase, our interest payments would increase even though the amount borrowed remains the same, and our net income and cash flows, including cash available for servicing our indebtedness, would correspondingly decrease. Although we may enter into agreements limiting our exposure to higher interest rates, these agreements may not be effective.

Risks Related to this Offering and Ownership of Our Class A Common Stock

As an emerging growth company within the meaning of the Securities Act, we may utilize certain modified disclosure requirements, and we cannot be certain if these reduced requirements will make shares of our Class A common stock less attractive to investors.

We are an emerging growth company, and, for as long as we continue to be an emerging growth company, we may choose to take advantage of exemptions from various reporting requirements applicable to other public companies but not to “emerging growth companies,” including:

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presenting only two years of audited financial statements;

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an exemption from compliance with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act;

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reduced disclosure about our executive compensation arrangements in our periodic reports, proxy statements and registration statements; and

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exemptions from the requirements of holding non-binding advisory votes on executive compensation or golden parachute arrangements.

We have in this prospectus utilized, and we may in future filings with the SEC continue to utilize, the modified disclosure requirements available to emerging growth companies. As a result, our stockholders may not have access to certain information they may deem important.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can utilize the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. Thus, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to not “opt out” of this exemption from complying with new or revised accounting standards, and, therefore, we are permitted to adopt new or revised accounting standards at the time private companies adopt the new or revised accounting standards and are permitted to do so until such time that we either (i) irrevocably elect to “opt out” of such extended transition period or (ii) no longer qualify as an emerging growth company. As a result, we will not be subject to the same new or revised accounting standards at the same time as other public companies that are not emerging growth companies or those that have opted out of using such extended transition period, which may make comparison of our financial statements with such other public companies more difficult.

Following this offering, we will remain an emerging growth company until the last day of the fiscal year following the fifth anniversary of the completion of our initial public offering unless, prior to that time, we have more than $1.235 billion in annual gross revenue, have a market value for our Class A common stock held by non-affiliates of more than $700 million as of the last day of our second fiscal quarter of the fiscal year and a determination is made that we are deemed to be a “large accelerated filer,” as defined in Rule 12b-2 promulgated under the Exchange Act, or issue more than $1.0 billion of non-convertible debt over a three-year period, whether or not issued in a registered offering.

We could be subject to claims based on the defective corporate acts ratified by us pursuant to Section 204 of the DGCL.

In connection with our preparation for this offering, we identified that our certificate of incorporation, as filed with the Delaware Secretary of State, did not align with our historical issuances of Class A common stock. As a result, shares of our Class A common stock were issued in excess of the number of authorized shares of Class A common stock under our certificate of incorporation then in effect. We also identified that shares of our Class A common stock and preferred stock may have been issued without obtaining certain required approvals of our board of directors and stockholders, and that our initial board of directors was not properly elected. Because these actions were not authorized and effected in compliance with the DGCL, they constituted “defective corporate acts” within the meaning of Section 204 of the DGCL.

On December 29, 2025, our board of directors adopted resolutions ratifying these defective corporate acts in accordance with Section 204 of the DGCL, including the election of our initial board of directors and all historical issuances of our Class A common stock and preferred stock. In connection with the ratification, we filed certificates of validation with the Delaware Secretary of State to reflect the intended number of authorized shares of Class A common stock in our certificate of incorporation, which have been processed and are effective. We delivered notice of the ratification to our stockholders on January 15, 2026, in accordance with the requirements of Section 204 of the DGCL.

Under Section 204 of the DGCL, any claim that any of the ratified defective corporate acts or putative stock is void or voidable due to the failures of authorization (as that term is used in Section 204), or any claim that the Delaware Court of Chancery should declare in its discretion that the ratification thereof not be effective or be effective only on certain conditions, must be brought within 120 days from the date on which notice of the ratification is given. Until such notice is given and the applicable 120-day period has expired, a stockholder or other party may seek to challenge the effectiveness of the ratification and the Delaware Court of Chancery could determine that the ratification was not effective or that additional actions are required to fully validate the defective corporate acts.

If the ratification of these defective corporate acts is successfully challenged, or if we are required to undertake additional corrective actions, we could be subject to further claims, disputes, or liabilities, including with respect to the validity, ownership, or issuance of our outstanding equity securities. Any such claims, disputes, or liabilities could result in significant costs, divert management’s attention, adversely affect our business, financial condition, and results of operations, and adversely affect the rights of our stockholders.

Delaware law and anti-takeover provisions in our governing documents, as well as our existing and future debt agreements, could make an acquisition of our company more difficult, limit attempts by our stockholders to replace or remove our current directors and may deprive our investors of the opportunity to receive a premium for their shares.

Our amended and restated certificate of incorporation, amended and restated bylaws and Delaware law contain provisions that will have the effect of rendering more difficult, delaying or preventing a third party from, acquiring control of us without the approval of our board of directors. Among other things, these provisions:

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have terms that have the same effect as DGCL Section 203;

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provide for a classified board of directors with staggered three-year terms;

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authorize the issuance of “blank check” preferred stock, the terms of which are established by our board of directors without any need for action by stockholders, that could be used to implement a stockholder rights plan;

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do not permit stockholders to call special meetings of stockholders;

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do not permit stockholders to act by written consent; and

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establish advance notice procedures, which apply for stockholders to nominate candidates for election to our board of directors or for proposing matters that can be acted on by stockholders at stockholder meetings.

Further, documents governing our indebtedness impose limitations on our ability to enter into change of control transactions and we anticipate that any documents governing our future indebtedness will also impose such limitations. The occurrence of a change of control transaction could constitute an event of default thereunder and permit acceleration of the indebtedness, thereby impeding our ability to enter into certain transactions.

The foregoing factors could discourage, delay or prevent a transaction involving a change in control of the Company, which 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 Class A common stock. See “Description of Capital Stock.”

We intend to pay regular dividends to our stockholders, but our ability to do so is subject to the discretion of our board of directors and may be limited by distributions and other payments from OpCo and our operating subsidiaries our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements, instruments governing our indebtedness and other factors and restrictions our board of directors deems relevant.

After the consummation of this offering, we intend to pay our stockholders regular dividends. However, the payment of dividends and other distributions is at the discretion of our board of directors and our board of directors may, in its discretion, increase, decrease or eliminate the payment of dividends. Our ability to pay dividends depends on many factors, including, but not limited to, financial conditions, results of operations, cash flows, prospects, industry conditions, capital requirements, instruments governing our indebtedness (including those goverinng our Senior Notes and the Revolving Credit Facility), any preferred stock, general business conditions and any other factors that our board of directors may deem relevant in making such a determination. Additionally, because we have no independent means of generating revenue or cash flow and we anticipate that the only source of our earnings will be cash distributions from our operating subsidiaries, our ability to pay dividends is dependent on the ability of our operating subsidiaries to make distributions to OpCo and the ability of OpCo to make distributions to us in an amount sufficient to cover such obligations. In particular, our ability to pay dividends is limited by covenants governing our Senior Notes and Revolving Credit Facility and may be further restricted by the terms of any future debt or preferred securities. See “Description of Material Indebtedness.” Furthermore, our ability to declare and pay dividends to our stockholders is likewise subject to Delaware law (which may limit the amount of funds available for dividends). While we do not currently believe that these restrictions will impair our ability to continue to pay regular cash dividends, there can be no assurance that we will not need or determine to reduce or eliminate the payment of dividends on our Class A common stock in the future. See “Dividend Policy.”

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

Our amended and restated certificate of incorporation will authorize our board of directors 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. In addition, following this offering, we expect to have shares of Series B preferred stock and Series D preferred stock outstanding. See “Description of Capital Stock.” The terms of one or more classes or series of our preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of a class or series of our 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 our preferred stock could affect the residual value of our Class A common stock.

No market currently exists for our Class A common stock and we cannot assure you that an active market will develop for such stock.

Prior to this offering, there has been no public market for our Class A common stock. The initial public offering price for our Class A common stock has been determined through negotiations among us and the representatives of the underwriters and may not be indicative of the market price of our Class A common stock after this offering or to any other established criteria of the value of our business. If you purchase shares of our Class A common stock, you may not be able to resell those shares at or above the initial public offering price. We cannot predict the extent to which investor interest in us will lead to the development of an active trading market on the NYSE or otherwise or how liquid that market might become. An active public market for our Class A common stock may not develop or be sustained after this offering. If an active public market does not develop or is not sustained, it may be difficult for you to sell your shares of Class A common stock at a price that is attractive to you or at all.

We cannot assure you that our stock price will not decline or not be subject to significant volatility after this offering.

The market price of shares of Class A common stock could be subject to significant fluctuations after this offering. The price of our stock may change in response to fluctuations in our results of operations in future periods and also may change in response to other factors, including factors specific to companies in our industry, many of which are beyond our control. As a result, our share price may experience significant volatility and may not necessarily reflect the value of our expected performance and may cause our stockholders to incur losses.

Among the factors that could affect our stock price are:

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changes in laws or regulations applicable to our industry;

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speculation about our business or industry in the press or the investment community;

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price and volume fluctuations in the overall stock market;

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volatility in the market price and trading volume of companies in our industry or companies that investors consider comparable;

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share price and volume fluctuations attributable to inconsistent trading levels of our shares;

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sales of Class A common stock by us or our significant stockholders, officers and directors;

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the expiration or waiver of the lock-up provision contained in the lock-up agreements and our amended and restated certificate of incorporation;

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the development and sustainability of an active trading market for shares of our Class A common stock;

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the public’s response to press releases or other public announcements by us or others, including our filings with the SEC, announcements relating to litigation or changes to our key personnel;

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the effectiveness of our internal controls over financial reporting;

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variations in our quarterly or annual results of operations;

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changes in our earnings estimates (if provided) or differences between our actual results of operations and those expected by investors and analysts;

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the contents of published research reports about us or our industry or the failure of securities analysts to cover our Class A common stock;

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actions by institutional stockholders;

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changes in our capital structure, such as future issuances of debt or equity securities;

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our entry into new markets;

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tax developments in the United States or other markets;

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strategic actions by us or our competitors, such as acquisitions, significant contracts, dispositions, strategic relationships, joint ventures, capital commitments or restructurings; and

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changes in accounting principles.

Further, the stock markets have experienced extreme price and volume fluctuations that have affected and continue to affect the market prices of equity securities of many companies. These fluctuations can be unrelated or disproportionate to the operating performance of those companies. In addition, the stock prices of many energy companies have experienced wide fluctuations that have often been unrelated to the operating performance of those companies. These broad market and industry fluctuations, as well as general economic, political and market conditions such as recessions, interest rate changes or international currency fluctuations, may cause the market price of shares of our Class A common stock to decline.

We cannot assure you that you will be able to resell any of your shares of Class A common stock at or above the initial public offering price. The initial public offering price will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of prices that will prevail in the trading market, if a trading market develops, after this offering. If the market price of shares of Class A common stock after this offering does not exceed the initial public offering price, you may not realize any return on your investment and may lose some or all of your investment.

Our amended and restated certificate of incorporation will designate the Court of Chancery of the State of Delaware and the federal district courts of the United States as the sole and exclusive forums for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.

Our amended and restated certificate of incorporation will provide that, subject to certain exceptions, unless we consent in writing in advance to the selection of an alternative forum, the Court of Chancery of the State of Delaware will be the sole and exclusive forum for any (i) derivative action or proceeding brought on our behalf, (ii) action asserting a claim of breach of a fiduciary duty or other wrongdoing by any current or former director, officer, employee, agent or stockholder to us or our stockholders, (iii) action asserting a claim arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our amended and restated bylaws or as to which the DGCL confers jurisdiction on the Court of Chancery of the State of Delaware or (iv) action asserting a claim governed by the internal affairs doctrine of the law of the State of Delaware. Pursuant to the Exchange Act, claims or causes of action arising thereunder must be brought in federal district courts of the United States. The exclusive forum provision will provide that the provision will not apply to claims or causes of action arising under the Exchange Act. However, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce a duty or liability created by the Securities Act or the rules and regulations thereunder; accordingly, we cannot be certain that a court would enforce such provision. Our amended and restated certificate of incorporation will further provide that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have notice of and consented to the provisions of our amended and restated certificate of incorporation described above; however, investors cannot waive compliance with the federal securities laws and the rules and regulations thereunder.

Our amended and restated certificate of incorporation will also provide that, unless we consent in writing to an alternative forum, the federal district courts of the United States will be the sole and exclusive forum for the resolution of any action asserting a claim arising under the Securities Act or the rules and regulations thereunder. 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, accordingly we cannot be certain that a court would enforce such a provision. By agreeing to this provision, however, stockholders will not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder.

These choice of forum provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or other stockholders, which may discourage such lawsuits. While the Delaware courts have determined that such choice of forum provisions are facially valid, a stockholder may nevertheless seek to bring an action in a venue other than those designated in the exclusive forum provisions. In such instance, we would expect to assert the validity and enforceability of our exclusive forum provisions, which may require significant additional costs associated with resolving such action in other jurisdictions, and there can be no assurance that the provisions will be enforced by a court in those other jurisdictions. If a court were to find that the exclusive forum provision in our amended and restated certificate of incorporation to be inapplicable or unenforceable in an action, we may incur further significant additional costs associated with resolving the dispute in other jurisdictions, which could have a material adverse effect on our business, financial condition and results of operations.

Claims for indemnification by our directors and officers may reduce our available funds to satisfy successful third-party claims against us and may reduce the amount of money available to us.

Our amended and restated certificate of incorporation and amended and restated bylaws will provide that we will indemnify our directors and officers, in each case, to the fullest extent permitted by Delaware law. Pursuant to our certificate of incorporation, our directors will not be liable to us or any stockholders for monetary damages for any breach of fiduciary duty, except (i) for acts that breach his or her duty of loyalty to us or our stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of the law, (iii) pursuant to Section 174 of the DGCL, which provides for liability of directors for unlawful payments of dividends of unlawful stock purchase, or (iv) for any transaction from which the director derived an improper personal benefit. Our amended and restated bylaws will also require us, if so requested, to advance expenses that such director or officer incurred in defending or investigating a threatened or pending action, suit or proceeding, provided that such person will return any such advance if it is ultimately determined that such person is not entitled to indemnification by us. Any claims for indemnification by our directors and officers may reduce our available funds to satisfy successful third-party claims against us and may reduce the amount of money available to us.

As a public reporting company, we will be subject to rules and regulations established from time to time by the SEC regarding our disclosure controls and procedures and internal control over financial reporting. If we fail to establish and maintain effective disclosure controls and procedures and internal control over financial reporting, we may not be able to accurately report our financial results, or report them in a timely manner.

As a public reporting company, we will be subject to the rules and regulations established from time to time by the SEC and the national securities exchange on which our securities are listed. These rules and regulations require, among other things, that we establish and periodically evaluate procedures with respect to our internal control over financial reporting. Reporting obligations as a public company are likely to place a considerable strain on our financial and management systems, processes and controls, as well as on our personnel.

In addition, upon becoming a public company, we will be required to comply with the Sarbanes-Oxley Act, which requires, among other things, that we maintain effective disclosure controls and procedures and internal control over financial reporting and, pursuant to Section 404 of the Sarbanes-Oxley Act, furnish a report by management on the effectiveness of our internal control over financial reporting in our second annual report. However, as discussed above, for as long as we are an emerging growth company under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404. We could be an emerging growth company for up to five years. An independent assessment of our internal control over financial reporting could detect problems that our management’s assessment might not. The process of reviewing and improving our internal controls is both costly and challenging and may also require substantial attention from our management team, which could negatively impact other matters that are important to our business.

Although management did not, and was not required to, conduct a formal assessment of internal control over financial reporting as of December 31, 2025, as a result of the Misstatement and the Restatement, the Company identified certain material weaknesses in its internal control over financial reporting. As a result of the material weaknesses in internal control over financial reporting, our disclosure controls and procedures were not effective at a reasonable assurance level as of December 31, 2025. Management will be implementing changes to strengthen our internal controls and remediate the material weaknesses. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Internal Controls and Procedures—Material Weaknesses in Internal Control over Financial Reporting” for additional information related to the material weaknesses in internal control over financial reporting and our related remediation activities.

If our senior management is unable to conclude that we have effective disclosure controls and procedures and internal control over financial reporting, or to certify the effectiveness of such controls, and our independent registered public accounting firm cannot render an unqualified opinion on management’s assessment and the effectiveness of our internal control over financial reporting at such time as it is required to do so and material

weaknesses in our internal control over financial reporting are identified, we could be subject to regulatory scrutiny, a loss of public and investor confidence and litigation from investors and stockholders, which could have a material adverse effect on our business and our stock price. In addition, if we do not maintain adequate financial and management personnel, processes and controls, we may not be able to manage our business effectively or accurately report our financial performance on a timely basis, which could cause a decline in the price of shares of Class A common stock and have a material adverse effect on our business, financial condition and results of operations. Failure to comply with the Sarbanes-Oxley Act could potentially subject us to sanctions or investigations by the SEC, the exchange upon which our securities are listed or other regulatory authorities, which would require additional financial and management resources.

If securities or industry analysts do not publish research or publish inaccurate or unfavorable research about our business, our stock price and trading volume 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. We do not currently have and may never obtain research coverage by securities and industry analysts. If no securities or industry analysts commence coverage of us, the trading price for our Class A common stock would be negatively impacted. If we obtain securities or industry analyst coverage and if one or more of these analysts cease coverage of our company or fails 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 our results of operations do not meet the expectations of the investor community, or one or more of the analysts who cover our company downgrade our stock, our stock price could decline. As a result, you may not be able to sell shares of our Class A common stock at prices equal to or greater than the initial public offering price.

Becoming a public company will significantly increase our compliance costs and require the expansion and enhancement of a variety of financial and management control systems and infrastructure and the hiring of additional qualified personnel.

Prior to this offering, we have not been subject to the reporting requirements of the Exchange Act, the Sarbanes-Oxley Act, the Dodd-Frank Act or the other rules and regulations of the SEC, or any securities exchange relating to public companies. We are working with our legal, independent accounting and financial advisors to identify those areas in which changes should be made to our financial and management control systems to manage our growth and our obligations as a public company. These areas include financial planning and analysis, tax, corporate governance, accounting policies and procedures, internal controls, internal audit, disclosure controls and procedures and financial reporting and accounting systems. We have made, and will continue to make, significant changes in these and other areas and have begun incurring expenses in preparation for becoming a public company. The expenses that will be required in order to adequately prepare for being, and those required to operate as, a public company could be material. Compliance with the various reporting and other requirements applicable to public companies will also require considerable time and attention of management and we could be required to hire additional qualified personnel into our existing finance, legal, human resources and operations departments to meet such compliance needs.

The requirements of being a public company may strain our resources, divert management’s attention and affect our ability to attract and retain qualified board members and officers, which may divert from our business operations.

As a public company, we are subject to the reporting requirements of the Exchange Act, the listing requirements of the national securities exchange on which our securities are listed and other applicable securities rules and regulations. Compliance with these rules and regulations will increase our legal and financial compliance costs, strain our resources, make some activities more difficult, time-consuming or costly and increase demand on our systems, resources, management and employees. As a public company, we will be required to enhance our investor relations, legal, financial and tax reporting, internal audit, legal, governance, investor relations and

corporate communications functions. The Exchange Act requires, among other things, that we file annual, quarterly and current reports with respect to our business and results of operations and maintain effective disclosure controls and procedures and internal control over financial reporting. To maintain and, if required, improve our disclosure controls and procedures and internal control over financial reporting to meet this standard, significant resources and management oversight may be required. As a result, management’s attention may be diverted from other business concerns, which could have a material adverse effect on our business, financial condition and results of operations.

