As filed with the U.S. Securities and Exchange Commission on May 4, 2026.

Registration No. 333-295113

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

EagleRock Land, LLC

(Exact Name of Registrant as Specified in its Charter)


Texas	6792	41-3142321
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

9655 Katy Freeway, Suite 375

Houston, Texas 77024

(713) 280-7002

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Greg Pipkin Jr.

Chief Executive Officer

9655 Katy Freeway, Suite 375

Houston, Texas 77024

(713) 280-7002

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Michael S. Telle

Scott D. Rubinsky

Vinson & Elkins L.L.P.

845 Texas Avenue, Suite 4700

Houston, Texas 77002

(713) 758-2222

Ryan J. Maierson

John J. Slater

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

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, 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, 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 that 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 this Registration Statement shall become effective on such date as the U.S. Securities and Exchange 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 the securities described herein until the registration statement filed with the U.S. Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell such securities, and it is not soliciting an offer to buy such securities, in any state or jurisdiction where the offer or sale is not permitted.

Subject to Completion, Preliminary Prospectus Dated May 4, 2026

Preliminary Prospectus

LOGO

EagleRock Land, LLC

17,300,000 Class A Shares

Representing Limited Liability Company Interests

This is the initial public offering of Class A shares representing limited liability company interests (“Class A shares”) of EagleRock Land, LLC, a Texas limited liability company (“EagleRock,” the “Company,” “we,” “us,” or “our”). We have elected to be treated as a corporation for U.S. federal income tax purposes.

We expect that the public offering price for our Class A shares will be between $17.00 and $20.00 per Class A share. We have applied to list our Class A shares on the New York Stock Exchange (the “NYSE”) and NYSE Texas, Inc. (“NYSE Texas”) under the symbol “EROK.”

Following this offering, we will have two classes of authorized equity securities outstanding: Class A shares and Class B shares representing limited liability company interests (“Class B shares” and, together with Class A shares, “common shares”). Our Class B shares have no economic rights but entitle holders to one vote per Class B share on all matters to be voted on by shareholders generally. Holders of Class A shares and Class B shares will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our LLC Agreement (as defined herein). Our outstanding Class A shares and Class B shares will represent approximately 19.2% and 80.8%, respectively, of the total voting power of our outstanding common shares immediately following this offering, assuming no exercise of the underwriters’ option to purchase additional Class A shares, with our Existing Owners (as defined herein) owning approximately 72.8% of such total voting power, without giving effect to any purchases that any of our affiliates may make through the directed share program.

We are an “emerging growth company” and a “smaller reporting company” under applicable federal securities laws and, as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. Please see the sections titled “Risk Factors” and “Summary—Emerging Growth Company and Smaller Reporting Company Status.” Immediately following this offering, our Existing Owners will collectively own approximately 72.8% of the total voting power of our outstanding common shares (or approximately 71.4% if the underwriters exercise their option to purchase additional Class A shares in full), and will agree with us, pursuant to the terms of Voting Agreements (as defined herein), to vote in favor of all director nominees recommended for election by our board of directors. As a result, we expect to be a “controlled company” within the meaning of the NYSE and NYSE Texas rules and will qualify for and intend to rely on exemptions from certain corporate governance requirements. See “Management—Status as a Controlled Company” for additional information.

Investing in our Class A shares involves risks. See “Risk Factors” beginning on page 51 of this prospectus to read about factors you should consider before investing in our Class A shares.

Neither the U.S. Securities and Exchange Commission (“SEC”) nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.


	Per Class A share	Total
Public offering price	$	$
Underwriting discount⁽¹⁾	$	$
Proceeds to EagleRock (before expenses)	$	$

(1)	See “Underwriting” for a description of compensation payable to the underwriters.

We have granted the underwriters the option to purchase, exercisable within 30 days from the date of this prospectus, up to 2,595,000 additional Class A shares from us, at the public offering price less the underwriting discounts.

At our request, the underwriters will reserve up to 10% of the Class A shares for sale at the public offering price through a directed share program to certain individuals associated with us. See “Underwriting—Directed Share Program.”

The underwriters expect to deliver the Class A shares to purchasers on or about , 2026 through the book-entry facilities of The Depository Trust Company.


Goldman Sachs & Co. LLC	Barclays	J.P. Morgan
Piper Sandler		Raymond James


Pickering Energy Partners		Stephens Inc.		Texas Capital Securities

Prospectus dated , 2026.

LOGO

TABLE OF CONTENTS


	Page
Summary		1
Risk Factors		51
Cautionary Note Regarding Forward-Looking Statements		111
Use of Proceeds		114
Dividend Policy		116
Capitalization		117
Dilution		119
Management’s Discussion and Analysis of Financial Condition and Results of Operations		121
Business		142
Management		182
Executive Compensation		189
Corporate Reorganization		200
Security Ownership of Certain Beneficial Owners and Management		202
Certain Relationships and Related Party Transactions		204
Description of Shares		212
Our LLC Agreement		215
Shares Eligible for Future Sale		225
Material U.S. Federal Income Tax Considerations for Non-U.S. Holders		228
Certain ERISA Considerations		233
Underwriting		236
Legal Matters		244
Experts		244
Where You Can Find More Information		245
Glossary of Certain Industry Terms		A-1
Index to Financial Statements		F-i

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on our behalf or the information to which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information or to make any representations different from those contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell Class A shares and seeking offers to buy Class A shares only under circumstances and in jurisdictions where such offers and sales are lawful. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of the Class A shares. Our business, liquidity position, financial condition, prospects or results of operations may have changed since the date of this prospectus.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See the sections titled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

BASIS OF PRESENTATION

This is the initial public offering of Class A shares of EagleRock. We were formed on December 1, 2025 by Lea & Eddy Holdings, LLC (“L&E”) and have not conducted and will not conduct any material business operations prior to the completion of the transactions described under “Corporate Reorganization” (such transactions, the “Corporate Reorganization”) other than certain activities related to this offering. Following the Corporate Reorganization, EagleRock will be a holding company, the sole material asset of which will consist of membership interests (“OpCo Units”) in EagleRock Land Operating, LLC, a Texas limited liability company (“OpCo”). EagleRock will also be the sole managing member of OpCo. As part of the Corporate Reorganization, (i) L&E will contribute all its subsidiaries, other than Hydrosource Logistics, LLC (“Hydrosource” or the “Excluded Assets”) to OpCo (the “L&E Contribution”), (ii) Double Eagle IV Midco, LLC (“Double Eagle”) will contribute DE IV Flow, LLC (“DE Flow”) to OpCo (the “DE Flow Contribution”) and (iii) the existing owners of the Shallow Valley Ranch (the “Shallow Valley Owners”) will contribute the entities that own Shallow Valley Ranch (“Shallow Valley”) to OpCo (the “Shallow Valley Contribution”).

The Corporate Reorganization is expected to be effected immediately prior to, and conditioned upon, the consummation of this offering. All steps comprising the Corporate Reorganization are expected to occur in connection with the closing of this offering and will be completed substantially concurrently with, but in any event prior to, the issuance of the Class A shares to the public shareholders. If this offering is not consummated, the Corporate Reorganization will not be completed. The sequencing and completion of the steps in the Corporate Reorganization may be adjusted for administrative or technical reasons, including the receipt of required consents and approvals, but such adjustments will not alter the substantive outcomes described under “Corporate Reorganization.”

Our organizational structure following the Corporate Reorganization will allow us to retain a direct equity ownership in OpCo, which will be classified as a partnership for U.S. federal income tax purposes following the offering. Investors in this offering will, by contrast, hold a direct economic and voting ownership interest in us in the form of Class A shares, and an indirect ownership interest in OpCo through our ownership of OpCo Units. Although we were formed as a limited liability company, we have elected to be taxed as a corporation for U.S. federal income tax purposes.