We also expect that being a public company will make it more expensive for us to obtain director and officer liability insurance, and we may be required to choose between reduced coverage and substantially higher costs in order to obtain coverage. These factors could make it more difficult for us to attract and retain qualified executive officers and members of our board of directors, particularly to serve on our audit committee and compensation committee.

Future sales and issuances of our Class A common stock or rights to purchase our Class A common stock (or other equity securities or securities convertible into our Class A common stock), or the perception that future sales by us or our other existing stockholders in the public market following this offering could cause dilution of the percentage of ownership of our stockholders, could cause the market price for our Class A common stock to decline.

After this offering, the sale of shares of our Class A common stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of shares of our Class A common stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.

Upon consummation of this offering, we will have a total of shares of our Class A common stock outstanding (or shares if the underwriters exercise in full their option to purchase additional shares). Of the outstanding shares, the shares sold in this offering (or shares if the underwriters exercise in full their option to purchase additional shares) will be freely tradable without restriction or further registration under the Securities Act, other than any shares held by our affiliates. Any shares of our Class A common stock held by our affiliates will be eligible for resale pursuant to Rule 144 under the Securities Act, subject to the volume, manner of sale, holding period and other limitations of Rule 144.

We and our directors and executive officers will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the offer, sale or disposition or hedge of any of our securities for a period of 180 days following the date of this prospectus. Additionally, our amended and restated certificate of incorporation will provide that, subject to certain exceptions, all of the shares of Class A common stock held by the Legacy Common Stock Investors may not be sold, pledged, transferred or otherwise disposed of for 365 days following the consummation of this offering, or such shorter period as determined by the board of directors, but in no event less than 180 days without the prior written consent of the managing underwriter of this offering. Upon the expiration of the lock-up restrictions, shares held by our directors, executive officers and the Legacy Common Stock Investors will be eligible for resale in the public market subject, in the case of shares held by our affiliates, to the volume, manner of sale, holding period and other limitations of Rule 144. The representatives of the underwriters may, in their sole discretion and at any time without notice, release all or any portion of the shares or securities subject to any such lock-up restrictions. See “Underwriting” and “Shares Eligible for Future Sale” for a description of these lock-up restrictions.

In addition, in connection with this offering, we intend to enter into the Registration Rights Agreement with certain of our Continuing Equity Owners. The Registration Rights Agreement will provide such holders with certain registration rights in respect of shares of our Class A common stock held by them, subject to certain conditions. Registration of any of these outstanding shares of Class A common stock would result in such shares becoming freely tradable without compliance with Rule 144 upon effectiveness of the registration statement.

Such Continuing Equity Owners party to the Registration Rights Agreement will, subject to the terms of the agreement, determine the timing and amount of sales of their Class A common stock, and such sales could be executed at a time or times that otherwise may not align with our interests and the interests of our other stockholders. See “Certain Relationships and Related Party Transactions” and “Shares Eligible for Future Sale” for a description of these registration rights.

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of shares of our Class A common stock issued or reserved for issuance under new and existing equity incentive plans. Subject to the satisfaction of vesting conditions and the expiration of lock-up restrictions, shares issued pursuant to or registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our 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. In the future, we may issue securities in connection with investments, acquisitions or capital raising activities. In particular, the number of shares of our Class A common stock issued in connection with an investment or acquisition, or to raise additional equity capital, could constitute a material portion of our then-outstanding shares of our Class A common stock. Any such issuance of additional securities in the future, or the perception that such issuances could occur, may result in additional dilution to you, or may adversely impact the price of our Class A common stock.

If you purchase shares of our Class A common stock sold in this offering, you will incur immediate and substantial dilution.

If you purchase Class A common stock in this offering, you will pay more for your shares than the amounts paid by existing stockholders for their shares. As a result, you will incur immediate dilution of $ per share, representing the difference between the assumed initial public offering price of $ per share (the midpoint of the estimated initial public offering price range set forth on the cover of this prospectus) and our pro forma net tangible book value (deficit) per share after giving effect to this offering. See “Dilution.”

Increases in interest rates may cause the market price of our Class A common stock to decline.

An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based equity investments such as our Class A common stock. Any such increase in interest rates or reduction in demand for our Class A common stock resulting from other investment opportunities may cause the trading price of our Class A common stock to decline.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “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, the words “may,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions and the negative of such words and similar expressions are intended 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 expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. 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.

The following important factors, in addition to those discussed elsewhere in this prospectus, could affect the future results of the energy industry in general, and our company in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

•

our revenues are primarily derived from mineral and royalty payments that are based on the price of natural gas, NGL and oil which is subject to volatility due to factors beyond our control;

•

lower natural gas, NGL and oil prices or negative adjustments of natural gas, NGL and oil prices may result in significant impairment charges;

•

our derivative activities may limit the cash flows received from natural gas and oil sales;

•

the development of our properties relies exclusively on our third-party operators and these operators may fail to develop our existing inventory of mineral and royalty acreage;

•

drilling for and producing natural gas, NGLs and oil are high-risk activities with many uncertainties;

•

our third-party operators may fail to drill sufficient wells to hold acreage before lease expiration which may result in loss of lease and prospective drilling opportunities;

•

we may experience delays in the receipt of royalty payments and may not be able to terminate leases with defaulting lessees if our third-party operators declare bankruptcy;

•

we may incur losses as a result of title defects or other issues in the properties we own;

•

a limited number of third-party operators currently generate a significant portion of our revenue and accounts receivable;

•

the substantial majority of our business is concentrated in the Appalachian and Haynesville Basins, making us vulnerable to risks associated with such geographic concentration of our assets;

•

we are subject to risks related to our wells where we are a non-operating working interest owner;

•

our future success depends on replacing reserves through acquisitions and there may be constraints in our ability to finance acquisitions;

•

we have experienced significant business and portfolio growth in a short time, and our significant growth rates and financial results may not be sustainable or indicative of future financial performance;

•

any acquisition of additional mineral and royalty interests that we complete will be subject to substantial risks;

•

our failure to retain our key personnel or attract additional qualified personnel could negatively affect our business strategy;

•

our estimated proved reserves are based on many assumptions that may prove to be inaccurate;

•

our identified drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling and there is no guarantee that our estimates will be materially consistent with actual drilling activities;

•

we rely on our third-party operators, other third parties and government databases for information regarding our assets and such information may be incorrect, incomplete or lost;

•

we may be subject to information technology system failures, network disruptions, cyber-attacks or other breaches in data security;

•

declining general economic, business or industry conditions, which could have a material adverse effect on our business;

•

our industry is highly competitive, and competitive pressures could negatively affect our business;

•

exported liquid natural gas could fail to be a competitive source of energy for the United States or international markets;

•

our growth strategy is partly dependent upon the continued expansion of electricity demand driven by AI data center development and expectations regarding increased demand may not materialize;

•

the unavailability, high cost or shortages of equipment, raw materials, supplies or personnel for our third-party operators related to developing and operating our properties;

•

the marketability of natural gas, NGLs and crude oil is dependent on the availability of equipment and transportation facilities that is outside of our and our third-party operators’ control;

•

our third-party operators are subject to significant governmental regulations, and governmental authorities can delay or deny permits and approvals or change legal requirements governing our business, which could restrict their operations, increase costs of conducting our business, and delay our implementation of, or cause us to change, our business strategy;

•

the development and enactment of climate change legislation as well as increased attention to sustainability may impact our business or the business of our third-party operators;

•

future legislative or regulatory changes may have a material adverse effect on our business;

•

our use of borrowings to finance our business exposes us to risks and any future indebtedness we may incur could further increase the risks associated with our indebtedness;

•

our ability to pay regular dividends to our stockholders may be limited by our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements, instruments governing our indebtedness and other factors and restrictions; and

•

the requirements of being a public company may strain our resources, divert management’s attention and affect our ability to attract and retain qualified board members and officers.

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. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking

statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Reserve engineering is a process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate 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 further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered.

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.

OUR ORGANIZATIONAL STRUCTURE

In connection with the consummation of the offering, we will consummate the Transactions:

•

we will amend and restate our certificate of incorporation (our “amended and restated certificate of incorporation”) to, among other things, (i) change our name to “WhiteHawk Minerals Corp.”; (ii) provide for the Common Stock Reclassification; (iii) provide for an adjustment to the number of authorized shares such that our authorized capital stock shall consist of 250,000,000 shares of Class A common stock, par value $0.0001 per share, 100,000,000 shares of Class B common stock, par value $0.0001 per share, and 10,000,000 shares of preferred stock, par value $0.0001 per share; (iv) authorize our board of directors to establish and issue one or more series of preferred stock from time to time and to fix the rights, preferences, privileges and restrictions thereof; (v) provide for the creation of Class B common stock in connection with our anticipated Up-C structure, with shares of Class B common stock to be issued to Continuing Equity Owners, with each share of Class B common stock entitled to one vote per share and no economic rights; and (vi) establish that Legacy Common Stock Investors are prohibited from selling their Class A common stock or related securities for 365 days following the consummation of this offering, or such shorter period as determined by the board of directors, but in no event less than 180 days without the prior written consent of the managing underwriter of this offering;

•

we will enter into the Registration Rights Agreement with certain Continuing Equity Owners, as further described in “Certain Relationships and Related Person Transactions;”

•

in connection with and in order to effectuate the Internalization, the Contribution Agreement will be entered into by the parties thereto, pursuant to which, among other things, OpCo will acquire all of the outstanding equity interests in ManagementCo from the Management Owners in exchange for OpCo Interests and shares of Class B common stock. Prior to the closing of this offering, ManagementCo, as our external manager, provided certain management, acquisition, disposition and oversight functions with respect to us and WhiteHawk OpCo. As a result of the Internalization, ManagementCo will become a wholly owned subsidiary of WhiteHawk OpCo and we will become internally managed;

•

Immediately following the consummation of the Transactions (including this offering):

•

we will be a holding company and our principal asset will consist of OpCo Interests we acquire or are otherwise issued directly from WhiteHawk OpCo;

•

as the sole member of OP GP, the sole general partner of WhiteHawk OpCo, we will control the business and affairs of WhiteHawk OpCo;

•

we will own a number of Series B preferred units in WhiteHawk OpCo equal to the number of shares of Series B Preferred Stock outstanding after the consummation of the Transactions, representing 100% of the preferred units of WhiteHawk OpCo;

•

we will no longer have any shares of Series D preferred stock outstanding;

•

Our corporate structure following this offering, as described below, is an Up-C structure. The Up-C structure will allow the Continuing Equity Owners to retain their equity ownership in WhiteHawk OpCo following the Transactions and to continue to realize tax benefits associated with owning interests in an entity that is treated as a partnership, or “flow-through” entity, for U.S. federal income tax purposes. Investors in this offering will, by contrast, hold their equity ownership in us, a Delaware corporation that is a domestic corporation for U.S. federal income tax purposes, in the form of shares of Class A common stock. One of the tax benefits to the Continuing

Equity Owners associated with this structure is that future taxable income of WhiteHawk OpCo that is allocated to the Continuing Equity Owners will be taxed on a flow-through basis and, therefore, will not be subject to corporate taxes at the entity level. Moreover, the Up-C structure permits the Continuing Equity Owners to defer the recognition of taxable gain on their OpCo Interests until they elect to exercise their redemption right (rather than recognizing such gain at the time of this offering). Additionally, because the Continuing Equity Owners may at their election have their OpCo Interests redeemed by WhiteHawk OpCo (or at our option, directly exchanged by us) for newly issued shares of our Class A common stock on a one-for-one basis (subject to customary adjustments, including for stock splits, stock dividends, and reclassifications) or, at our option, for cash, the Up-C structure also provides the Continuing Equity Owners with potential liquidity that holders of non-publicly traded limited liability companies are not typically afforded. Upon any such redemption or exchange of OpCo Interests for shares of Class A common stock, the Company may benefit from certain tax attributes, including potential increases in tax basis that may reduce the amount of tax that would otherwise be payable by us. In connection with any such redemption or exchange of OpCo Interests, a corresponding number of shares of Class B common stock held by the relevant Continuing Equity Owner will automatically be transferred to us for no consideration and be canceled.

For more information regarding the Transactions and our structure, see “Our Organizational Structure.”

Organizational Structure

LOGO

(1)	Excludes any Continuing Equity Owners who hold Class A common stock as a result of the Common Stock Reclassification (in addition to OpCo Interests and Class B common stock).

(2)

(3)

USE OF PROCEEDS

We estimate that the net proceeds to us from our sale of shares of Class A common stock in this offering will be approximately $ , after deducting underwriting discounts and commissions and estimated expenses payable by us in connection with this offering. The underwriters also have an option to purchase up to an additional shares of Class A common stock from us. We estimate that the net proceeds to us, if the underwriters exercise their right to purchase the maximum of additional shares of Class A common stock from us, will be approximately $ , after deducting underwriting discounts and commissions and estimated expenses payable by us in connection with this offering. This assumes a public offering price of $ per share of Class A common stock, which is the midpoint of the price range set forth on the cover of this prospectus.

We intend to use the net proceeds from this offering, as well as cash on hand, as follows: (i) approximately $ million to prepay, in whole or in part, the outstanding principal of our Senior Notes, (ii) approximately $ million for the redemption of all of the outstanding shares of our Series D preferred stock, (iii) approximately $ million for the redemption of a portion of our outstanding Series B preferred stock, and (iv) the remainder for other general corporate purposes, including the payment of a Liquidity Incentive Fee of $ million to upon completion of this offering. See “Certain Relationships and Related Person Transactions—Investment Management Agreement.”

We are a holding company and our only assets after consummation of this offering will be our ownership of OpCo Interests and membership units in OP GP. Accordingly, we intend to use the gross proceeds from this offering to purchase newly issued OpCo Interests from WhiteHawk OpCo at a price per unit equal to the initial public offering price per share of Class A common stock, less estimated underwriting discounts and commissions. In the event the underwriters exercise their option to purchase additional shares of Class A common stock, we intend to use any such additional proceeds in the same manner.

As of December 31, 2025, we had $237.7 million of principal outstanding under our Senior Notes. Our Senior Notes bear interest at the adjusted term SOFR rate plus 6.50%, which, as of December 31, 2025, resulted in an interest rate of 10.80% per annum. The Senior Notes mature on June 23, 2030.

Assuming no exercise of the underwriters’ option to purchase additional shares, a $1.00 increase (decrease) in the assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this prospectus) would increase (decrease) the net proceeds to us from this offering by $ , assuming the number of shares offered by us, as set forth on the cover of this prospectus, remains the same and after deducting underwriting discounts and commissions and estimated expenses payable by us.

DIVIDEND POLICY

We initially intend to make a significant portion of our Cash Available for Distribution available for dividends. Holders of our Class B common stock are not entitled to participate in any dividends declared by our Board. We aim to balance the return of capital to investors with the selective allocation of capital toward acquisitions that we believe will be accretive to stockholder value while preserving a strong balance sheet through varying commodity price environments. In order to effect this approach, we intend to return capital to our stockholders through quarterly dividends, after retaining cash for debt service, our working capital needs and acquisition activities.

While we expect to pay regular dividends in accordance with this financial philosophy, we have not adopted a formal written dividend policy to pay a fixed amount of cash regularly or to pay any particular amount based on the achievement of, or derivable from, any specific financial metrics, including Cash Available for Distribution. The actual amount of any dividends we pay may fluctuate depending on our cash flow needs, which may be impacted by potential acquisition opportunities and the availability of financing alternatives, the need to service any indebtedness or other liquidity needs and general industry and business conditions, including the impact of commodity prices and the pace of the development of our properties by our third-party operators. Our payment of dividends will be at the sole discretion of our board of directors, which may change our dividend philosophy at any time. Our board of directors will take into account:

•

general economic and business conditions;

•

our financial condition and operating results;

•

our cash flows from operations and current and anticipated cash needs;

•

legal, tax, regulatory and contractual restrictions; and

•

such other factors as our board of directors may deem relevant.

Additionally, our ability to pay dividends is restricted by covenants governing our Senior Notes and the Revolving Credit Facility. For a description of the covenants governing our Senior Notes and those contained in the Revolving Credit Facility that restrict our ability to pay dividends, see “Description of Material Indebtedness.” Additionally, our ability to pay dividends may be restricted by the terms of any future credit agreement or any future debt or preferred equity securities of us. Therefore, there can be no assurance that we will pay any dividends to holders of our Class A common stock, or as to the amount of any such dividends. See “Risk Factors—Risks Related to this Offering and Ownership of Our Class A Common Stock—We intend to pay regular dividends to our stockholders, but our ability to do so is subject to the discretion of our board of directors and may be limited by our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements, instruments governing our indebtedness and other factors and restrictions our board of directors deems relevant.”

CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of December 31, 2025:

•

on an actual basis; and

•

as adjusted to give effect to (i) the Transactions, (ii) the sale of shares of our Class A common stock in this offering, at an assumed public offering price of $ per share, which is the midpoint of the price range set forth on the cover of this prospectus, after deducting the underwriting discount and estimated offering expenses payable by us, (iii) the application of the net proceeds received by us from this offering as described under “Use of Proceeds” (iv) our entry into the Revolving Credit Facility and the amendment to the Note Purchase Agreement (each as described under “Description of Material Indebtedness”), and (v) the use, if any, of cash on hand to fully redeem the outstanding aggregate principal of the Series D Preferred Stock.

The following table should be read in conjunction with “Use of Proceeds,” “Unaudited Pro Forma Condensed Consolidated Combined Financial Information,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Description of Material Indebtedness,” “Description of Capital Stock” and the audited consolidated financial statements and notes thereto included elsewhere in this prospectus.


	As of December 31, 2025
	Actual			As Adjusted⁽¹⁾
	(in thousands, except par and share amounts)
Cash and cash equivalents	$	28,989		$

Total Debt⁽²⁾:
Senior Notes	$	237,700		$
Revolving Credit Facility		—

Mezzanine equity:
Series B Preferred stock, $0.0001 par value; shares authorized; issued and outstanding		27,662
Series D Preferred stock, $0.0001 par value; shares authorized; issued and outstanding⁽³⁾		—			—
Stockholders’ equity:
Class A common stock, par value $0.0001 per share; no shares authorized, issued and outstanding, actual; shares authorized, shares issued and outstanding, WhiteHawk Income Corporation pro forma		—
Class B common stock, par value $0.0001 per share; no shares authorized, issued and outstanding, actual; shares authorized, shares issued and outstanding, WhiteHawk Income Corporation pro forma		—
Class A common stock, $0.0001 par value; 6,000,000 shares authorized; 6,518,383 shares issued and outstanding⁽⁴⁾					—
Class T common stock, $0.0001 par value; 6,000,000 shares authorized; 66,830 shares issued and outstanding					—
Class I common stock, $0.0001 par value; 6,000,000 shares authorized; 8,050,883 shares issued and outstanding					—
Additional paid in capital		223,900
Accumulated deficit		(15,146	)

Total stockholders’ equity		208,754

Total capitalization	$			$

(1)	Each $1.00 increase or decrease in the public offering price per share would increase or decrease, as applicable, our net proceeds, after deducting the underwriting discount and estimated offering expenses payable by us, by $ million (assuming no exercise of the

underwriters’ option to purchase additional shares). Similarly, an increase or decrease of one million shares of Class A common stock sold in this offering by us would increase or decrease, as applicable, our net proceeds, after deducting the underwriting discount and estimated offering expenses payable by us, by $ million, based on an assumed initial public offering price of $ per share, which is the midpoint of the price range set forth on the cover of this prospectus.