Pursuant to our LLC Agreement and the OpCo LLC Agreement (both, as defined herein), our capital structure and the capital structure of OpCo will generally replicate one another and will provide for customary antidilution mechanisms in order to maintain the one-for-one exchange ratio between the OpCo Units and our Class A shares. In connection with the Corporate Reorganization and this offering, each holder of OpCo Units (other than EagleRock) will receive one Class B share representing a non-economic voting limited liability company interest in us for each OpCo Unit that it holds. Accordingly, holders of the OpCo Units will have a number of votes in us equal to the aggregate number of OpCo Units that they hold. Class B shares cannot be transferred except in connection with a permitted transfer of a corresponding number of OpCo Units. Following this offering, under the OpCo LLC Agreement, each holder of OpCo Units (other than EagleRock) will, subject to certain limitations, have the right to redeem its OpCo Units (together with the cancellation of a corresponding number of Class B shares) for the same number of Class A shares, as described in more detail under “Summary—Redemption Right.” Holders of Class A shares and Class B shares will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our LLC Agreement.

For additional information, please see “Corporate Reorganization” and “Certain Relationships and Related Party Transactions—OpCo LLC Agreement.”

Throughout this prospectus, we present operational and financial information regarding the business of OpCo. This information is generally presented on an enterprise-wide basis. However, the

Class A shares to be issued to the public shareholders in this offering will initially represent a minority economic interest in OpCo. We expect that our Existing Owners and the TCW Entities will initially hold a majority of the economic interest in OpCo, as non-controlling interest holders, through their ownership of a majority of the OpCo Units and Class A shares outstanding immediately following the closing of this offering. Immediately following this offering, our Existing Owners and the TCW Entities will directly control us and, as a result, will indirectly control OpCo through their ownership of Class B shares representing greater than a majority of our outstanding equity interests. Because the Class A shares issued in this offering will initially indirectly represent a minority economic interest in OpCo, prospective investors should therefore evaluate performance metrics and financial information in this prospectus accordingly. To the extent that OpCo Units (along with a corresponding number of our Class B shares) are redeemed for our Class A shares (or, at our election, for cash) over time, the relative economic interest of EagleRock and our public shareholders in OpCo’s economic results will increase relative to that of our Existing Owners and the TCW Entities.

Financial and Operating Data Presentation

References to “EagleRock,” “we,” “our,” “us” or like terms refer collectively to (i) L&E (other than the Excluded Assets), Shallow Valley and DE Flow, together with their consolidated subsidiaries, before the completion of the Corporate Reorganization and (ii) EagleRock Land, LLC and its consolidated subsidiaries, including L&E, Shallow Valley and DE Flow, as of and following the completion of the Corporate Reorganization. Unless otherwise indicated, the historical financial information presented in this prospectus is that of L&E, our predecessor for accounting purposes.

In certain instances in this prospectus, we present financial data on a “pro forma” or “pro forma, as adjusted” basis, as applicable. As used herein and as applicable based on the periods presented, unless otherwise indicated, these references have the following meanings:

•

the term “pro forma” refers to the historical financial data of our predecessor, as adjusted to give effect to (i) L&E’s acquisition of the equity interests of Accelerated Water Resources, LLC on April 14, 2025 (such entity, “Accelerated” and such acquisition, the “Accelerated Acquisition”), (ii) the exclusion of the Excluded Assets that are not being conveyed to EagleRock, (iii) the Shallow Valley Contribution and (iv) the DE Flow Contribution (collectively, the “Pro Forma Transactions”); and

•

the term “pro forma, as adjusted” refers to the historical financial data of our predecessor, as adjusted to give effect to (i) the Pro Forma Transactions, (ii) the Up-C Reorganization (as defined herein) and (iii) this offering and the application of the net proceeds therefrom as described in “Use of Proceeds” (collectively, the “Pro Forma As Adjusted Transactions”).

Unless otherwise indicated, (i) pro forma financial data for the year ended December 31, 2025 gives effect to the Pro Forma Transactions as if each transaction had been consummated on January 1, 2025, and (ii) pro forma, as adjusted financial data for the year ended December 31, 2025 gives effect to the Pro Forma As Adjusted Transactions as if such transactions had been consummated on January 1, 2025, except that the pro forma and pro forma, as adjusted balance sheet data has not been adjusted for the Accelerated Acquisition because the predecessor balance sheet as of December 31, 2025 fully reflects the Accelerated Acquisition, which was completed on April 14, 2025. Pro forma and pro forma, as adjusted financial data contain certain reclassification adjustments to conform the historical L&E, Accelerated, Shallow Valley and DE Flow financial statement presentation to the Company’s financial statement presentation, as applicable. The pro forma and pro forma, as adjusted financial data also give effect to (i) the exclusion of the Excluded Assets and the entry into the Hydrosource Recycling Agreement (as defined herein) in connection with the L&E Contribution and (ii) the entry into the DE Flow WSMA (as defined herein) in connection with the DE Flow Contribution.

iii

The pro forma and pro forma, as adjusted financial 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 Pro Forma Transactions or the Pro Forma As Adjusted Transactions had taken place on the specified dates. In addition, future results may vary significantly from the results reflected in such pro forma and pro forma, as adjusted data and should not be relied on as an indication of future results. Please refer to our Unaudited Pro Forma Condensed Consolidated Financial Statements and the related notes thereto included elsewhere in this prospectus for additional information.

Unless otherwise indicated, all operational data in this prospectus is presented on a pro forma basis.

INDUSTRY DATA

Certain market and industry data and other statistical information used throughout this prospectus have been obtained from Enverus, an independent industry source, as well as from research reports prepared for other purposes. Some market data and statistical information contained in this prospectus are also based on management’s estimates and calculations, which are derived from our review and interpretation of publicly available industry publications, our internal research and our knowledge of the markets in which we currently operate and, as of the date of this prospectus, anticipate operating in the future. This information involves a number of assumptions and limitations, and you are cautioned not to give undue weight to such information. Forecasts and other forward-looking information obtained from these sources are subject to the same qualifications and uncertainties as the other forward-looking statements in this prospectus. While we are not aware of any misstatements regarding our industry data presented herein, our estimates involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” in this prospectus.

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 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 or SM symbols, but the omission of such references is 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 owner or licensor to these trademarks, service marks and trade names.

SUMMARY

Our Company

Access to land, resources and infrastructure is fundamental for critical industries like energy and technology to thrive. We are a land management company that owns or controls approximately 236,000 acres in the heart of the Delaware and Midland sub-basins within the prolific Permian Basin. In addition, we have an interest in up to approximately 70,000 acres pursuant to an acreage dedication related to our Midland Basin water infrastructure assets (the “DE Acreage Dedication”). Our acreage is vital to the efficient development of oil and natural gas resources in the Permian Basin and is strategically located to support the growing surface, resource, infrastructure and related commercial development needs of the power and other emerging industries in the Permian Basin.

Our assets are situated in the most active oil and natural gas development and production areas in Texas and New Mexico. The Permian Basin is regarded as the premier region for oil and gas development due to its prolific remaining resource, low break-even costs and robust network of service and infrastructure companies that support oil and gas development. The depth and quality of the remaining resource has attracted large, public and well-capitalized producers who have largely consolidated the core of the Midland and Delaware sub-basins. In turn, the abundance of economic and highly reliable energy has underpinned a number of emerging industries within the Permian Basin, including traditional and renewable power generation, transmission and storage and data centers. Our strategically located portfolio of assets provides the land and ability to construct infrastructure required for producing oil and natural gas, as well as supporting these emerging industries, which we believe will support growing and enduring revenue streams and cash flow.

Our assets are uniquely tailored to meet the needs of our customers in the distinct regulatory and operational environments in each sub-basin of the Permian Basin. Our Delaware Basin acreage sits in productive development corridors in the Permian Basin and supports water supply for drilling activity and produced water offtake, handling and recycling services to support the emerging beneficial reuse markets, generating activity-based revenue streams and royalties tied to recycled water. This position also provides abundant pore space capacity for sour gas and carbon dioxide injection (“AGI”), helping our customers mitigate the potential impact of local sour gas refining constraints and reducing flaring required by operators. In the Midland Basin, where geologic conditions are more favorable and regulatory conditions are more consistent for subsurface produced water disposal, we have valuable pore space capacity for produced water disposal in areas not affected by seismicity and over-pressurization concerns. Our acreage may also support future CO₂ pipeline development in conjunction with our pore space, which is well suited for large scale CCUS. Our Midland Basin assets also include one of the largest produced water handling and disposal systems in the Permian Basin that, under a long-term agreement with DEF Operating, LLC (“DEF Operating”), an affiliate of Double Eagle Energy Holdings IV, LLC (“Double Eagle”), one of our operating partners, underpins our ability to monetize produced water handling, disposal, recycling and beneficial reuse activities across our footprint.