(2)	For a description of our debt, see “Description of Material Indebtedness.”

(3)

The Company intends to use a portion of the proceeds from this offering to redeem any shares of Series D Preferred Stock outstanding. See “Use of Proceeds.” To the extent the proceeds of this offering are insufficient to redeem the total aggregate principal amount of Series D Preferred Stock outstanding, the Company intends to use cash on hand to fully redeem the total aggregate principal amount of Series D Preferred Stock outstanding.

(4)	Represents pre-Transaction Class A common stock issued and outstanding prior to this offering.

DILUTION

If you invest in our Class A common stock in this offering, your ownership interest will be immediately diluted to the extent of the difference between the initial public offering price per share of our Class A common stock and the pro forma net tangible book value per share of our Class A common stock upon the consummation of this offering. Dilution results from the fact that the per share offering price of our Class A common stock is in excess of the pro forma net tangible book value per share attributable to the Class A common stock held by the existing equity holders.

The Continuing Equity Owners will own OpCo Interests after the Transactions. Because the Continuing Equity Owners do not have any right to receive distributions or dividends from us with respect to any Class B common stock or OpCo Interests held by them, we have presented dilution in pro forma net tangible book value per share both before and after this offering assuming that all of the holders of OpCo Interests (other than us) had their OpCo Interests redeemed or exchanged for newly-issued shares of Class A common stock on a one-for-one basis (rather than for cash) and the transfer to us and cancellation for no consideration of all of their shares of Class B common stock (which are not entitled to receive distributions or dividends, whether cash or stock from us). In order to more meaningfully present the dilutive impact on the investors in this offering. We refer to the assumed redemption or exchange of all OpCo Interests for shares of Class A common stock as described in the previous sentence as the “Assumed Redemption.”

Our actual net tangible book value as of , 2026 was approximately $ , or $ per share of Class A common stock on a fully diluted basis. Actual net tangible book value represents the amount of total tangible assets less total liabilities, and actual net tangible book value per share represents actual net tangible book value divided by the number of shares of Class A common stock outstanding as of .

Our pro forma net tangible book value as of , 2026 was approximately $ , or $ per share of Class A common stock on a fully diluted basis. Pro forma net tangible book value represents the amount of total tangible assets less total liabilities, and pro forma net tangible book value per share represents pro forma net tangible book value divided by the number of shares of Class A common stock outstanding after giving effect to the Transactions.

After giving effect to (i) the Transactions, (ii) the sale of shares of Class A common stock in this offering at the assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover of this prospectus) and (iii) the application of the net proceeds from this offering as described in “Use of Proceeds,” our pro forma as adjusted net tangible book value as of , 2026 would have been $ , or $ per share of Class A common stock. This amount represents an immediate increase in pro forma as adjusted net tangible book value of $ per share of Class A common stock to our existing equity holders and an immediate dilution in pro forma as adjusted net tangible book value of $ per share of Class A common stock to new investors in this offering.

The following table illustrates this dilution on a per share of Class A common stock basis given the assumptions above:


Assumed initial public offering price per share		$
Pro forma net tangible book value per share as of , 2026		$
Increase in pro forma net tangible book value per share attributable to new investors		$
Pro forma as adjusted net tangible book value per share after this offering		$
Dilution in net tangible book value per share to new investors in this offering		$

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share, which is the midpoint of the estimated price range set forth on the cover page of this prospectus, would increase (decrease) the pro forma net tangible book value per share after this offering by $ and dilution per share to new Class A common stock investors in this offering by $ assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discount.

If the underwriters exercise in full their option to purchase additional shares of Class A common stock, the pro forma net tangible book value after the offering per share, the pro forma net tangible book value per share to existing stockholders and the dilution in pro forma net tangible book value to new investors would be unchanged, in each case assuming an initial public offering price of $ per share, which is the midpoint of the estimated price range set forth on the cover page of this prospectus.

The following table summarizes, as of December 31, 2025, after giving effect to the Transactions (including this offering and proposed use of proceeds) and the Assumed Redemption, the number of shares of Class A common stock purchased from us, the total consideration paid, or to be paid, to us and the average price per share paid, or to be paid, by Continuing Equity Owners and by the new investors. The calculation below is based on an assumed initial public offering price of $ per share, which is the midpoint of the estimated price range set forth on the cover page of this prospectus, before deducting the underwriting discount.


	Shares Purchased				Total Consideration				Average Price Per Share
	Number	Percent			Amount	Percent			Average Price Per Share
Continuing Equity Owners				%	$			%	$
Investors in this offering									$

Total			100.0	%	$		100.0	%

Each $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) the total consideration paid by new investors and the total consideration paid by all stockholders by $ , assuming the number of shares offered by us remains the same and after deducting the underwriting discount.

Except as otherwise indicated, the discussion and the tables above assume no exercise of the underwriters’ option to purchase additional shares of Class A common stock. The number of shares of our Class A common stock outstanding after this offering as shown in the tables above is based on the number of shares outstanding as of December 31, 2025, after giving effect to the Transactions and the Assumed Redemption, and excludes shares of Class A common stock reserved for issuance under the 2026 Plan, including approximately shares of Class A common stock issuable pursuant to the settlement of restricted stock units which we will grant to certain of our directors, executive officers and other employees in connection with this offering. See “Executive Compensation.”

To the extent any of these restricted stock units settle, there will be further dilution to new investors. To the extent all of such outstanding restricted stock units had vested in full and settled as of December 31, 2025, the pro forma net tangible book value per share after this offering would be $ and total dilution per share to new investors would be $ .

If the underwriters exercise in full their option to purchase additional shares of Class A common stock:

•

the percentage of shares of Class A common stock held by the Continuing Equity Owners will decrease to approximately % of the total number of shares of our Class A common stock outstanding after this offering; and

•

the number of shares of Class A common stock held by new investors in this offering will increase to , or approximately % of the total number of shares of our Class A common stock outstanding after this offering.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED FINANCIAL STATEMENTS

The following unaudited pro forma condensed consolidated combined financial statements (the “pro forma financial statements”) present the historical consolidated financial statements of the Company, and the historical financial statements of PHX, adjusted to give effect to the PHX Acquisition. Additionally, the pro forma financial statements include adjustments associated with the Three Rivers Royalty Acquisition completed by WhiteHawk prior to the PHX Acquisition. On March 31, 2025, the Company purchased mineral and royalty interests in the Marcellus Shale from the TRR Seller. On June 23, 2025, WH Acquisition Corp. and Merger Sub closed on the PHX Merger Agreement and WH Acquisition Corp. fully acquired all of PHX, with PHX continuing as the surviving entity and a wholly owned indirect subsidiary of the Company.

The unaudited pro forma condensed consolidated combined balance sheet gives effect to the Transactions as if they had occurred on December 31, 2025. The PHX Acquisition and Three Rivers Royalty Acquisition are reflected in the historical consolidated balance sheet of WhiteHawk as of December 31, 2025, and, as such, no pro forma adjustments are made for such transactions in the unaudited pro forma condensed consolidated combined balance sheet. The unaudited pro forma condensed consolidated combined statement of operations for the year ended December 31, 2025 gives effect to the PHX Acquisition, the Three Rivers Royalty Acquisition and the Transactions as if each had occurred on January 1, 2025 (the “assumed date”). The pro forma financial statements contain certain reclassification adjustments to (i) conform the historical PHX financial statement presentation to the Company’s financial statement presentation and (ii) conform certain of the Company’s historical amounts to PHX’s financial statement presentation.

The unaudited 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 assumptions set forth in the notes to the unaudited pro forma financial statements. The pro forma financial statements have been adjusted to include transaction accounting adjustments in accordance with GAAP, linking the effects of the PHX Acquisition and the Three Rivers Royalty Acquisition and the adjustments to the PHX historical financial statements and the TRR Seller consolidated carve-out financial statement presentation to the historical consolidated financial statements of the Company. The Company has finalized purchase accounting for the PHX and TRR Seller acquisitions and conformed their accounting policies to those of the Company, and the accompanying unaudited pro forma condensed combined financial information reflects the final purchase price allocations recorded in the Company’s audited consolidated financial statements for the year ended December 31, 2025, with only transaction accounting adjustments presented. The pro forma financial statements and related notes are presented for illustrative purposes only and should not be relied upon as an indication of the financial condition or the operating results that the Company would have achieved if the PHX Acquisition and the Three Rivers Royalty Acquisition had taken place on the assumed date.

The pro forma financial statements do not reflect future events that may have occurred after the consummation of the PHX Acquisition and the Three Rivers Royalty Acquisition, including, but not limited to, the anticipated realization of ongoing savings from potential operating efficiencies, asset dispositions, cost savings or economies of scale that may be achieved with respect to the combined operations. As a result, future results may vary significantly from the results reflected in the pro forma financial statements and should not be relied on as an indication of the Company’s post-combination future results.

Unaudited Pro Forma Condensed Consolidated Combined Balance Sheet

As of December 31, 2025


	Historical
	WhiteHawk Income Corporation			Transaction Adjustments	Pro Forma Combined
	(As Restated)
	(in thousands, except par value and share amounts)
Assets:
Current assets:
Cash and cash equivalents	$	28,989			$
Accounts receivable		10,176
Short-term derivative receivable		5,349
Other current assets		1,410

Total current assets		45,924

Natural gas and oil mineral interests, net		460,586
Other property and equipment, net		275
Other assets		353

Total assets	$	507,138			$


Liabilities, mezzanine equity and shareholders’ equity:
Current liabilities:
Accounts payable	$	1,177			$
Accrued liabilities		1,158
Accrued dividends		7,516
Operating lease liability, current portion		176
Senior notes, current portion		6,275

Total current liabilities		16,302

Long-term debt, net of unamortized debt issuance costs and current portion		227,985
Deferred tax liability		21,329
Asset retirement obligation		316
Operating lease liability, net of current portion		121
Long-term derivative liability		4,669

Total liabilities		270,722

Commitments and contingencies
Mezzanine equity:
Series B Preferred stock, $0.0001 par value; 400,000 shares authorized; 35,524 shares issued and outstanding on a historical and pro forma basis, respectively		27,662
Shareholders’ equity:
Class A common stock, $0.0001 par value; 7,000,000 shares authorized; 6,518,383 shares issued and outstanding on a historical basis and 250,000,000 shares authorized: shares issued and outstanding on a pro forma basis		—
Class T common stock, $0.0001 par value; 100,000 shares authorized; 66,830 and shares issued and outstanding on a historical and pro forma basis, respectively		—
Class I common stock, $0.0001 par value; 9,100,000 shares authorized; 8,050,883 and shares issued and outstanding on a historical and pro forma basis, respectively		—
Class B common stock, $0.0001 par value, 100,000,000 shares authorized; shares issued and outstanding on a pro forma basis		—
Additional paid in capital		223,900
Non-controlling interests		—
Retained earnings (accumulated deficit)		(15,146	)

Total shareholders’ equity		208,754

Total liabilities, mezzanine equity and shareholders’ equity	$	507,138			$

Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations

For the Year Ended December 31, 2025


	Historical								Historical
	WhiteHawk Income Corporation			Three Rivers Royalty Adjustments		As Adjusted for TRR Acquisition			PHX Minerals			PHX Adjustments			As Adjusted for TRR Acquisition and PHX Acquisition			Transaction Adjustments	Pro Forma Combined
	(As Restated)
Revenues:					A					B
Royalty revenue	$	50,075		$	5,616	$	55,691		$	19,569		$	(3,421	)	$	71,839			$
Gain (loss) on commodity derivative instruments		16,648			—		16,648			(596	)		—			16,052
Lease bonus revenue		872			—		872			471			—			1,343

Total revenue		67,595			5,616		73,211			19,444			(3,421	)		89,234

Operating expenses:
Lease operating expenses		—			—		—			560	C		(560	)		—
Transportation, gathering and marketing		—			—		—			2,138	C		(2,138	)		—
Production and ad valorem taxes		—			—		—			723	C		(723	)		—
General and administrative		16,585			—		16,585			10,854			—			27,439
Management fees		9,966			—		9,966	E		—			—			9,966
Depletion, depreciation and accretion		24,237			—		24,237			4,907	D		7,307			36,451

Total operating expenses		50,788			—		50,788			19,182			3,886			73,856

Operating income (loss)		16,807			5,616		22,423			262			(7,307	)		15,378

Other expense:
Loss on extinguishment of debt		3,839			—		3,839			—			—			3,839
Loss (gain) on sale of assets		123			—		123			(6,429	)		—			(6,306	)
Interest expense, net		19,070			—		19,070			659			—			19,729

Income (loss) before income taxes		(6,225	)		5,616		(609	)		6,032			(7,307	)		(1,884	)

Provision for (benefit from) income taxes		(2,640	)		—		(2,640	)		1,297			—			(1,343	)

Net income (loss)		(3,585	)		5,616		2,031			4,735			(7,307	)		(541	)
Net income (loss) attributable to non-controlling interests		—			—		—			—			—			—

Net income (loss) attributable to common shareholders	$	(3,585	)	$	5,616	$	2,031		$	4,735		$	(7,307	)	$	(541	)		$

Earnings (loss) per common share:
Common shares—basic and diluted	$	(1.30	)																$
Weighted average number of shares outstanding:
Common shares—basic and diluted		8,378

Notes to unaudited pro forma condensed consolidated combined financial statements

1. Basis of Presentation, the Offering and Reorganization

The pro forma financial statements have been derived from the historical financial statements of WhiteHawk (in the case of financial information as of and for the year ended December 31, 2025 as restated in the Restatement). The unaudited pro forma condensed consolidated combined balance sheet gives effect to the Transactions as if they had occurred on December 31, 2025. The PHX Acquisition and Three Rivers Royalty Acquisition are reflected in the historical consolidated balance sheet of WhiteHawk as of December 31, 2025, and, as such no pro forma adjustments are made for such transactions in the unaudited pro forma condensed combined balance sheet. The unaudited pro forma condensed consolidated combined statement of operations for the year ended December 31, 2025 gives effect to the PHX Acquisition, the Three Rivers Royalty Acquisition and the Transactions as if each had occurred on January 1, 2025.

The pro forma financial statements reflect pro forma adjustments that are based on available information and certain assumptions that management believes are reasonable. However, actual results may differ from those reflected in these statements. In management’s opinion, all adjustments known to date that are necessary to present fairly the pro forma information have been made. The pro forma financial statements do not purport to represent what WhiteHawk’s post-combination financial position or results of operations would have been if the transactions had actually occurred on the dates indicated above, nor are they indicative of the Company’s post-combination future financial position or results of operations.

These pro forma financial statements should be read in conjunction with the historical financial statements, and related notes thereto, of WhiteHawk, PHX and TRR for the periods presented, which are included or incorporated by reference in this Registration Statement.

Corporate Reorganization & Offering

In connection with the consummation of the offering, we will consummate the Transactions. We will amend and restate our certificate of incorporation to, among other things, change our name to “WhiteHawk Minerals Corp.”; effect the Common Stock Reclassification; adjust our authorized capital stock to 250,000,000 shares of Class A common stock, 100,000,000 shares of Class B common stock and 10,000,000 shares of preferred stock, each par value $0.0001 per share; authorize our board of directors to establish and fix the terms of one or more series of preferred stock; and create Class B common stock in connection with our anticipated Up-C structure, to be issued to holders of OpCo Interests, with each share entitled to one vote and no economic rights.

WhiteHawk OpCo will enter into the OpCo Agreement to, among other things, appoint OP GP as sole general partner with authority to manage WhiteHawk OpCo’s business and affairs; authorize the issuance of OpCo Interests to us in exchange for the offering proceeds; provide the Continuing Equity Owners with the right to redeem their OpCo Interests for, at our election (determined solely by our disinterested independent directors), cash or newly-issued shares of Class A common stock on a one-for-one basis (subject to customary adjustments), with a corresponding number of shares of Class B common stock automatically transferred to us and canceled; and provide for tax distributions and allocations of income, gain, loss, deduction and credit among holders of OpCo Interests. We will enter into the Registration Rights Agreement with certain of our Continuing Equity Owners, as further described in “Certain Relationships and Related Person Transactions.”

We will issue shares of our Class A common stock to the purchasers in this offering (or shares if the underwriters exercise in full their option to purchase additional shares) at an assumed initial public offering price of

$ per share (the midpoint of the estimated price range set forth on the cover page of this prospectus), less the underwriting discount, for net proceeds of approximately $ million (or approximately $ million if the underwriters exercise in full their option to purchase additional shares), which we will use to purchase newly issued OpCo Interests for approximately $ million directly from WhiteHawk OpCo. Immediately following the consummation of the Transactions (including this offering), we will be a holding company whose principal asset will consist of OpCo Interests acquired directly from WhiteHawk OpCo. As the sole member of OP GP, we will control the business and affairs of WhiteHawk OpCo. We will own, directly or indirectly, OpCo Interests representing approximately % of the economic interest in WhiteHawk OpCo (or OpCo Interests representing approximately % if the underwriters exercise in full their option to purchase additional shares). The Continuing Equity Owners will own OpCo Interests representing approximately % of the economic interest in WhiteHawk OpCo (or approximately % if the underwriters exercise in full their option to purchase additional shares), and shares of our Class B common stock representing approximately % of the combined voting power of all of our common stock (or shares representing approximately % if the underwriters exercise in full their option to purchase additional shares).

The purchasers in this offering will own shares of our Class A common stock (or shares if the underwriters exercise in full their option to purchase additional shares), representing approximately % of the combined voting power and % of the economic interest in us (or approximately % if the underwriters exercise in full their option to purchase additional shares), and through our ownership of OpCo Interests, indirectly approximately % of the economic interest in WhiteHawk OpCo (or approximately % if the underwriters exercise in full their option to purchase additional shares).

2. Unaudited Pro Forma Condensed Consolidated Combined Balance Sheet

Transaction Adjustments

The unaudited pro forma condensed consolidated combined balance sheet as of December 31, 2025 reflects the historical consolidated balance sheet of WhiteHawk, which already includes the effects of the PHX Acquisition and Three Rivers Royalty Acquisition. Accordingly, no pro forma adjustments are presented for these transactions in the balance sheet. Transaction accounting adjustments related to the Transactions will be included in a subsequent amendment to this registration statement.

3. Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations

Three Rivers Royalty Acquisition Adjustments

Reflects natural gas and oil operations of properties acquired in the Three Rivers Royalty Transaction prior to the effective date of the transaction.

PHX Adjustments

Reflects combination of the historical statement of operations of PHX for the period January 1, 2025 through March 31, 2025 and the PHX Minerals Stub Period results of operations for the stub period between April 1, 2025 through June 23, 2025 (date of acquisition). A reconciliation of the adjustments is below (in thousands):


	PHX Minerals Historical			PHX Minerals Stub Period		Adjusted PHX Minerals
Revenues:
Natural gas, oil and NGL sales	$	10,433		$	9,135	$	19,569
Gain (loss) on commodity derivative instruments		(3,163	)		2,568		(596	)
Lease bonus revenue		328			143		471

Total revenue		7,598			11,846		19,444


	PHX Minerals Historical			PHX Minerals Stub Period		Adjusted PHX Minerals
Operating expenses:
Lease operating expenses		274			286		560
Transportation, gathering and marketing		1,104			1,034		2,138
Production and ad valorem taxes		423			301		723
Depreciation, depletion and amortization		2,430			2,477		4,907
Interest expense		452			207		659
General and administrative		3,754			7,100		10,854
Losses (gain) on asset sales and other		(6,520	)		90		(6,429	)

Total operating expenses		1,917			11,495		13,412

Income (loss) before provision for income taxes		5,681			351		6,032

Provision for income taxes		1,297			—		1,297

Net income	$	4,384		$	351	$	4,735

Reflects a pro forma adjustment to reclassify lease operating expenses, transportation, gathering and marketing, and production and ad valorem taxes to conform to WhiteHawk’s presentation.