operating costs or capital expenditures by us. We intend to apply this same proactive approach to attract development by emerging industries on our land. We also seek to grow organically through the expansion of existing infrastructure and operations carried out on our acreage, as well as through the identification and exploitation of new and novel uses of our land to attract new customers and strategic partners. In turn, existing and additional development on our land augments our ability to attract further incremental activities and uses, as new customers are able to utilize existing infrastructure.

Our land holdings benefit from a number of strategic contractual arrangements that provide durable revenue streams and consistent demand from our customers. These agreements are characterized by long tenors, minimum payment obligations, minimum use commitments, inflation-linked fee escalators and exclusivity provisions. For example, we are party to surface use agreements and surface use and royalty agreements (each, an “SUA”) with a number of customers that have operations on our land. Our SUAs typically include 5 to 10-year initial terms, subject to renewal, and provide us with a fee when the SUA is executed, fixed monthly or annual fees that typically escalate annually based on the Consumer Price Index (“CPI”), and often include additional fees at the beginning of each renewal period. Our SUAs also typically include pre-defined terms for additional fees that we will receive for our customers’ development and use of drilling sites, new and existing roads, pipeline easements and electric transmission easements. Many of our SUAs require our customers to use rights-of-way (“ROWs”) and easements on our land as well as the resources from our land, such as water and caliche, for their operations on our land, for which we receive additional fees. Production of oil and natural gas from the reservoirs underlying our land is expected to continue for many decades and, as a result, we expect these contracts to be renewed for an extended period of time. Furthermore, our SUAs typically include provisions that require our customers to remove their assets from and remediate our land if such agreements are not renewed, providing an incentive for our customers to continue to renew their existing agreements with us.

In addition, our Midland Basin assets include an integrated water infrastructure system (the “DE Flow System”) from which we will generate royalty revenues from the activities of our operating partner, DEF Operating, under a Water System Management Agreement (the “DE Flow WSMA”), which we will enter into in connection with this offering. The DE Flow WSMA will have an initial 10-year term, include a minimum annual royalty commitment, and will be supported by the DE Acreage Dedication. Our produced water infrastructure is capable of handling up to approximately 400 MBbls/d of produced water under long-term contracts, and includes produced water gathering systems, saltwater disposal wells (“SWDs”), water sourcing and delivery pipelines and recycling facilities.

In connection with this offering, we will also enter into a long-term produced water recycling rights agreement (the “Hydrosource Recycling Agreement”) with Hydrosource, our other operating partner, pursuant to which we will receive a royalty for, among other things, each barrel of produced water Hydrosource treats and recycles for oil and gas customers on our land and within certain designated areas outside of our land. Under the Hydrosource Recycling Agreement, Hydrosource will provide treated, blended and recycled water to customers across certain parts of our acreage. The Hydrosource Recycling Agreement will have a 10-year term with a five-year minimum royalty commitment. The Company and Hydrosource have access to supplemental off-ranch water, and the Company’s surface pipeline has the capacity to move approximately 100 MBbls/d, or approximately 36.5 MMBbls per year, of off-ranch water from Texas to its land in New Mexico. Additionally, Hydrosource has a long-term agreement that provides it with access to up to 3 MMBbls/d of produced water that can be recycled from one of the largest water disposal companies’ produced water pipeline system in New Mexico (the “Hydrosource Recycled Water Supply Agreement”), as well as other water infrastructure on our land.