Reflects the pro forma impact to depletion expense associated with the change in fair value adjustment to oil and gas properties as a result of the PHX Acquisition. Pro forma depletion expense was calculated on a consolidated basis as though all such properties were owned for the entire period. This number was then offset by the historical depletion expense related to PHX Minerals. The adjustment under Transaction Adjustments was calculated using the units-of-production method under the successful efforts method of accounting (in thousands):


For the year ended December 31, 2025
Depletion expense related to the fair value of oil and gas properties of PHX	$	12,214
Less PHX historical depletion expense		4,907

Transaction Adjustments to depletion expense	$	7,307

Reflects the management fees expense of WhiteHawk that were paid as compensation for services rendered in the management of the Company. The management fee expenses represent the charge for managing the Company and did not include general and administrative expenses related to operating the business. While a pro forma adjustment has not been made to eliminate the management fees, the Company will no longer incur any management fees after completion of the Transaction.

Transaction adjustments

Transaction accounting adjustments related to the Transactions will be included in a subsequent amendment to this registration statement.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Summary—Summary Historical and Pro Forma Financial Data” and the accompanying financial statements and related notes included 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. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas, NGLs and oil, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not give effect to the transactions described in “Corporate Reorganization, the PHX Acquisition or the Three Rivers Royalty Acquisition.”

Overview

We are focused on being the premier natural gas mineral and royalty business in the United States. We are committed to delivering cash flow and total returns to our investors through the disciplined acquisition, active management and ownership of high-quality mineral and royalty interests. Our assets are concentrated in the Marcellus and Haynesville Shales, which are located in the Appalachian and Haynesville Basins, among the most productive and lowest-cost natural gas basins in the United States. Upon completion of the offering, we will own the largest, high-quality publicly traded natural gas mineral portfolio in the United States.⁴⁷ As a mineral and royalty business, we do not pay any drilling-related capital expenditures and only minimal operating expenses on our properties. This results in a high-margin business and allows us to distribute a meaningful portion of our cash flow to investors, while providing them with potential for significant capital appreciation over time.

Market Conditions and Operational Trends

How We Evaluate Our Operations

We use a variety of operational and financial measures to assess our operations. Among the measures considered by management are the following:

•

volumes of natural gas, NGLs and oil produced;

⁴⁷	Based upon management’s review of public filings with the SEC, excluding those companies which either derive a majority of their revenue from oil or are oil and NGL weighted in production.

•

current activity trends including (rigs, producing wells, WIPs, permits and other locations); and

•

commodity prices and hedging.

Volumes of Natural Gas, NGLs and Oil Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various resource plays that comprise our portfolio of properties. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Current Activity Trends (Rigs, Producing Wells, WIPs, Permits and Other Locations)

In order to track and assess the performance of our assets, we monitor and analyze the number of rigs currently drilling and in close proximity to our properties. We also constantly monitor the number of producing wells, WIPs, permits and other locations that are applicable to our mineral and royalty interests. This analysis provides us with line of sight to near-, medium- and long-term potential production from the various resource plays that comprise our asset base. Our engineering and land teams employ a rigorous, data-driven technical process to track each well through its full lifecycle—from other locations, to permit, to drilling, to production—ensuring that every well is properly classified, accurately paid and fully captured in our forecasting.

Commodity Prices and Hedging

Commodity prices have historically been volatile and may continue to be volatile in the future. Lower prices not only decrease our revenues, but also potentially the amount of natural gas, NGLs and oil that our operators can produce economically. The prices we receive for natural gas, NGLs and oil are determined by factors affecting global and regional supply and demand dynamics, such as economic and geopolitical conditions, production levels, availability of transportation, weather cycles and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials.

Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.

Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas that is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.

NGLs. NGLs pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.

Oil. The majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil-pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will

result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur.

Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

Hedging

Our ongoing operations expose us to changes in the market price for natural gas assets. To mitigate the inherent commodity price risk associated with its operations, we use natural gas commodity derivative instruments for a substantial portion of our expected natural gas volumes. The vast majority of our hedge contracts are fixed price swaps, though from time to time, such instruments may also include costless collars and other contractual arrangements. In addition, we hedge basis exposure through basis swaps and similar instruments to manage the differential between the indices and locations at which we price our physical sales and those underlying our financial hedges. We enter into natural gas derivative contracts that contain netting arrangements with each counterparty, and we do not enter into derivative instruments for speculative purposes. For further discussion, see “Note 4—Commodity Derivative Financial Instruments” to our consolidated financial statements included elsewhere in this prospectus.

As of December 31, 2025, our open derivative contracts primarily consisted of fixed-price swap natural gas and oil contracts as well as natural gas costless collar contracts. A fixed-price swap contract between the Company and a counterparty specifies a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. A costless collar contract between the Company and the counterparty specifies a floor and a ceiling commodity price over a specified period for a contracted volume. We have not designated any of our contracts as fair value or cash flow derivatives; accordingly, the changes in fair value of the contracts are included in the consolidated statements of operations in the period of the change. All derivative gains and losses from our derivative contracts have been recognized in revenue in our accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in our consolidated balance sheets as of December 31, 2025.

Our natural gas fixed price swap transactions and costless collar transactions are settled based upon the first of the month pricing, which settles three business days prior to the first day of the calendar month of the contract period. Payment for natural gas fixed price swap contracts occurs in the month of the contract period.

We also have oil fixed price swap transactions which are settled based upon the average daily prices of the calendar month of the contract period. Payment for oil fixed price swap contracts occurs in the succeeding month.

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties that may adversely impact the fair value of our commodity derivative assets. While we do not require contract counterparties to post collateral, we do evaluate the credit standing on each counterparty as deemed appropriate. The evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of December 31, 2025, we had one counterparty, which is rated Baa2 or better by Moody’s. For additional information, see “Note 4—Commodity Derivative Financial Instruments” to our consolidated financial statements included elsewhere in this prospectus.

Sources of Our Revenue

A significant portion of our revenues are derived from the mineral royalty payments we receive from our operators based on the sale of natural gas, NGLs and oil produced from our mineral interests. Royalty revenues may vary significantly from period to period as a result of changes in volumes of production sold by our

operators, production mix and commodity prices. A portion of our revenue also comes from other royalty and lease bonus payments. Other royalty revenue is comprised of flat rate, shut-in and gas storage payments. Lease bonus revenue includes cash payments received at the beginning of a new lease and extension payments on current leases.

The following table presents the breakdown of our revenues for the following periods:


	Year Ended December 31,
	2025			2024
Royalty revenue:
Natural gas sales		82	%		81	%
Natural gas liquids sales		8	%		11	%
Oil		9	%		1	%
Lease bonus		1	%		7	%

Total		100	%		100	%

Principal Components of Our Cost Structure

The following is a description of the principal components of our cost structure. Importantly, as an owner of mineral interests, we are not obligated to fund drilling and completion capital expenditures to bring a well on line, lease operating expenses to produce our natural gas, NGLs and oil or the plugging and abandonment costs at the end of a well’s economic life. All of the aforementioned costs are borne entirely by the E&P operator that has leased our mineral interests.

Depletion

Depletion is the systematic expensing of the capitalized costs incurred to acquire oil and natural gas mineral and royalty properties. We use the successful efforts cost method of accounting, and, as such, all costs associated with successful acquisitions are capitalized and reasonably aggregated and depleted based on a common geological structural feature. Costs associated with unsuccessful acquisitions are expensed. Depletion is the expense recorded based on the cost basis of our properties and the volume of hydrocarbons extracted during each respective period, calculated on a units-of-production basis. Estimates of proved reserves are a major component of our calculation of depletion. We adjust our depletion rates in the fourth quarter of each year based upon the year-end reserve report prepared by Cawley, Gillespie & Associates, Inc., our independent petroleum engineers, unless circumstances indicate that there has been a significant change in reserves or costs.

General and Administrative

General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our personnel costs of maintaining our office locations, costs of managing our properties, audit and other fees for professional services and legal compliance. As a result of becoming a public company, we anticipate incurring incremental G&A expenses as a result of operating as a publicly traded company. These incremental public company G&A expenses include expenses associated with SEC reporting requirements, including annual and quarterly reports, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our Class A common stock on the NYSE, increased independent auditor fees, increased independent reserve engineer fees, increased legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation. These incremental G&A expenses are not reflected in our historical financial statements included elsewhere in this prospectus.

Interest Expense

We have financed a portion of our working capital requirements and acquisitions with borrowings under our Senior Notes. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our

financing decisions. We reflect interest paid to the lenders under our Senior Notes and amortization of debt issuance costs in interest expense in our consolidated statements of operations.

Income Tax Expense

As a corporation, we are subject to U.S. federal income taxes. We are also subject to the Texas margin tax and certain other state income taxes.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations may not be comparable to the historical results of operations of our predecessor for the periods presented, primarily for the reasons described below.

Corporate Reorganization

To effectuate the Internalization, the Contribution Agreement will be entered into by the parties thereto, pursuant to which WhiteHawk OpCo will acquire all outstanding equity interests in ManagementCo from the Management Owners in exchange for OpCo Interests and shares of Class B common stock; as a result, ManagementCo will become a wholly owned subsidiary of WhiteHawk OpCo and we will become internally managed. We will issue shares of our Class A common stock to the purchasers in this offering (or shares if the underwriters exercise in full their option to purchase additional shares) at an assumed initial public offering price of $ per share (the midpoint of the estimated price range set forth on the cover page of this prospectus), less the underwriting discount, for net proceeds of approximately $ million (or approximately $ million if the underwriters exercise in full their option to purchase additional shares), which we will use to purchase newly issued OpCo Interests for approximately $ million directly from WhiteHawk OpCo.

Immediately following the consummation of the Transactions (including this offering), we will be a holding company whose principal asset will consist of OpCo Interests acquired directly from WhiteHawk OpCo. As the sole member of OP GP, we will control the business and affairs of WhiteHawk OpCo. We will own, directly or indirectly, OpCo Interests representing approximately % of the economic interest in WhiteHawk OpCo (or OpCo Interests representing approximately % if the underwriters exercise in full their option to purchase additional shares). The Continuing Equity Owners will own OpCo Interests representing approximately % of the economic interest in WhiteHawk OpCo (or approximately % if the underwriters exercise in full their option to purchase additional shares), and shares of our Class B common stock representing

approximately % of the combined voting power of all of our common stock (or shares representing approximately % if the underwriters exercise in full their option to purchase additional shares). The purchasers in this offering will own shares of our Class A common stock (or shares if the underwriters exercise in full their option to purchase additional shares), representing approximately % of the combined voting power and % of the economic interest in us (or approximately % if the underwriters exercise in full their option to purchase additional shares), and through our ownership of OpCo Interests, indirectly approximately % of the economic interest in WhiteHawk OpCo (or approximately % if the underwriters exercise in full their option to purchase additional shares).

As a result of the Internalization, we expect a meaningful reduction in our operating expenses due to the elimination of management fees and other costs paid to ManagementCo.

Acquisitions

Our financial statements for the year ended December 31, 2025 and 2024 do not include the results of operations for the Three Rivers Royalty Acquisition or the PHX Acquisition prior to the respective dates of acquisition and our financial statements for the year ended December 31, 2024 do not include the assets acquired in the Three Rivers Royalty Acquisition and the PHX Acquisition. As a result, our financial results do not give an accurate indication of what the actual results would have been if such acquisitions had been completed at the beginning of the periods presented or of what our future results are likely to be. For additional discussion of the Three Rivers Royalty Acquisition and the PHX Acquisition, please refer to “Unaudited Pro Forma Condensed Consolidated Combined Financial Information.” Prior to the Three Rivers Royalty Acquisition in which we acquired the remaining 50% undivided interest in the natural gas mineral assets of the TRR Seller, we previously acquired an aggregate 50% undivided interest in the natural gas mineral assets of the TRR Seller which are reflected in our financial statements for the years ended December 31, 2025 and 2024. See “Business—Our Acquisition History.”

Acquisitions are an important part of our growth strategy, and we plan to pursue potential accretive acquisitions of additional natural gas-weighted mineral and royalty interests. We believe we will be well positioned to acquire such assets and, should such opportunities arise, identifying and executing acquisitions will be a key part of our strategy. However, if we are unable to make acquisitions on economically accretive terms, our future growth may be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to pay dividends to stockholders in the short term.

Public Company Expenses

Following the closing of this offering, we anticipate incurring incremental G&A expenses as a result of operating as a publicly traded company, such as expenses associated with SEC reporting requirements, including annual and quarterly reports, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our Class A common stock on the NYSE, increased independent auditor fees, increased independent reserve engineer fees, increased legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental G&A expenses are not reflected in our historical financial statements. Additionally, we may hire additional employees, including accounting, engineering, land and legal personnel, in order to comply with requirements of being a publicly traded company.

Management Fees

The Company incurred and paid fees under the amended and restated investment management agreement, dated as of October 3, 2025 (the “Investment Management Agreement”), with WhiteHawk Management , an affiliate of WhiteHawk Energy, LLC, of which Daniel Herz is a managing member. Fees incurred under the Investment Management Agreement for the years ended December 31, 2025 and 2024 totaled approximately $10.0 million and $4.7 million, respectively. As noted above, as a result of the Internalization, we expect a meaningful reduction in our operating expenses due to the elimination of management fees and other costs paid to ManagementCo.

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Restatement of Prior Period Financial Statements

As discussed under the heading “Restatement,” we recently restated our previously issued consolidated financial statements and related notes for the year ended December 31, 2025, which restated financial statements are included elsewhere in this prospectus. Refer to Note 3 in the notes to the audited consolidated financial statements in this prospectus for additional information. The impact of the restatement is reflected in the “Results of Operations” section within this “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Results of Operations

Year Ended December 31, 2025 Compared to the Year Ended December 31, 2024

Consolidated Results

The following tables summarize our consolidated revenue and expenses and production data for the years ended December 31, 2025 and 2024:


	Years Ended December 31,					Variance
	2025		2024			Variance
	(As Restated)
	(dollars in thousands, except for realized prices)
Production:
Natural gas (Mcf)		16,586,178		7,370,198			9,215,980		125	%
NGLs (Bls)		210,677		74,350			136,327		183	%
Oil (Bbls)		87,970		3,750			84,220			*


Equivalents (Mcfe)⁽¹⁾		18,378,060		7,838,798			10,539,262		134	%
Equivalents per day (Mcfe / d)⁽¹⁾		50,351		21,417			28,934		135	%
Realized prices:
Natural gas (per Mcf)	$	2.94	$	1.85		$	1.09		59	%
NGLs (per Bbl)	$	21.94	$	25.50		$	(3.56	)	-14	%
Oil (per Bbl)	$	60.93	$	54.67		$	6.26		11	%
Equivalents (per Mcfe)	$	3.20	$	2.01		$	1.19		59	%
Average Realized Price After Effects of Derivative Settlements:
Natural gas (per Mcf)	$	3.45	$	3.04		$	0.41		13	%
Revenues:
Royalty revenue	$	50,075	$	12,702		$	37,373		294	%
Gain (loss) on commodity derivative instruments		16,648		(4,418	)		21,066		477	%
Lease bonus revenue		872		1,166			(294	)	-25	%

Total revenue		67,595		9,450			58,145		615	%

Operating expenses:
General and administrative		16,585		2,792			13,793		494	%
Management fees		9,966		4,681			5,285		113	%
Depletion, depreciation and accretion		24,237		10,827			13,410		124	%

Total operating expenses		50,788		18,300			32,488		178	%

Operating income (loss)		16,807		(8,850	)		25,627		-290	%
Other expense:
Loss on extinguishment of debt		3,839		359			3,480			*
Loss on sale of assets		123		—			123			*
Interest expense, net		19,070		3,939			15,131		384	%

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	Years Ended December 31,						Variance
	2025			2024			Variance
	(As Restated)
	(dollars in thousands, except for realized prices)
Total other expense		23,032			4,298			18,734		436	%

Income (loss) before income taxes		(6,225	)		(13,148	)		6,923		-53	%

Provision for (benefit from) income taxes		(2,640	)		(1,587	)		(1,053	)	66	%

Net income (loss)	$	(3,585	)	$	(11,561	)	$	7,976		-69	%

⁽¹⁾	Natural gas equivalents are calculated using a ratio of six thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs, based on approximate relative energy content. This ratio does not represent the current or historical price relationship between natural gas and oil or NGLs.

Revenue

Our consolidated revenues for the year ended December 31, 2025, increased $58.1 million or 615%, as compared to the year ended December 31, 2024. The increase in revenues was primarily due to an increase in natural gas, NGL and oil royalty revenue and an increase in revenue from our commodity derivatives, partially offset by a decrease in lease bonus revenue. The increase in royalty revenues was primarily due to an increase in our production volumes of 134% from the acquisitions of additional mineral and royalty interests.

Natural gas revenues for the year ended December 31, 2025, increased $35.1 million or 258%, compared to the year ended December 31, 2024. Natural gas production volumes increased 125% to 45,442 Mcf/day resulting in a $27.1 million increase in natural gas sales primarily due to acquisitions of additional mineral and royalty interests. Realized natural gas prices increased 59% to $2.94 per Mcf resulting in an increase in revenue of $10.0 million. The increase in revenue was partially offset by an increase in gathering, transportation and marketing expenses of $4.5 million.

NGLs revenues for the year ended December 31, 2025, increased $2.7 million, or 144%, compared to the year ended December 31, 2024. NGLs production volumes increased 183% to 577 BBls/day resulting in an approximately $3.0 million increase in NGLs sales. Realized NGLs prices decreased 14% to $21.94 per Bbl resulting in a decrease in revenue of approximately $0.5 million. The increase in NGL revenue was partially offset by an increase in gathering, transportation and marketing expenses of $0.3 million.

Oil revenues for the year ended December 31, 2025, increased $5.2 million, compared to the year ended December 31, 2024. Oil production volumes increased to 241 Bbl/day resulting in a $5.1 million increase in oil sales. Realized oil prices increased 11% to $60.93 per Bbl resulting in a increase in revenue of approximately $0.5 million. The increase in oil revenue was partially offset by an increase in gathering, transportation and marketing expenses of $0.7 million.

Commodity derivatives gains totaled $16.6 million for the year ended December 31, 2025, as compared to losses of $4.4 million for the year ended December 31, 2024. The increase of $21.1 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024 is due to changes in commodity prices.

Lease bonus revenue decreased, $0.3 million, or 25%, for the year ended December 31, 2025, as compared to the year ended December 31, 2024. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing.

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Operating expenses

General and administrative expenses for the year ended December 31, 2025, increased $13.8 million, or 494%, as compared to the year ended December 31, 2024. The increase was primarily attributable to an $8.2 million increase in legal and professional expenses related to acquisitions, a $4.5 million increase in employee and director expenses related to the growth of the Company including certain non-recurring acquisition related payments during 2025, $0.2 million increase in franchise taxes, a $0.3 million increase in travel related expenses, a $0.2 million increase in software expense and a $0.1 million increase in rent related expenses.

Management fees for the year ended December 31, 2025, increased $5.3 million, or 113%, compared to the year ended December 31, 2024. Management fees paid to WHIC Manager are calculated as a percentage of assets under management and a percentage of all distributions paid to the Company shareholders and each continue to increase as the Company continues to issue equity and make additional acquisitions.

Depletion, depreciation and accretion for the year ended December 31, 2025, increased $13.4 million, or 124%, compared to the year ended December 31, 2024. The increase was due to a 134% increase in year-over-year production volumes partially offset by a lower depletion rate, which decreased to $1.31 per Mcfe for the year ended December 31, 2025 from $1.38 per Mcfe for the year ended December 31, 2024.

Other Income and Expenses

Interest expense relates to interest incurred on borrowings under our various credit facilities. The increase for the year ended December 31, 2025, of $15.1 million, or 384%, compared to the year ended December 31, 2024 was primarily due to a higher average amount outstanding under our Senior Notes.

For the year ended December 31, 2025, losses on extinguishment of debt totaled $3.8 million. For the year ended December 31, 2024, losses on the extinguishment of debt totaled $0.4 million. During the year ended December 31, 2025, $3.8 million of previously capitalized deferred financing costs were written off when the Company amended and restated the Senior Notes. During the year ended December 31, 2024, $0.4 million of previously capitalized deferred financing costs were written off when the Company extinguished the Term Loan in September 2024 with proceeds received from the Senior Notes.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been from capital raised from third-party investors, cash flows from operations and proceeds from the issuance of our Senior Notes. Following the completion of this offering, we expect our primary sources of liquidity to be the proceeds retained from this offering, cash flows from operations, and proceeds from any future issuances of debt or equity securities. Future sources of liquidity may also include other credit facilities we may enter into in the future and/or additional issuances of debt or equity securities. Historically, our primary uses of cash have been for the acquisition of mineral and royalty interests, the reduction of outstanding debt balances and the payment of dividends, and we expect our primary uses of cash going forward to be for the acquisition of mineral and royalty interests, the reduction of outstanding debt balances and the payment of dividends. Our ability to generate cash is subject to several factors, some of which are beyond our control, including commodity prices and general economic, financial, legislative, regulatory and other factors. In addition, there can be no assurance that we will pay any dividends to holders of our Class A common stock, or as to the amount of any such dividends. See “Risk Factors—Risks Related to this Offering and Ownership of Our Class A Common Stock—We intend to pay regular dividends to our stockholders, but our ability to do so is subject to the discretion of our board of directors and may be limited by our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements, instruments governing our indebtedness and other factors and restrictions our board of directors deems relevant.”

We believe internally generated cash flows from operations and access to capital markets will provide us with sufficient liquidity and financial flexibility to meet our cash requirements, including normal operating needs, debt

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service obligations, our return of capital program, and capital expenditures, for at least the next 12 months and allow us to continue to execute our strategy of acquiring attractive mineral and royalty interests that will position us to grow our cash flows and return capital to our stockholders. As an owner of mineral and royalty interests, we incur the initial cost to acquire our interests but thereafter do not incur any drilling or completion capital expenditures, which are entirely borne by the E&P operators and the other working interest owners. As a result, our only capital expenditures are related to our acquisition of additional mineral and royalty interests, and we have no subsequent capital expenditure requirements related to acquired properties. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing and financing activities and our ability to integrate acquisitions. We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. Our ability to generate cash flow is subject to a number of factors, many of which are beyond our control, including commodity prices, weather and general economic, financial and competitive, legislative, regulatory and other factors. We believe our cash flows from operations will be sufficient to fund our operating expenses, debt service obligations, and dividend payments for the next 12 months without accessing the capital markets. However, if we require additional capital for acquisitions or other reasons, we may raise such capital through additional borrowings, asset sales, offerings of equity and debt securities or other means. If we are unable to obtain funds needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us. There can be no assurance that capital markets financing will be available on favorable terms, or at all.

As of December 31, 2025, our cash and cash equivalents was $29.0 million.

Cash Flows for the Year Ended December 31, 2025 Compared to the Year Ended December 31, 2024 (in thousands):


	For the Year Ended December 31,
	2025			2024
	(As Restated)
Net cash flows provided by (used in):
Operating activities	$	13,577		$	9,447
Investing activities		(309,958	)		(30,392	)
Financing activities		320,040			22,061

Operating Activities

Our operating cash flows are impacted by the variability in our revenues and operating expenses, as well as the timing of the related cash receipts and disbursements. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our E&P operators, as well as the timeliness and accuracy of payments from our E&P operators. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2025 were $13.6 million as compared to $9.4 million for the year ended December 31, 2024. The increase was primarily a result of the increase in our production of 134% to acquisitions and an increase of 59% in our realized prices.

Investing Activities

Cash flows used in investing activities totaled $310.0 million for the year ended December 31, 2025 as compared to $30.4 million for the year ended December 31, 2024, an increase of $279.6 million due to the variance in our acquisitions of oil and gas properties, net of purchase price adjustments.

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Financing activities

Cash flows provided by financing activities for the year ended December 31, 2025 totaled $320.0 million as compared to cash flows provided by financing activities of $22.1 million for the year ended December 31, 2024.

During the year ended December 31, 2025, cash flows provided by financing activities was primarily related to $172.7 million of proceeds from our Senior Notes, net of repayments and $248.1 million of proceeds raised from the issuance of common and preferred stock. This was partially offset by dividends of $19.5 million paid to common and preferred stockholders during the year ended December 31, 2025, $75.4 million of common and preferred stock redemptions and $5.8 million of deferred financing costs.

During the year ended December 31, 2024, cash flows provided by financing activities was primarily related $45.0 million of additional proceeds from our Senior Notes, net of repayments, and $18.1 million of proceeds raised from the issuance of common and preferred stock. This was partially offset by common and preferred stock redemptions of $25.5 million and dividends of $13.2 million paid to common and preferred stockholders during the year ended December 31, 2024.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates and operator credit risk as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates and operator credit risk. 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.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the crude oil, natural gas and NGLs production of our E&P operators, which affects the royalty payments we receive from our E&P operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for crude oil, natural gas and NGL production has been volatile historically and we expect this volatility to continue in the future. The prices that our E&P operators receive for production depend on many factors outside of our or their control.

A $0.10 per Mcf change in our realized natural gas price would have resulted in a $1.7 million change in our natural gas revenues for the year ended December 31, 2025. A $1.00 per Bbl change in NGLs and oil prices would have resulted in a $0.3 million change in our NGLs and oil revenues for the year ended December 31, 2025. Royalties on natural gas sales, NGL sales and oil contributed 83%, 8% and 9%, respectively, of our total royalty revenues for the year ended December 31, 2025.

We may enter into derivative instruments from time to time, such as collars, swaps and basis swaps, to partially mitigate the impact of commodity price volatility. These hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil, natural gas and NGL prices and provide increased certainty of cash flows related to certain of our acquisitions. However, these instruments provide only partial price protection against declines in oil, natural gas and NGL prices and may partially limit our potential gains from future increases in prices. Refer to “Note 4—Commodity Derivative Financial Instruments for further information.

Operator Credit Risk

Our principal exposures to credit risk are through receivables generated by the production activities of our operators. The inability or failure of our significant operators to meet their obligations to us or their insolvency or

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liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators is acceptable.

Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under the Senior Notes which bears interest at a floating rate. The average annual interest rate incurred on our borrowings under the Senior Notes during the year ended December 31, 2025 was 10.8%. We estimate that an increase of 1.0% in the average interest rate during the year ended December 31, 2025 would have resulted in an approximately $1.8 million increase in interest expense.

Critical Accounting Policies and Related Estimates

The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations.

We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the facts and circumstances at the time the estimates are made. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. There can be no assurance that actual results will not differ from those estimates and assumptions. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Changes in estimates are accounted for prospectively.

Our estimates and classification of natural gas and oil reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering, and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions. These factors and assumptions include historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil and estimates of the future net cash flows may vary substantially.

Any significant variance in the assumptions could materially affect the estimated quantity of reserves, which could affect the carrying value of our natural gas and oil properties and/or the rate of depletion related to natural gas and oil properties.

Gas and Oil Properties

We use the successful efforts method of accounting for natural gas and oil producing properties, as further defined under Accounting Standards Codification 932, Extractive Activities—Oil and Natural Gas. Under this

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method, costs to acquire mineral interests in natural gas and oil properties are capitalized. The costs of non-producing mineral interests and associated acquisition costs are capitalized as unproved properties pending the results of leasing efforts and drilling activities of E&P operators on our interests. As unproved properties are determined to have proved reserves, the related costs are transferred to proved gas and oil properties. Capitalized costs for proved natural gas and oil mineral interests are depleted on a unit-of-production basis over total proved reserves. For depletion of proved gas and oil properties, interests are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic conditions.

Impairment of Gas and Oil Properties

We evaluate our proved properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, we compare the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future net cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future net cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.

Unproved gas and oil properties are assessed periodically for impairment of value, and a loss is recognized at the time of impairment by charging capitalized costs to expense. Impairment is assessed based on when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Factors used in the assessment include, but are not limited to, commodity price outlooks, current and future operator activity, and analysis of recent mineral transactions in the surrounding area.

Crude Oil, Natural Gas and NGLs Reserve Quantities and Standardized Measure of Gas and Oil

Our estimates of natural gas, crude oil and NGLs reserves and associated future net cash flows are prepared or audited by our independent reservoir engineers. The SEC has defined proved reserves as the estimated quantities of gas and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating crude oil, natural gas and NGLs reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGLs reserves. Crude oil, natural gas and NGLs reserve engineering is a process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify positive or negative revisions of reserve estimates.

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Revenue Recognition

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas, oil, and natural gas liquids sales from third-party operators may not be received for 30 to 120 days after the date production is delivered. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded based upon our royalty interest. Where available, historical actual data is used to calculate volume estimates for wells operated by third parties. If historical actual data is not available for these wells, engineering estimates are used to calculate expected volumes. As such, estimated volumes utilized in period end royalty income accruals are subject to revision as additional actual data becomes available and such revisions may have a material impact on our results of operations and our royalty income receivables. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis. We record the differences between our estimates and the actual amounts received for royalties from third parties in the month that payment is received from the operator. We have existing internal controls for our royalty income estimation process and related accruals, but actual third-party royalty income in future periods could differ materially from estimated amounts. Identified differences between our accrued revenue estimates and actual revenue received historically have not been significant.

Natural gas, NGLs and oil revenues from our mineral and royalty interests are recognized when control transfers at the wellhead.

We also earn revenue related to lease bonuses by leasing our mineral interests to E&P operators. We recognize lease bonus revenue when the lease agreement has been executed and payment is determined to be collectible.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of Sarbanes-Oxley, 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 implementing Section 302 of Sarbanes-Oxley, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal control over financial reporting under Section 404 until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Notwithstanding that we are not currently required to make such a formal assessment, in the course of preparing our financial statements and building out our internal controls infrastructure, we have in the past identified, and may in the future identify, deficiencies in our internal control over financial reporting, including material weaknesses.

To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Material Weaknesses in Internal Control over Financial Reporting

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 in a timely basis.

In connection with the preparation of our unaudited consolidated financial statements for the three months ended March 31, 2026 and 2025, we identified material weaknesses in our internal control over financial reporting. The identified material weaknesses include (i) controls over the quarterly close and account reconciliations process

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related to the reconciliation of related party balances were not designed at a sufficient level of precision to prevent or detect material misstatements in a timely manner and (ii) controls over business combinations did not contain a control specific to the recording of post combination adjustments related to the business combination effective date.

Remediation steps are being taken to improve our internal control over financial reporting to address the underlying causes of the material weaknesses described above, including designing and implementing increased controls along with increasing oversight and review of controls. Specifically, we plan to institute new and enhanced controls to improve and formalize the level of precision applied to the review of our financial statements, including the development and documentation of detailed review procedures. As part of these planned control enhancements, we intend to establish documented protocols specifying the steps that our review process will entail, including the purpose of each schedule, the complexity of the underlying account(s), the specific items under review (e.g., footing errors, unexpected account balance fluctuations), the degree of judgment involved, and the source of reports and other data points used in the analysis. We also plan to introduce new documentation controls designed to ensure that sufficient supporting evidence exists to substantiate the amounts and balances included in our financial statements and to confirm that management review procedures were performed. We intend to continue evaluating and instituting additional controls and safeguards as necessary to fully remediate the identified material weaknesses.

While we believe that these efforts will improve our internal control over financial reporting, the implementation of these measures is ongoing and will require validation and testing of the design and operating effectiveness of internal controls over a sustained period of financial reporting cycles. If the steps we take do not remediate the material weaknesses in a timely manner, there could continue to be a reasonable possibility that these control deficiencies or others could result in a material misstatement of our annual or interim financial statements that would not be prevented or detected on a timely basis. If we are unable to successfully remediate our existing or any future material weaknesses, the accuracy of our financial reporting may be adversely affected, which could cause investors to lose confidence in our financial reporting and our share price may decline as a result.

Notwithstanding the identified material weaknesses, management believes that the financial statements and related financial information included in this prospectus fairly present, in all material respects, our balance sheets, statements of operations, statements of stockholders’ equity (deficit) and statements of cash flows as of and for the periods presented. We will continue to assess the effectiveness of our internal control over financial reporting and take steps to remediate the known material weaknesses expeditiously.

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BUSINESS

Our Company

WhiteHawk is focused on being the premier natural gas mineral and royalty business in the United States. We are committed to delivering cash flow and total returns to our investors through the disciplined acquisition, active management and ownership of high-quality mineral and royalty interests. Our assets are concentrated in the Marcellus and Haynesville Shales, which are located in the Appalachian and Haynesville Basins, which are among the most productive and lowest-cost U.S. natural gas basins.⁴⁸ Upon completion of the offering, we will own the largest, high-quality publicly traded natural gas mineral portfolio in the United States.⁴⁹ As a mineral and royalty business, we do not pay any drilling-related capital expenditures and only minimal operating expenses on our properties. This results in a high-margin business and allows us to distribute a meaningful portion of our cash flow to investors, while providing them with potential for significant capital appreciation over time.

As of December 31, 2025, our portfolio spans approximately 3.4 million gross DSU acres, including 1.6 million gross DSU acres across the Appalachian and Haynesville Basins and represents an economic interest in approximately 13%⁵⁰ of all natural gas produced in the United States as of December 31, 2025. Further, we have more than 10,900 producing wells and more than 8,000 remaining identified undeveloped locations as of December 31, 2025. The Appalachian and Haynesville Basins form the core of U.S. natural gas production and are among the most prolific energy-producing regions globally. If measured against sovereign nations, the Appalachian Basin would rank as the world’s second-largest natural gas producer, with daily production of approximately 33 Bcf/d, and the Haynesville Basin would rank eighth with daily production of approximately 13 Bcf/d.⁵¹ In 2025, the Appalachian and Haynesville Basins together accounted for more than 50%⁵² of total U.S. dry gas production, providing the foundation of domestic natural gas supply and export growth. Our mineral interests are concentrated in the core of these premier natural gas regions and offer long-term participation in two of the largest, most active and lowest-cost natural gas weighted basins in the United States.⁵³

WhiteHawk’s mineral interests are developed by many of the largest, most active and well-capitalized natural gas operators in the United States, including EQT (NYSE: EQT), Range Resources (NYSE: RRC), CNX Resources (NYSE: CNX), Antero Resources (NYSE: AR), Expand Energy (NASDAQ: EXE), Comstock Resources (NYSE: CRK) and Aethon Energy. In 2025, approximately 18%⁵⁴ of all wells drilled in the Appalachian and Haynesville Basins were located on acreage in which we hold royalty interests. Our significant footprint across both basins provides alignment and scale with these premier operators. In 2025, EQT was the largest natural gas producer in the Appalachian Basin, and Expand Energy was the largest producer in the Haynesville Basin.⁵⁵ In the same year, approximately 49% of EQT’s Appalachian production and 57% of Expand Energy’s Haynesville production were sourced from acreage in which we hold royalty interests.⁵⁶ Because our mineral interests are concentrated within these operators’ active and planned development areas, we can benefit directly from their scale, financial strength and efficiency. Our exposure to leading operators enables us to gain from their continuous development across commodity cycles and provides a resilient base for predictable cash flow growth.

Leveraging our scale and position alongside leading operators, we believe we are well positioned to capitalize on two powerful natural gas demand catalysts: AI driven electricity demand growth and expanding U.S. LNG exports. Natural gas remains the most reliable, scalable and cost-effective source of baseload power and

⁴⁸	EIA Short-Term Energy Outlook; Enverus Data.

⁴⁹	Based upon management’s review of public filings with the SEC, excluding those companies which either derive a majority of their revenue from oil or are oil and NGL weighted in production.

⁵⁰	Enverus Data.

⁵¹	World Energy Report.

⁵²	EIA Short-Term Energy Outlook.

⁵³	Enverus Data.

⁵⁴	Enverus Data.

⁵⁵	Enverus Data.

⁵⁶	Enverus Data.

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accounted for approximately 41%⁵⁷ of total U.S. electricity generation in 2025. The rapid buildout of AI and cloud-computing infrastructure is projected to create additional demand for natural gas-fired power generation, with a management-estimated 7.8 Bcf/d of total natural gas demand associated with new power plants expected to be constructed by 2031,⁵⁸ largely within WhiteHawk’s Appalachian Basin footprint. In addition to an increase in domestic demand, global demand for U.S. natural gas is expected to further accelerate through LNG export growth. The United States will nearly double its LNG export capacity from approximately 17 Bcf/d⁵⁹ in 2025 to nearly 34 Bcf/d by 2031⁶⁰ as European and Asian buyers seek to diversify supply and reduce exposure to higher regional benchmark prices. The Haynesville Basin’s proximity and pipeline connectivity to the Gulf Coast LNG corridor position our mineral interests to benefit directly from this expansion in export capacity and feed-gas demand. Together, accelerating power demand from AI and the continued buildout of LNG export capacity, inclusive of announced projects, are expected to drive a structural step-change in U.S. natural gas demand—driving roughly a 36%⁶¹ increase in combined demand by 2031 compared to 2025 levels. WhiteHawk believes it offers public investors direct equity exposure to the powerful tailwinds of AI-driven power demand and expanding U.S. LNG exports without drilling-related capital expenditures.

WhiteHawk is led by one of the most experienced and acquisitive management teams in the minerals and royalties sector. Collectively, our leadership has more than 125 years of industry experience and has completed over $31 billion of energy transactions across the upstream, midstream, and minerals and royalty value chain. Members of our team previously served as senior executives or founders of Atlas Energy (NYSE: ATLS), Atlas Pipeline Partners (NYSE: APL) and Falcon Minerals Corporation (NASDAQ: FLMN), each of which were successful public companies that generated substantial shareholder value through disciplined growth, accretive acquisitions and strategic monetizations.

Since its inception, WhiteHawk has completed eight large acquisitions, making it the most active acquirer of natural gas mineral and royalty properties in the United States.⁶² More importantly, these acquisitions have been highly accretive to shareholders and have resulted in approximately 36%⁶³ cash-on-cash return to our initial investors through 46 months of consecutive cash dividend payments, plus an additional 41% increase in shareholder value through three share dividends through January 1, 2026. We continue to execute a focused consolidation strategy in a fragmented market, targeting accretive acquisitions to expand scale, enhance returns and extend development visibility. Our ability to consistently source, evaluate and close accretive transactions ahead of broader market consolidation underscores WhiteHawk’s leadership as a focused, data-driven consolidator with a proven track record of value creation.

Our History

⁵⁷	EIA Electric Monthly.

⁵⁸	Assumes 1 gigawatt of capacity equates to 154 mmcf/d of natural gas demand.

⁵⁹	EIA Natural Gas Exports. Includes current operating and under construction projects only.

⁶⁰	EIA Electric Monthly.

⁶¹	EIA Natural Gas Monthly.

⁶²	Enverus Data.

⁶³	Reflects a cash-on-cash return to our initial investors whose share price did not include any selling commissions on investment. Returns to our initial investors whose share price included selling commissions on investment resulted in cash-on-cash returns of approximately 33%.

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point to acquire premium assets at compelling valuations. WhiteHawk was created to capitalize on this opportunity, bringing technical expertise, public market experience and fresh capital to a fragmented sector.

As of December 31, 2025, WhiteHawk has accumulated natural gas mineral and royalty assets across approximately 3.4 million gross DSU acres focused primarily on the Appalachian and Haynesville Basins. From our inception in 2022 through 2025, WhiteHawk has made seven acquisitions and has paid more than 46 consecutive monthly cash dividends, representing approximately 36%⁶⁴ cash-on-cash return to our initial investors, plus an additional 41% increase in shareholder value through three share dividends through January 1, 2026.

The figure below summarizes our acquisition history with respect to acquired NRAs on an 8/8^th basis.

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⁶⁴	Reflects a cash-on-cash return to our initial investors whose share price did not include any selling commissions on investment. Returns to our initial investors whose share price included selling commissions on investment resulted in cash-on-cash returns of approximately 33%.

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driven analysis, allows WhiteHawk to efficiently negotiate and close transactions while maintaining disciplined capital allocation. In addition to utilizing technical analysis, we strive to acquire mineral and royalty interests in properties with top-tier E&P operators. We seek E&P operators that are well-capitalized, have a strong operational track record, and we believe will continue to increase production through the application of the latest drilling and completion techniques across our mineral and royalty interests, and have demonstrated resilience through commodity cycles.

The U.S. natural gas minerals and royalties market remains highly fragmented with many private owners and few scaled aggregators. This structural fragmentation presents a significant opportunity for continued consolidation. WhiteHawk is one of the few active, large mineral buyers focused exclusively on natural gas. Upon completion of this offering, WhiteHawk will be the only public natural gas mineral and royalty company with meaningful, scaled exposure to the Appalachian and Haynesville Basins, allowing WhiteHawk to capitalize on this fragmented market.⁶⁵ We intend to leverage our position to pursue disciplined, accretive acquisitions that enhance portfolio quality, expand our footprint in premier basins, and drive sustainable growth in cash flow and shareholder returns over time.

Natural Gas Industry and Future Development

Natural gas is the largest source of U.S. electricity generation and a cornerstone of global energy supply, accounting for approximately 41%⁶⁶ of total domestic power output in 2025. U.S. natural gas demand has the potential to increase from 107 Bcf/d in 2025 to approximately 148 Bcf/d by 2031, supported by structural growth across LNG exports, power generation expansion, rising electricity demand from data centers and AI, and advanced manufacturing.⁶⁷

U.S. LNG export capacity could expand to around 45 Bcf/d by 2031, supported by approximately 34 Bcf/d currently operating or under construction and an additional 11 Bcf/d of capacity announced but not currently under construction⁶⁸. If all export capacity is active by 2031, this would represent a 28% increase in natural gas demand over 2025 levels from LNG exports alone. The continued growth in LNG exports is expected to position the United States as the world’s leading supplier of natural gas to Europe and Asia as international buyers seek secure, competitively priced and transparent alternatives to oil-indexed or regional benchmarks.

⁶⁵	Based upon management’s review of public filings with the SEC, excluding those companies which either derive a majority of their revenue from oil or are oil and NGL weighted in production.

⁶⁶	EIA Electric Monthly.

⁶⁷	Management estimate based on EIA Short-Term Energy Outlook.

⁶⁸	EIA Liquefaction Report as supplemented by management’s review of recently announced facilities.

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The figure below illustrates estimated liquefaction capacity for existing, under construction and announced projects as of December 2025:

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Note: Liquefaction Capacity reflects Peak Nameplate Capacity. Commercial Operation includes commissioned projects. Source: EIA Liquefaction Report.

In addition to the growing LNG export demand, the accelerated buildout of AI and cloud-computing infrastructure is creating a new and durable source of electricity demand, much of which is expected to be met by natural gas-fired power generation due to its reliability, scalability and relatively favorable carbon intensity. WhiteHawk’s mineral position in the Appalachian Basin lies in close proximity to major data center growth corridors across Virginia, Ohio and Pennsylvania, where WhiteHawk has identified, as of December 2025, publicly announced 28 new data centers representing what management estimates will generate 3.3 Bcf/d of incremental natural gas demand, of which approximately 1.7 Bcf/d is under construction or has achieved FID and approximately 1.6 Bcf/d is in pre-FID and announced stages.⁷⁰

⁶⁹	Assumes 1 gigawatt of capacity equates to 154 mmcf/d of natural gas demand .

⁷⁰	Assumes 1 gigawatt of capacity equates to 154 mmcf/d of natural gas demand .

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Our Focus on Key Gas Basins

WhiteHawk’s assets are concentrated in the Appalachian Basin, Haynesville Basin and Mid-Continent (“Mid-Con”) region, which collectively represent the core of U.S. natural gas production. Each region combines substantial resource depth, high-quality operators, and access to major infrastructure and end-markets.

Appalachian Basin (Pennsylvania / West Virginia / Ohio)

The Appalachian Basin, located primarily in Pennsylvania, West Virginia and Ohio, constitutes the largest and most prolific natural gas basin in the United States and a critical source of future global natural gas supply, as of December 2025.⁷¹ The basin’s scale, consistent reservoir quality and access to infrastructure have made it a cornerstone of U.S. natural gas production and a key driver of the nation’s transition toward cleaner, lower-carbon energy. The Appalachian Basin’s importance to future natural gas growth is underpinned by its vast remaining resource potential and direct connectivity to both domestic and international demand. The basin benefits from an extensive network of gathering, processing and long-haul pipeline infrastructure that links production to major population centers and growing data center markets in the Northeast, Midwest and Northern Virginia, as well as to LNG export markets along the Gulf Coast. Continued expansion of southbound takeaway capacity and LNG facilities is expected to reinforce the region’s role as a primary growth engine for U.S. natural gas supply over the next decade.

In the Appalachian Basin, the Marcellus Shale has transformed the United States from a net importer to a net exporter of natural gas over the past 20 years. During 2025, it accounted for roughly one-third of total U.S. dry gas production, producing at some of the lowest breakeven costs in the United States.⁷² Exceptional pressure regimes, thick, laterally continuous pay zones and modern completion techniques allow operators to achieve recoveries and sustained productivity that rank among the highest in the industry.⁷³ The Utica Shale provides additional stacked-pay potential that enhances the economic life and development diversity of the basin and already accounted for 8% of total U.S. natural gas production in 2025.⁷⁴

As of December 31, 2025, WhiteHawk’s interests cover approximately 975,000 gross DSU acres across Southwest Pennsylvania and Northern West Virginia, operated by leading Appalachian Basin producers, including EQT, Range Resources, CNX Resources and Antero Resources. These operators possess deep drilling inventories, strong balance sheets and a proven track record of disciplined development. Throughout 2024 and 2025, approximately 47% of wells turned in line by these operators in the Appalachian Basin were drilled on our acreage.⁷⁵

Haynesville Basin (East Texas / North Louisiana)

⁷¹	EIA Short-Term Energy Outlook.

⁷²	EIA Short-Term Energy Outlook.

⁷³	Enverus Data.

⁷⁴	EIA Short-Term Energy Outlook.

⁷⁵	Enverus Data.

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existing and planned U.S. LNG export terminals—including Sabine Pass, Cameron, Golden Pass, Port Arthur and Plaquemines—source a substantial portion of their feed gas from the Haynesville Basin. This geographic alignment ensures that the basin will remain a key driver of U.S. natural gas export growth for decades as global markets seek cheaper, reliable sources of natural gas and lower-carbon alternatives to coal and oil.

Since its renewed development in 2017, the Haynesville Basin has delivered steady volume growth supported by high-deliverability wells and low full-cycle development costs.⁷⁶ The basin is characterized by over pressured, laterally extensive shale formations that yield high initial production rates and long-lived reserves.⁷⁷ Continued advances in lateral lengths, completion designs and multi-well pad efficiencies have enhanced recoveries and reduced breakeven costs, making the Haynesville Basin one of the most economically viable sources of natural gas in the world. In addition to the Haynesville Shale, our acreage also benefits from additional resources from the Cotton Valley and Mid-Bossier formations, which together produced approximately 3.2%⁷⁸ of U.S. natural gas production in 2025.

Mid-Con Region (Anadarko Basin, Oklahoma)

As of December 31, 2025, WhiteHawk’s Mid-Con position spans approximately 1.7 million gross DSU acres across the SCOOP, STACK and Arkoma plays, operated by established and well-capitalized producers such as Continental Resources, Devon Energy and Ovintiv. These operators maintain deep, de-risked inventories and continue to optimize recovery through longer laterals, tighter spacing and improved completion designs.

⁷⁶	EIA Short-Term Energy Outlook.

⁷⁷	Upstream Outlook Report.

⁷⁸	Enverus Data.

⁷⁹	Enverus Data.

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Our Mineral and Royalty Interests

Nature of Our Mineral and Royalty Interests

WhiteHawk’s portfolio consists primarily of producing and undeveloped mineral and royalty interests in the Appalachian Basin, Haynesville Basin and Mid-Con region that provide the right to receive a share of production revenue from the sale of natural gas, NGLs and oil produced by third-party operators. These interests include fee mineral ownership, non-participating royalty interests and overriding royalty interests.

We own two types of interests: mineral and royalty interests and non-operating working interests. Of the mineral and royalty interests, we own three types: mineral interests, NPRIs and ORRIs. For the year ended December 31, 2025, our mineral and royalty interests accounted for approximately 99% of our royalty revenues and our non-operating working interests accounted for approximately 1% of our royalty revenues. Each of these interests have different rights and obligations as further described below:

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Non-Participating Royalty Interest. A NPRI has the same characteristics as a standard royalty interest except that the term “non-participating” indicates that the interest owner has the right to participate in the execution of gas and oil leases but does not share in the bonus or rentals from a gas and oil lease. NPRIs represented approximately 3% of our mineral and royalty interests as of December 31, 2025.

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Non-Operating Working Interest. In addition to our mineral and royalty interests, we own certain non-operating working interests acquired in connection with the PHX Acquisition. Non-operating working interest holders have the right to extract minerals from acreage leased pursuant to a gas and oil lease from a mineral interest holder. Holders of working interests are responsible for their pro rata share of capital expenditures and lease operating expenses, but holders of working interests only receive revenues after distributions have first been made to holders of royalty interests and ORRIs. Working interests expire upon the termination or expiration of the underlying gas and oil lease. As of December 31, 2025, our non-operating working interest portfolio consisted of 437 gross (18.1 net) wells located exclusively in the Mid-Con region and accounted for approximately 1% of our royalty revenues. These non-operating working interests represented approximately 7% of our total proved reserves and 3% of our total production for the year ended December 31, 2025.

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As of December 31, 2025, our interest covered approximately 3.4 million gross DSU acres and more than 10,900 producing wells. As of December 31, 2025 we held an economic interest in 13% of total U.S. natural gas production and in 2025 we had an interest in 18% of new wells drilled in the Appalachian and Haynesville Basins.⁸⁰ As of December 31, 2025, the estimated proved natural gas, NGL and crude oil reserves attributable to our interest are 86% natural gas, 10% NGLs and 4% crude oil, with $293,690 thousand of PV-10. Of these proved reserves, 98% were classified as PD reserves and 2% were classified as undeveloped reserves. For the year ended December 31, 2025, the average net daily production associated with our portfolio was 50,351 Mcfe/d, consisting of 45,442 Mcf/d of natural gas, 577 Bbls/d of NGLs and 241 Bbls/d of oil and on a pro forma basis, average net daily production of 67,255 Mcfe/d, consisting of 59,621 Mcf/d of natural gas, 790 Bbls/d of NGLs and 483 Bbls/d of oil.

⁸⁰	Enverus Data.

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Key Operators

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Collectively, in 2025, these 14 operators listed above controlled more than 79% of WhiteHawk’s leased acreage and represented the leading producers in the Appalachian Basin, Haynesville Basin and Mid-Con region. Their scale, balance-sheet strength and technological capabilities enhance recovery efficiency, reduce breakeven costs and provide reliable long-term development of our mineral interests—directly supporting our ability to pay sustainable dividends to our investors, although there can be no assurance that we will pay any dividends to holders of our Class A common stock, or as to the amount of any such dividends. See “Risk Factors—Risks Related to this Offering and Ownership of Our Class A Common Stock—We intend to pay regular dividends to our stockholders, but our ability to do so is subject to the discretion of our board of directors and may be limited by our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements, instruments governing our indebtedness and other factors and restrictions our board of directors deems relevant.”

Strengths

We believe that the following competitive strengths will allow us to successfully capitalize on our market opportunities, execute our business strategies, and achieve our primary business objectives:

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Premier, large-scale natural gas mineral and royalty company in America’s most productive gas basins. We have assembled one of the largest pure-play natural gas mineral and royalty portfolios in the United States, spanning approximately 3.4 million gross DSU acres and providing exposure to more than 10,900 producing wells as of December 31, 2025. Our acreage is concentrated in the Appalachian and Haynesville Basins, two of the most productive and lowest-cost sources of natural gas in the United States, which together accounted for more than 50% of total U.S. dry gas production⁸² and 81% of our royalty revenue in 2025. These basins feature thick, laterally continuous shale intervals, high-pressure reservoirs, and well-developed gathering and long-haul pipeline infrastructure that enable some of the lowest breakeven development economics in the United States. The fact that 11% and 33%⁸³ of Appalachian and Haynesville Basin wells, respectively, were drilled on our acreage in 2025, is indicative that our assets are located in the core development areas of these premier gas plays. We believe our proximity to the core development areas of these basins will provide long-term visibility into drilling activity and sustained royalty cash flow through consistent operator investments and stacked play potential.

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⁸¹	Enverus Data. Percentages exceed 100% due to rounding.

⁸²	EIA Short-Term Energy Outlook.

⁸³	Enverus Data.

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and minimal operating costs. Our mineral and royalty interests allow us to capture the economic benefits of natural gas development without bearing the capital risk or inflationary cost pressures typical of traditional E&P companies because we do not incur drilling, completion, lease operating expenses, or plugging and abandonment obligations at the end of a well’s productive life. This capital-light model enables us to convert a significant portion of our revenue directly into free cash flow. Our recurring costs are limited primarily to production taxes, gathering, processing, and transportation expenses, and modest general and administrative overhead.

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High-quality assets supported by top-tier operators with visible development activity. Our mineral interests are operated by leading, well-capitalized E&P companies in some of the most productive and economically attractive natural gas basins in the United States. In 2025, the Appalachian Basin accounted for approximately 38% of the total U.S. natural gas production,⁸⁴ with WhiteHawk’s acreage operated by premier producers including EQT, Antero Resources, Range Resources and CNX Resources. Combined, these operators accounted for approximately 96% of our royalty revenue in the Appalachian Basin in 2025. The Haynesville Basin contributed approximately 14% of total U.S. natural gas production in 2025,⁸⁵ with WhiteHawk’s acreage operated by premier producers including Expand Energy, Comstock Resources and Aethon Energy. Combined, these operators accounted for approximately 58% of our royalty revenue in the Haynesville Basin for 2025. As of December 31, 2025, our portfolio includes nearly 430 WIPs and permitted locations, and more than 8,000 remaining identified undeveloped locations. We believe this embedded inventory provides a visible, multi-year growth runway that requires no additional capital investment from us. Our exposure to operators with strong balance sheets, basin-leading drilling productivity, and disciplined capital programs is designed to enhance the stability of our production base and support long-term royalty cash flow generation.

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Capturing value from AI-driven electricity demand growth. We are positioned to benefit from the accelerating rise in electricity demand driven by AI and data center expansion, much of which is expected to be met by natural gas. Natural gas is the primary fuel for U.S. power generation accounting for approximately 41%⁸⁶ of total electricity output in 2025. In line with this trend, our Appalachian Basin acreage is located near 21 publicly announced new or planned natural gas fired power plants representing what management estimates to be approximately 7.8 Bcf/d of total natural gas demand associated with new power plants expected by 2031.⁸⁷ The ongoing expansion of AI-driven and digital-infrastructure power needs is expected to support long-term natural gas consumption and price stability, encouraging sustained operator investment and development activity on our mineral acreage and providing predictable recurring cash flows that can be distributed to investors.

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Positioned to capitalize on LNG export growth. The EIA estimates U.S. LNG export capacity will nearly double from approximately 17 Bcf/d in 2025 to nearly 34 Bcf/d by 2031⁸⁸, as European and Asian buyers seek secure, competitively priced supply and diversify away from oil-indexed benchmarks or regional international benchmarks such as JKM (Asia) and TTF (Europe), where the average pricing is 3-4x Henry Hub pricing in the United States for the year 2025.⁸⁹ In addition, as of December 2025, approximately 28 Bcf/d of incremental LNG capacity is in various stages of regulatory review and development, representing further upside to long-term U.S. export potential.⁹⁰ The Haynesville Basin’s proximity and pipeline connectivity to the Gulf Coast LNG corridor position our assets to benefit directly from this expansion. Sustained growth in U.S. LNG exports is expected to drive long-term feed-gas demand from the basins where our mineral interests are concentrated, for years to come.

⁸⁴	EIA Short-Term Energy Outlook.

⁸⁵	EIA Short-Term Energy Outlook.

⁸⁶	EIA Electric Monthly.

⁸⁷	Assumes 1 gigawatt of capacity equates to 154 mmcf/d of natural gas demand.

⁸⁸	EIA Natural Gas Exports. Excludes announced projects.

⁸⁹	FactSet LNG Pricing.

⁹⁰	EIA Liquefaction Report as supplemented by management’s review of recently announced facilities

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Proven management team with a track record of public company value creation and accretive growth. Our management team is among the most experienced and acquisitive in the minerals sector, with more than 125 years of combined industry experience and over $31 billion of completed energy transactions across the upstream, midstream, and mineral and royalty value chain. Members of our team previously served as senior executives or founders of Atlas Energy, Atlas Pipeline Partners and Falcon Minerals, each a successful public company that created substantial shareholder value through disciplined growth, accretive acquisitions, and strategic monetization. Since our founding, WhiteHawk has been the most active acquirer of natural gas minerals and royalties, completing eight large transactions across the most prolific gas-oriented basins in the United States.⁹¹ Our ability to consistently source, evaluate, and close accretive transactions underscores WhiteHawk’s leadership as a focused, data-driven consolidator with proven expertise in capital allocation, M&A execution and public-market stewardship.

Strategies

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Provide sustained income to investors through strong Cash Available for Distribution generation and cash dividends. We expect initially to pay dividends from our Cash Available for Distribution with the remaining cash flow to be used for additional acquisitions that meet our investment criteria or to maintain our conservative capital structure. As mineral and royalty owners, we benefit from the continued organic development of our acreage and are able to convert a high percentage of our revenues to Cash Available for Distribution. We believe that our mineral and royalty interests are positioned for growth as E&P operators continue to concentrate on the Appalachian Basin, Haynesville Basin and Mid-Con region to meet growing global demand for natural gas. Since our inception in 2022, we have paid 46 consecutive monthly common equity dividends, totaling approximately $30 million and representing a cash-on-cash return of approximately 36%⁹² to our initial investors through January 1, 2026. We believe our efficient, conservatively levered structure, with low capital intensity and disciplined financial management, provides a sustainable foundation for attractive dividend yields, balance sheet flexibility, and long-term value creation for shareholders; however, there can be no assurance that we will pay any dividends to holders of our Class A common stock, or as to the amount of any such dividends. See “Risk Factors—Risks Related to this Offering and Ownership of Our Class A common stock—We intend to pay regular dividends to our stockholders, but our ability to do so is subject to the discretion of our board of directors and may be limited by our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements, instruments governing our indebtedness and other factors and restrictions our board of directors deems relevant.”

•

⁹¹	Enverus Data.

⁹²	Reflects a cash-on-cash return to our initial investors whose share price did not include any selling commissions on investment. Returns to our initial investors whose share price included selling commissions on investment resulted in cash-on-cash returns of approximately 33%.

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•

Pursue disciplined, accretive acquisitions in premier natural gas plays. We intend to grow our portfolio through the disciplined acquisition of high-quality natural gas mineral and royalty interests in the Appalachian Basin, Haynesville Basin and Mid-Con region. By leveraging our management team’s extensive industry relationships, and proprietary geologic and title data, we target assets that can provide accretive growth in shareholder value while strengthening our production and reserve base. Since inception, we have been among the most active consolidators in the natural gas minerals sector, completing seven transactions that have materially increased our scale and enhanced cash flow. These acquisitions have been highly accretive to shareholders and have resulted in approximately 36%⁹³ cash-on-cash return to our initial investors. We believe current market conditions remain highly favorable for consolidation, as fragmented ownership across numerous private sellers continues to create opportunities for accretive acquisitions that meet our investment criteria.

•

Optimize portfolio to maximize Cash Available for Distribution and maintain diversified exposure. We actively manage our portfolio to prioritize acreage with a strong cash-flow base, visible near-term development, and substantial future inventory. A core component of this strategy is maintaining a broad, diversified mineral footprint across multiple core natural gas basins, encompassing an average NRI of 0.69% in more than 10,900 producing wells, with additional wells consistently in various stages of development across a footprint exceeding 3.4 million gross DSU acres as of December 31, 2025. This scale and diversity provide exposure to the most prolific, lowest-cost natural gas plays in the United States while reducing reliance on any single operator or well. The result is a balanced portfolio designed to generate resilient cash flow and mitigate volatility through commodity cycles. Through disciplined asset management, targeted reinvestment, and continued optimization, we seek to enhance portfolio productivity, strengthen cash flow stability and grow our dividend over time.

•

⁹³	Reflects a cash-on-cash return to our initial investors whose share price did not include any selling commissions on investment. Returns to our initial investors whose share price included selling commissions on investment resulted in cash-on-cash returns of approximately 33%.

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Our Acquisition History

We completed our first acquisition in 2022 when we acquired an aggregate 25% undivided interest in the natural gas-weighted mineral and royalty assets of the TRR Seller located in the Appalachian Basin of southwestern Pennsylvania. The assets are primarily located in Washington and Greene counties in Pennsylvania, which WhiteHawk believes represent some of the highest quality natural gas reserves in the United States. This initial position was anchored by best-in-class natural gas operators EQT, Range Resources and CNX Resources. This initial position established our footprint in the Marcellus Shale.

In 2023, we expanded into the Haynesville Shale, acquiring minerals in two separate transactions from Mesa Minerals Partners II, LLC and affiliated entities across northwestern Louisiana and East Texas operated by best-in-class producers including Expand Energy, Aethon Energy and Comstock Resources. This transaction marked a pivotal step in building a diversified, multi-basin platform, pairing Appalachia’s predictable base with Haynesville’s price-responsive growth and direct exposure to Gulf Coast LNG demand. The Mesa acquisitions were completed through two separately negotiated transactions, closing in the first and third quarters of 2023. Later that year, we doubled our Marcellus position through an acquisition of an additional 25% interest in our existing footprint of natural gas mineral and royalty assets from the TRR Seller.

In 2024, we deepened our Appalachian presence with a 20% undivided interest in other natural gas mineral and royalty assets of an affiliate of the TRR Seller, adding acreage in Pennsylvania and West Virginia, and increasing WhiteHawk’s Appalachian footprint to approximately 975,000 gross DSU acres. This acquisition also added more significant exposure to Antero Resources, along with increased exposure to EQT, Range Resources and CNX Resources. The assets are primarily located in Washington and Greene counties in Pennsylvania, and Wetzel and Marshall counties in West Virginia.

In the first quarter of 2025, we acquired additional Marcellus Shale mineral and royalty interests in the acquisition of the remaining 50% interest in natural gas mineral and royalty assets of the TRR Seller. In June 2025, we acquired PHX. The PHX Acquisition increased our mineral and royalty ownership position by acquiring additional mineral and royalty interests in the Haynesville Shale, as well as the SCOOP/STACK, Bakken, Arkoma and others. The PHX Acquisition also increased our exposure to some of its top third-party operators, including Expand Energy, Comstock Resources and Aethon Energy in the Haynesville Shale, while adding other top operators, including Continental Resources and Devon Energy in the SCOOP/STACK region in Oklahoma. As a result of the PHX Acquisition, WhiteHawk added approximately 1.8 million gross DSU acres of premier natural gas mineral and royalty assets, significantly expanding its footprint in the core of the Haynesville Shale in East Texas/North Louisiana and diversifying its portfolio into the SCOOP/STACK region.

Haynesville Assets

On March 2, 2026, the Company and its affiliate entered into a definitive purchase and sale agreement to acquire the Haynesville Assets. The Haynesville Assets cover approximately 150,000 gross DSU acres and will further increase the Company’s exposure to high-quality development across the Haynesville and Mid-Bossier formations. The assets are concentrated in core areas of the basin and are operated by established, well-capitalized operators. The Haynesville Assets acquisition closed on April 3, 2026. We funded the purchase price of the Haynesville Assets acquisition primarily through the issuance of approximately $37.8 million of shares of Series D preferred stock. See “Description of Capital Stock—Preferred Stock—Series D Preferred Stock.”

Natural Gas, NGL and Oil Data

Proved Reserves

Evaluation of Proved Reserves. Our proved reserve estimates as of December 31, 2025 and 2024 are based on reserve reports prepared by CG&A and Schaper Energy, respectively, our independent petroleum engineers. The reports of CG&A and Schaper Energy contain further discussion of the reserves estimates and their preparation procedures.

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With respect to our 2025 reserve report, the technical person primarily responsible for supervising the preparation of the reserves estimates set forth in the CG&A report is Mr. W. Todd Brooker, P.E., President of Cawley, Gillespie & Associates, Inc. Prior to joining CG&A in 1992, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron U.S.A. His experience includes extensive projects in conventional and unconventional reservoirs across all major U.S. basins, including oil and gas shales, coalbed methane, waterfloods and complex, faulted structures. His current responsibilities include reserve and economic evaluations, fair market valuations, expert reporting and testimony, field studies, pipeline resource assessments, development planning and acquisition/divestiture analysis. Mr. Brooker graduated with honors from The University of Texas at Austin with a Bachelor of Science in Petroleum Engineering. He is a licensed Professional Engineer in the State of Texas, a member of the Society of Petroleum Engineers (SPE) and serves on the board of the Society of Petroleum Evaluation Engineers (SPEE).

CG&A meets or exceeds the requirements relating to professional qualifications, independence, objectivity and confidentiality set forth in the standards pertaining to estimating and auditing oil and gas reserves information. CG&A does not own an interest in any of our properties and is not employed by us on a contingent basis.

With respect to our 2024 reserve report, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve reports incorporated herein is Mr. Andrew Schaper, P.E., President of Schaper Energy. Prior to joining Schaper Energy, Mr. Schaper acted as the Head of Americas A&D Origination at Bank of America Merrill Lynch in Houston, Texas. Prior to his time at Bank of America Merrill Lynch, Mr. Schaper held positions with Citigroup, Quantum Resources Management LLC and Newfield Exploration Company. He spent the first several years of his career acting as a reservoir engineer in both development and exploratory capacities focused on domestic basins. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin, including gas and oil shale plays, conventional fields, and secondary recovery operations. His current responsibilities include reserve and economic evaluations, fair market valuations, field studies, acquisition/divestiture analysis and expert witness support for the foregoing topics.

Mr. Schaper graduated Summa Cum Laude from Texas A&M University with a Bachelor of Science degree in Electrical Engineering specializing in Power Systems, and holds a Master of Engineering degree in Petroleum Engineering from Texas A&M University, a Master in Business Administration degree from The University of Texas at Austin and a Doctor of Engineering degree in Engineering from Texas A&M University with a focus in Nuclear, Energy & Environmental Engineering. Mr. Schaper is a licensed Professional Engineer in the State of Texas and is a Certified Petroleum Engineer (SPEC^®) with the Society of Petroleum Engineers (“SPE”) and a member of the Society of Petroleum Evaluation Engineers (“SPEE”).

Mr. Schaper meets or exceeds the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Schaper Energy does not own an interest in any of our properties, nor is it employed by us on a contingent basis.

The summary of our 2024 report with respect to our proved reserve estimates as of December 2024 is included as an exhibit to the registration statement of which this prospectus forms a part.

We maintain a staff of petroleum engineers who work closely with our management team and our independent petroleum engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our properties. Our management team meets with our independent reserve engineers periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to our independent petroleum engineers for our properties, such as ownership interest, natural gas and oil production, commodity prices and our estimates of our operators’ operating and development costs. John Picton, our Vice President of Engineering, is primarily responsible for overseeing the review of our reserve estimates. Mr. Picton has substantial reservoir and operations experience with more than 15 years of experience. Prior to joining our Company full-time in April

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2025 and as a consultant since April 2023, Mr. Picton previously held roles at Quantum Energy Partners, Teton Range LLC, Jefferies Financial Group, Inc., LINN Energy, LLC, Occidental Petroleum Corp. and Citation Oil & Gas Corp.

The preparation of our proved reserve estimates were reviewed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•

review and verification of historical production data, which data is based on actual production as reported by our operators;

•

review by Mr. Picton of all of our reported proved reserves, including the review of all significant reserve changes and all new PUDs additions;

•

review of reserve estimates by Mr. Picton or under his direct supervision; and

•

direct reporting responsibilities by Mr. Picton to our Chief Operating Officer.

Estimation of Proved Reserves. In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural gas, 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, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of our proved reserves as of December 31, 2025 and 2024 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing and PUDs for our properties, due to the abundance of analog data.

To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core data, and historical well cost and operating expense data.

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Summary of Reserves. The following tables present our estimated net proved reserves as of December 31, 2025 and 2024, based on our proved reserve estimates as of such dates, which have been prepared by CG&A and

Schaper Energy, respectively, our independent petroleum engineering firms, in accordance with the rules and regulations of the SEC. All of our proved reserves are located in the United States. The increase in our estimated net proved reserves over this period was primarily the result of an increase in commodity prices.

The table below summarizes our present value and reserves as of December 31, 2025:


	WhiteHawk⁽¹⁾
	(dollars in thousands)
Estimated proved developed producing reserves:
Natural gas (MMcf)		154,137
NGLs (MBbls)		2,914
Oil (MBbls)		1,154
Total (MMcfe)⁽²⁾		178,544
Estimated proved developed non-producing reserves:
Natural gas (MMcf)		19,094
NGLs (MBbls)		459
Oil (MBbls)		203
Total (MMcfe)⁽²⁾		23,066
Estimated proved undeveloped reserves:
Natural gas (MMcf)		4,149
NGLs (MBbls)		84
Oil (MBbls)		35
Total (MMcfe)⁽²⁾		4,864
Estimated proved reserves:
Natural gas (MMcf)		177,380
NGLs (MBbls)		3,457
Oil (MBbls)		1,392
Total (MMcfe)⁽²⁾		206,473
Standardized Measure($)	$	266,326
PV-10 ($)⁽³⁾	$	293,690

(1)

Our estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For gas volumes, the average Henry Hub spot price calculated in accordance with SEC guidance of $3.387 per MMBtu was adjusted for local basis differential, treating cost, transportation, gas shrinkage and gas heating value (BTU content). For NGLs and oil volumes, the average West Texas Intermediate price calculated in accordance with SEC guidance of $65.34 per barrel as of December 31, 2025 was adjusted for local basis differential, treating cost, transportation and/or crude quality and gravity corrections. All economic factors were held constant throughout the lives of the properties in accordance with SEC guidelines. The average adjusted product prices weighted by production over the remaining lives of the proved properties were $3.03 per Mcf of gas, $22.03 per barrel of NGLs and $62.99 per barrel of oil as of December 31, 2025.

(2)	Natural gas equivalents are calculated using a ratio of six thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs, based on approximate relative energy content. This ratio does not represent the current or historical price relationship between natural gas and oil or NGLs.

(3)

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10% using SEC rules. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize PV-10 as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use PV-10 when assessing the potential return on investment related to our oil and natural gas properties; however, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. PV-10 and the standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves. See “—Reconciliation of Standardized Measure to PV-10.”

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The table below summarizes our, PHX and the TRR Seller’s present value and reserves as of December 31, 2024:


	WhiteHawk⁽¹⁾		PHX⁽²⁾		TRR Seller⁽³⁾
	(dollars in thousands)
Estimated proved developed producing reserves:
Natural gas (MMcf)		64,783		41,648		47,103
NGLs (MBbls)		690		1,320		653
Oil (MBbls)		23		943		14
Total (MMcfe)⁽⁴⁾		69,061		55,227		51,105
Estimated proved developed non-producing reserves:
Natural gas (MMcf)		469		901		2,424
NGLs (MBbls)		11		2		61
Oil (MBbls)		0		5		4
Total (MMcfe)⁽⁴⁾		535		944		2,814
Estimated proved undeveloped reserves:
Natural gas (MMcf)		16,469		6,758		0
NGLs (MBbls)		176		26		0
Oil (MBbls)		16		99		0
Total (MMcfe)⁽⁴⁾		17,619		7,506		0
Estimated proved reserves:
Natural gas (MMcf)		81,721		49,307		49,527
NGLs (MBbls)		877		1,348		714
Oil (MBbls)		39		1,047		18
Total (MMcfe)⁽⁴⁾		87,213		63,677		53,919
Standardized Measure($)⁽⁵⁾	$	61,933	$	76,255	$	45,088
PV-10($)⁽⁵⁾	$	72,153	$	79,642	$	45,088

(1)

(2)

(3)

The TRR Seller’s estimated reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For gas volumes, the average Henry Hub spot price calculated in accordance with SEC guidance of $2.13 per MMBtu was adjusted for local basis differential, treating cost, transportation, gas shrinkage and gas heating value (BTU content). For NGLs and oil volumes, the average West Texas Intermediate price calculated in accordance with SEC guidance of $75.48 per barrel as of December 31, 2024 was adjusted for local basis differential, treating cost, transportation and/or crude quality and gravity corrections. All economic factors were held constant throughout the lives of the properties in accordance with SEC guidelines. The average adjusted product prices weighted by production over the remaining lives of the proved properties were $1.44 per Mcf of gas, $23.67 per barrel of NGLs and $71.51 per barrel of oil as of December 31, 2024. Estimates of TRR Seller’s reserves were based upon the reserve report prepared by TRR Seller’s independent petroleum engineer, Ryder Scott Company, LP.

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(4)	Natural gas equivalents are calculated using a ratio of six thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs, based on approximate relative energy content. This ratio does not represent the current or historical price relationship between natural gas and oil or NGLs.

(5)

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10% using SEC rules. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize PV-10 as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use PV-10 when assessing the potential return on investment related to our oil and natural gas properties; however, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. PV-10 and the standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves. See “—Reconciliation of Standardized Measure to PV-10.”

The following table provides information regarding our gross and net drilling locations by basin and reserve category as of December 31, 2025:


	PDP		WIPs		Permits		Other Locations		Total
Basin / Region
Appalachia		2,322		150		79		2,563		5,114
Haynesville		2,203		64		30		1,487		3,784
Mid-Continent		5,492		65		21		3,866		9,444
Other		930		15		6		437		1,388

Total Gross Location Count		10,947		294		136		8,352		19,729

Total Net Location Count		75.2		1.2		0.3		26.46		103.22

Summary of Undeveloped Locations. The following table presents our estimated undeveloped inventory as of December 31, 2025, which have been audited by our independent petroleum engineering firm, CG&A. CG&A’s review considered only technical criteria in reviewing undeveloped locations and did not attempt to determine commerciality of any location or intent by operators to develop such locations identified by the Company. Further, no reserves (except for those presented as part of CG&A’s reserve report dated March 13, 2026, with respect to the Company’s proved reserves as of December 31, 2025) have been quantified beyond identifying numbers of viable undeveloped locations based on their technical review.

We identify drilling locations based on our assessment of current geologic, engineering and land data. This includes DSU formation, current well spacing and typical lateral length information derived from state agencies and operations of the E&P companies drilling our mineral interests. Our extensive inventory includes locations in the Appalachian Basin, Haynesville Basin, Mid-Continent Region and other basins and regions.

The following table provides information regarding our gross and net locations by region or basin based on technical parameters as of December 31, 2025.


	Gross Undeveloped Location Count⁽¹⁾						Net Undeveloped Location Count⁽⁴⁾		Average Lateral Length
Region / Basin	Included in Proved Reserves⁽²⁾		Other Locations⁽³⁾		Total		Total		(feet)
Appalachian Basin		229		2,563		2,792		8.7		13,246
Haynesville Basin		94		1,487		1,581		3.1		9,267
Mid-Continent Basin⁽⁵⁾		86		3,866		3,952		14.1		9,314
Other⁽⁶⁾		21		437		458		2.1		9,864

(1)	Numbers of gross well locations may vary based on actual lateral lengths drilled by operators.

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(2)	Includes Proved Undeveloped locations included as part of CG&A’s reserve report dated March 13, 2026 with respect to the Company’s proved reserves as of December 31, 2025. Includes WIPs and permits as defined by management.

(3)	Includes locations not included as part of CG&A’s reserve report dated March 13, 2026 with respect to the Company’s proved reserves as of December 31, 2025; however, such locations have been audited and approved by CG&A. Includes other undeveloped locations, as defined by management.

(4)	Reflects management’s estimated net revenue interest multiplied by Total Gross Undeveloped Locations as audited by CG&A.

(5)	Includes locations in the SCOOP, STACK, Cherokee, Arkoma and Fayetteville.

(6)	Includes locations in the Bakken.

Reconciliation of Standardized Measure to PV-10. PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10% using SEC rules. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize PV-10 as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use PV-10 when assessing the potential return on investment related to our oil and natural gas properties; however, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. PV-10 and the standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

The following table presents a reconciliation of PV-10 to the most directly comparable GAAP financial measure for the period indicated (in thousands):


	Years Ended December 31,
	2024		2025
Standardized measure	$	61,933	$	266,326
Present value of future income tax discounted 10%		10,220		27,364
PV-10 of proved reserves		72,153		293,690

PUDs

As of December 31, 2025, we estimated our PUD reserves to be 4,149 MMcf of natural gas, 84 MBbls of NGLs and 35 MBbls of oil, for a total of 4,864 MMcfe. As of December 31, 2024, we estimated our PUD reserves to be 16,469 MMcf of natural gas, 176 MBbls of NGLs and 16 MBbls of oil, for a total of 17,619 MMcfe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table summarize our changes in PUDs during the year ended December 31, 2025:


	Natural Gas (Mmcf)			Crude Oil (Mbbl)			NGL (Mbbl)			Proved Undeveloped Reserves (MMcfe)⁽¹⁾
	(unaudited)
Balance, December 31, 2024		16,469			16			176			17,619
Acquisitions of reserves		—			—			—			—
Extensions and discoveries		2,255			20			69			2,785
Divestiture of minerals in place		—			—			—			—
Revisions of previous estimates		(5,256	)		9			(68	)		(5,602	)
Transfers to estimated proved developed		(9,319	)		(10	)		(93	)		(9,939	)
Balance, December 31, 2025		4,149			35			84			4,864

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(1)	Natural gas equivalents are calculated using a ratio of six thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs, based on approximate relative energy content. This ratio does not represent the current or historical price relationship between natural gas and oil or NGLs.

Changes in PUDs that occurred during 2025 were primarily due to:

•

well additions, extensions and discoveries of approximately 2.8 Bcfe. 2.8 Bcfe was added as proved undeveloped over 232 gross locations due to increased operator activity;

•

negative revisions of approximately 7.5 Bcfe. 5.3 Bcfe decrease over 228 gross locations being reclassified to non-proved due to changes in operator development. 2.2 Bcfe decrease over 23 locations being reclassified to non-proved due to changes in operator unit configuration; and

•

positive revisions of approximately 1.1 Bcfe. 1.1 Bcfe increase over 531 gross locations due to wells that were identified as having a WhiteHawk ownership.

As a mineral and royalty interests owner, we do not incur any capital expenditures or lease operating expenses in connection with the development of our PUDs, which costs are borne entirely by the operator. As a result, during the twelve months ended December 31, 2025, we did not have any expenditures to convert PUDs to proved developed reserves.

We identify drilling locations based on our assessment of current geologic, engineering and land data. This includes DSU formation and current well spacing information derived from state agencies and the operations of the E&P companies drilling our mineral interests. We generally do not have evidence of approval of our operators’ development plans, however we do rely on publicly available information from our third-party operators. As a mineral and royalty company, our PUDs are limited exclusively to locations for which we have public confirmation that the third-party operator has initiated the drilling process for a specific well location. For our purposes, this includes WIPs, where third-party operators have publicly reported a spud date or otherwise confirmed that drilling has commenced, as well as wells that have been drilled but are not yet producing, including those undergoing completion activities. We also include locations covered by approved, publicly available drilling permits where the operator has received regulatory authorization but has not yet commenced drilling. Accordingly, all of our PUDs consist solely of WIPs or permitted locations supported by public operator disclosures, and we do not include speculative or unpermitted future development locations in our PUD inventory. As of December 31, 2025 and 2024, approximately 2% and 20%, respectively, of our total proved reserves were classified as PUDs.

Natural Gas, NGL and Production Prices and Costs

Production and Price History

The following table sets forth information regarding net production of natural gas, NGLs and oil, and certain price and cost information for each of the periods indicated:


	Year Ended December 31, 2024						Year Ended December 31, 2025
	PHX		TRR Seller		WhiteHawk
Production:
Natural gas (Mcf)		7,969,948		5,826,061		7,370,198		16,586,178
NGLs (Bbls)		133,609		67,883		74,350		210,677
Oil (Bbls)		178,357		2,513		3,750		87,970
Equivalents (Mcfe)		9,841,746		6,248,432		7,838,798		18,378,060
Equivalents per day (Mcfe)		26,964		18,209		21,417		50,351
Realized Prices
Natural gas (Mcf)	$	2.19	$	1.78	$	1.85	$	2.94
NGLs (Bbls)	$	21.95	$	25.08	$	25.50	$	21.94
Oil (Bbls)	$	74.59	$	63.82	$	54.67	$	60.93

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	Year Ended December 31, 2024						Year Ended December 31, 2025
	PHX		TRR Seller		WhiteHawk
Equivalents (Mcfe)⁽¹⁾	$	3.42	$	1.96	$	2.01	$	3.19
Average Realized Price After Effects of Derivative Settlements:
Natural gas (per Mcf)	$	2.75	$	3.26	$	3.04	$	3.45
Average costs (per Mcfe):
Transportation, gathering, and marketing	$	0.46	$	0.39		—		—
Depletion, depreciation and accretion	$	0.98	$	0.54	$	1.38	$	1.32
Interest expense, net	$	0.26	$	0.31	$	0.50	$	1.04
General and administrative	$	1.19	$	0.16	$	0.36	$	0.90
Total	$	3.19	$	1.40	$	2.24	$	3.26

(1)	Natural gas equivalents are calculated using a ratio of six thousand cubic feet of natural gas to one barrel of oil, condensate or NGLs, based on approximate relative energy content. This ratio does not represent the current or historical price relationship between natural gas and oil or NGLs.

Productive Wells

Productive wells consist of producing horizontal and vertical wells, wells capable of production and exploratory, development or extension wells that are not dry wells. As of December 31, 2025, we owned mineral and royalty interests in 10,947 gross productive wells and 75.2 net productive wells.

The majority of our mineral and royalty interests are leased to our operators with 94% of our 90,729 leased net mineral acres being held by production as of December 31, 2025. In addition, we had 4,585 net mineral acres that were not leased as of December 31, 2025.

Drilling Results

For the year ended December 31, 2025, 411 gross and 1.4 net wells turned to production. As of December 31, 2025, we owned interests in a total of 10,947 gross productive wells (75.2 net wells), which represents our cumulative producing well count across all of our mineral and royalty interests as of such date, rather than wells turned to production during the year, and our third-party operators turned to production 411 gross and 1.4 net wells on acreage in which we own mineral and royalty interests. As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory or as developmental wells. We are not aware of any dry holes drilled on the acreage underlying our mineral interests during the relevant periods.


	For the Year Ended December 31,
	2025		2024
Productive Gross		411		257
Dry		0		0
Total		411		257
Productive Net		1.4		0.59

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Acreage

The following table sets forth historical information about our developed and undeveloped net mineral acres as of December 31, 2025.


	Net Mineral Acres		Weighted Avg. Net Revenue Interest			NRA (1/8^th Basis)⁽¹⁾		Total NRAs (100% Basis)
Developed		52,887		0.69	%		73,257		9,157
Undeveloped		42,427		0.32	%		58,769		7,346

Total		95,314		0.48	%		132,026		16,503

(1)

Standardized to a 1/8th royalty: The hypothetical number of acres in which an owner owns a standardized 12.5% royalty interest, calculated by multiplying the actual net mineral acres by the average royalty rate and dividing by 12.5%. For example, an owner who has a 25% royalty interest in 100 acres would own 200 NRAs on a 1/8th basis.

Regulation of Environmental and Occupational Safety and Health Matters

Natural gas, NGL and oil exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment, natural resources, and occupational health and safety. These laws and regulations have the potential to impact production by our third-party operators on our properties, including requirements to:

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obtain permits to conduct regulated activities;

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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, habitats of listed or protected species and other protected areas;

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restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities;

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initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells;

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apply specific health and safety criteria addressing worker protection; and

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impose substantial liabilities for pollution resulting from operations.

Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. Moreover, these laws, rules and regulations may restrict the rate of natural gas, NGL and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment or natural resources and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost to our third-party operators of developing our properties. Moreover, accidental releases or spills may occur in the course of operations on our properties, potentially causing our third-party operators to 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.

Increased costs or operating restrictions on our properties as a result of compliance with environmental laws could result in reduced exploratory and production activities by our third-party operators on our properties and,

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as a result, our revenues and results of operations. The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which operations on our properties by our third-party operators are subject.

Regulation of Transportation

The sale and transportation of our natural gas, NGLs and crude oil is generally undertaken by our third-party operators (or by third parties at the direction of such operators) of our properties. Sales of crude oil, condensate and NGL are not currently regulated and are made at negotiated prices; however, Congress has enacted price controls in the past and could reenact price controls in the future. Sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs.

FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Under CERCLA, these “responsible persons” may include the current or former owner or operator of the site where the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances released at the site. These responsible persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the management, generation, treatment, storage and disposal of hazardous and non-hazardous waste. With federal approval, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of natural gas, NGLs and oil, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain natural gas, NGLs and oil drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in the costs to manage and dispose of such wastes, which could increase the costs of our third-party operators’ operations.

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Certain of our properties have been used for natural gas and oil exploration and production for many years. Although former third-party operators may have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under our properties, or on or under other offsite locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. Our properties and the petroleum hydrocarbons and wastes disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the owner or operator could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to prevent future contamination or to pay some or all of the costs of any such action.

Water Discharges and NORM

The Federal Water Pollution Control Act (the “Clean Water Act” or the “CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of dredged or fill material and the discharge of pollutants, including spills and leaks of oil, into waters of the United States (“WOTUS”) and state waters, including certain wetlands. 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 dredged or fill material typically requires a permit issued by the U.S. Army Corps of Engineers (“Corps”).

Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure (“SPCC”) plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak and require certain facility operators to develop, implement, and maintain SPCC plans. The Clean Water Act and analogous state laws also require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities and requires those facilities to develop and implement stormwater pollution prevention plans. The Oil Pollution Act of 1990, as amended (the “OPA”), amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare facility response plans for responding to a worst-case discharge of oil into waters of the United States. Uncertainty with respect to water discharges and changes in water regulations, including under the Clean Water Act and the OPA, have the potential to delay or materially modify the issuance of permits which may be required for certain of our third-party operators’ activities.

The scope of federal jurisdictional reach over WOTUS under the CWA has been subject to significant uncertainty and litigation. In September 2023, the EPA and the Corps issued a final rule conforming the regulatory definition of WOTUS to the U.S. Supreme Court’s 2023 decision in Sackett v. EPA, which narrowed the scope of federally jurisdictional waters to “relatively permanent, standing, or continuously flowing bodies of water” and wetlands with a “continuous surface connection” to such waters. However, the rule is currently subject to litigation. As a result, the September 2023 rule is currently in effect in only 24 states, and the EPA and the Corps are using the pre-2015 definition of WOTUS in the other 26 states. In November 2025, the EPA and the Corps issued a proposed rule to further update and narrow the definition of WOTUS. In addition, the U.S. Supreme Court’s 2020 decision in County of Maui v. Hawaii Wildlife Fund held that, in certain cases, certain discharges from a point source to groundwater could fall within the scope of the CWA and require a permit.

Also, in January 2026, the EPA released a proposed rule to revise its CWA Section 401 Certification Rule following a May 2025 memorandum raising concerns with the existing rule implementing Section 401 promulgated in November 2023. Under CWA Section 401, a federal agency may not issue a license or permit to conduct an activity that may result in a discharge into a WOTUS unless a state or authorized Tribe issues or waives Section 401 water quality certification. The January 2026 proposed rule seeks to limit the scope of Section 401 reviews and clarify the regulations to ensure such reviews are completed within the one-year statutory deadline. Eleven states sued the EPA challenging the 2023 CWA Section 401 Certification Rule, alleging that the

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rule exceeds the EPA’s statutory authority under the CWA, including in State of Louisiana, et al., v. EPA, et al., which has been held in abeyance pending the administration’s review of the rule and litigation. The final rule revising the CWA Section 401 Certification Rule is expected in Spring 2026. However, opponents of the January 2026 proposal are pushing back on these efforts, including EPA efforts to narrow the scope of state authority.

In addition, wastes containing naturally occurring radioactive material (“NORM”) may be generated in connection with our third-party operators’ natural gas and oil production. Certain processes used to produce natural gas and oil may enhance the radioactivity of NORM, which may be present in oilfield wastes. Comprehensive federal regulation does not currently exist for NORM. However, the EPA has studied the impacts of technologically enhanced NORM. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by OSHA. These state and OSHA regulations impose certain requirements concerning worker protection, the treatment, storage and disposal of NORM waste and the management of waste piles, containers and tanks containing NORM, as well as restrictions on the uses of land with NORM contamination. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned treatment works into surface waters), which may increase the costs associated with management of NORM. To the extent that federal or state regulation increases the compliance costs for NORM disposal, our third-party operators may incur additional costs that may make some properties unprofitable to operate.

Air Emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting programs and impose various monitoring and reporting requirements. CAA regulations include, among others, New Source Performance Standards for the oil and natural gas source category to address emissions of sulfur dioxide, methane and volatile organic compounds and a separate set of emissions standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. These laws and regulations may require our third-party operators 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 incur development expenses to install and utilize specific equipment or technologies to control emissions. For example, in December 2023, the EPA finalized new rules intended to reduce methane emissions from gas and oil sources. The rules strengthened the existing emissions reduction requirements in regulations known as Subpart OOOOa, expanded reduction requirements for new, modified and reconstructed natural gas and oil sources in Subpart OOOOb, and imposed methane emissions limitations on existing natural gas and oil sources nationwide for the first time in Subpart OOOOc. In Subpart OOOOc, the rules established “Emissions Guidelines,” which required states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. The rules also created a new third-party monitoring program to flag large emissions events, referred to as “super emitters.” Under Subparts OOOOb and OOOOc, the rules established more stringent requirements for new, modified and reconstructed natural gas and oil sources constructed after December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates. The rules gave states, along with federal tribes that wish to regulate existing sources, until March 2026 to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provided until 2029 for existing sources to comply. However, in March 2025, the EPA announced plans to reconsider Subparts OOOOb and OOOOc and, in November 2025, the EPA finalized an interim final rule extending certain compliance deadlines for certain provisions provided in the 2023 rules. Litigation challenging the final interim final rule remains pending.

Additionally, in May 2024, the EPA finalized amendments to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities in accordance with the Inflation Reduction Act. Among other things, the rule expands the emissions events that are subject to reporting requirements to include “other large release events.” The emissions reported under the Greenhouse Gas Reporting Program were intended to be the basis for any Waste Emissions Charges assessed under the Methane Emissions Reduction Program of the Inflation Reduction

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Act. However, in February 2026, the EPA finalized a rule rescinding the GHG “Endangerment Finding” that underlies these regulations on the basis that the finding, among other reasons, exceeds the EPA’s statutory authority. Litigation challenging the final rule is pending, and as a result there is significant uncertainty with respect to regulation of GHG emissions. Further, in September 2025, the EPA proposed to delay the reporting of GHG emissions under the Greenhouse Gas Reporting Program for the oil and gas sector until 2034. This proposal is still under consideration and is subject to a number of uncertainties and will likely face legal challenges that would further delay the implementation of any rules, and we cannot predict the ultimate outcome.

In November 2024, the EPA finalized a regulation to implement the Inflation Reduction Act’s Waste Emissions Charge. The rule required the EPA to impose and collect a Waste Emissions Charge annually from oil and gas facilities that exceed statutory methane emissions thresholds. However, in February 2025, Congress repealed the Waste Emissions Charge rule using the Congressional Review Act. In addition, the One Big Beautiful Bill Act, enacted in July 2025, delayed implementation of the charge until 2034. While the EPA cannot reissue its rule implementing the Waste Emissions Charge (either in substantially the same form or in a new rule), the underlying requirement in the Inflation Reduction Act remains unchanged. We cannot predict if the Trump Administration and/or Congress may take action to repeal or revise this requirement of the Inflation Reduction Act; however, compliance with this and other air pollution control and permitting requirements has the potential to delay the development of natural gas projects and increase our third-party operators’ costs of development, which costs could be significant. In addition, various states have adopted or are considering adopting new rules to reduce emissions from oil and gas operations in the state, including requirements for more extensive emissions monitoring and reporting. Any such requirements could increase the costs for our third-party operators of development and production on our properties, potentially impairing the economic development of our properties. Obtaining permits has the potential to delay the development of natural gas and oil projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

Climate Change

The threat of climate change continues to attract considerable attention in the United States and around the world, and numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government, and among trade organizations and industry groups to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. While Congress has from time to time considered legislation to reduce emissions of GHGs, comprehensive legislation aimed at reducing GHG emissions has not yet been adopted at the federal level, and in February 2026, the EPA issued a final rule rescinding the “Endangerment Finding” that provides the underlying basis for the majority of its GHG regulations. A number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap-and-trade programs, which typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs, or by means of emissions reporting or climate risk disclosure requirements. Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or that companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. For further discussion regarding these international, federal, and state regulatory and policy initiatives as well as climate change transition and physical risks affecting our and our third-party operators’ businesses see “Risk Factors—Risks Related to Legal, Regulatory and Environmental Matters—The development and enactment of climate change legislation and regulation regarding emissions of GHGs could adversely affect the mineral industry and reduce demand for the natural gas and oil that our third-party operators produce.”

Hydraulic Fracturing Activities

A substantial portion of the production on our properties by our third-party operators involve the use of hydraulic fracturing techniques. Hydraulic fracturing is an important and common practice that is used to stimulate

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production of natural gas, NGLs and oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Most hydraulic fracturing is currently exempt from the definition of “underground injection” under the SDWA; however, legislation to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing activities, and to require disclosure of the chemical constituents of the fluids used in the fracturing process, has been proposed in Congress from time to time. This legislation has not been enacted.

Hydraulic fracturing typically is regulated by state natural gas and oil commissions or similar agencies, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuel in fracturing fluids and issued permitting guidance that applies to such activities. While our third-party operators engaged in hydraulic fracturing do not currently use diesel fuels in their hydraulic fracturing fluids, they may become subject to federal permitting under the SDWA if their fracturing formula changes and may incur significant costs to comply with disposal requirements for hydraulic fracturing fluids and produced water. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. For more information, see “Risk Factors—Risks Related to Legal, Regulatory and Environmental Matters—Future legislative or regulatory changes may result in increased costs and decreased revenues, cash flows and liquidity, all of which could have a material adverse effect on our business, financial condition and results of operations—Hydraulic Fracturing and Water Disposal.”

Endangered Species Act

The Endangered Species Act of 1973, as amended (the “ESA”) and analogous state laws restrict activities that may affect endangered and threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act of 1918, as amended (the “MBTA”) and to eagles under the Bald and Golden Eagle Protection Act. The ESA, MBTA, and similar laws provide for significant penalties for willful or even unintentional violations. The designation of previously unidentified endangered or threatened species could cause our third-party operators to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. To the extent species are listed under the ESA or similar state laws, or are protected under the MBTA, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.

National Environmental Policy Act

The National Environmental Policy Act (“NEPA”) is a procedural statute that requires federal agencies to evaluate the environmental impacts of major federal actions that may significantly affect the quality of the environment, which generally includes the granting of a permit or similar authorization by a federal agency. Some states have analogous laws that provide for similar environmental reviews. As part of such reviews, agencies are generally required to consider a broad array of environmental impacts, such as impacts of the proposed action on air quality, water quality, wildlife, cultural resources, geology, socioeconomics, and aesthetics, as well as practicable alternatives to the project. Procedures for implementing NEPA vary at the agency level. In May 2025, the U.S. Department of Interior issued a new “alternative arrangements” policy for NEPA reviews of proposed fossil fuel projects, significantly expediting environmental review. Also in May 2025, the U.S. Supreme Court held in Seven County Infrastructure Coalition v. Eagle County, Colorado that courts must grant agencies “substantial judic

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