As a land management company, we charge fees and royalties based on our customers’ usage of our land, assets and resources. The cost of developing our land and operating the assets in which we own interests is primarily borne by our customers and operating partners, allowing us to deploy little to no capital of our own while benefitting from the increasing use of our land, assets and resources. To promote our strategy, we collaborate commercially with our customers to support robust and efficient use of our resources to maximize returns for our shareholders. We generate revenue from multiple sources, including:

•

Resource Sales and Royalties: We receive fees when customers purchase our resources, such as water and caliche mined from our land for use in their operations. The development of oil and natural gas resources requires significant quantities of water, which are typically obtained from commercial water wells or recycling of produced water, as well as caliche for the construction of drilling pads, roads and production batteries. Under many of our SUAs, our customers are required to purchase from us or our operating partners the resources used in their operations at negotiated fees. We source water to fulfill our customers’ needs from commercial water wells on our fee lands, our operating partners and other third-party sources. Our commercial water wells in New Mexico, water infrastructure in Texas and off-ranch water from third party sources allow us to produce and sell in excess of 200 MMBbls of water per year. We sell caliche from 29 caliche mines on our land.

•

Surface Use Royalties and Revenues: We receive fees when customers use our surface acreage. Under our SUAs, we charge customers fees for land activity, including the construction of well pads, wellbores, central tank batteries, existing and new roads, electrical infrastructure, buried pipelines and reuse and frac ponds. Under our SUAs, we also generate revenue from the use of easements and ROWs by our customers. We also expect to generate long-term royalty revenue under the DE Flow WSMA from produced water handling activities in and adjacent to our land in the Midland Basin. Our produced water handling and disposal infrastructure has multiple SWD wells with significant valuable pore space in more stable geologic areas for the development of additional locations across our Midland Basin assets that our customers will be able to use for such disposal activities. Through Hydrosource and the Hydrosource Recycling Agreement, we have access to up to 3 MMBbls/d of produced water for treatment and recycling by Hydrosource and sold to customers on and off our land, from which we generate royalty revenue. We also expect to generate long-term royalty revenue under the DE Flow WSMA through its water supply and recycling activities in and adjacent to our land in the Midland Basin. In addition to generating royalty revenue from water-related activities, we have also experienced increased demand for our pore space for AGI wells in the Delaware Basin, from which we expect to generate royalty revenue. Our first AGI well is already contracted and projected to commence revenue activities within the next two years. Our largely contiguous acreage position underpins our ability to capture incremental revenue streams from sand mines, solid waste disposal facilities and other surface optimization opportunities, as well as serving as a location for development by emerging industries.

The diagram below depicts the activities that generate certain of our existing and potential future revenue streams and royalties on our surface. We do not currently engage in the activities identified as potential future activities. These activities represent opportunities we may pursue in the future but for which we have no binding agreements, committed capital or definitive development timelines. There can be no assurance that we will pursue any of these activities or that, if pursued, they will generate material revenues. Our ability to pursue these activities is subject to numerous risks and uncertainties, including regulatory approvals, market conditions, customer demand, competition, technological developments and our ability to negotiate favorable commercial terms. See “Risk Factors—Risks Related to Our Business and Operations—We may not be successful in pursuing additional commercial opportunities on our land from non-traditional energy production and other users.”

EagleRock Land Revenue

LOGO

Our business model focuses on monetizing our land, resources and water infrastructure assets through the exclusive nature of our SUAs and royalty-based strategy that minimizes our exposure to operating costs and risks and under which our customers and operating partners assume substantially all operating and capital expenditures associated with activities on our land. This structure supports the generation of significant, sustainable Free Cash Flow. The following table summarizes our financial performance for the periods shown:


	Predecessor						Pro Forma, as Adjusted
	Year Ended December 31,						Year Ended December 31,
	2024			2025			2025
	($ in thousands)
Total revenues	$	17,701		$	72,173		$	141,438
Net (loss) income	$	(1,075	)	$	(73,071	)	$	2,409
Adjusted EBITDA⁽¹⁾	$	7,350		$	35,533		$	118,581
Cash flows from operating activities	$	907		$	14,138
Capital expenditures⁽²⁾	$	(1,482	)	$	(5,252	)
Free Cash Flow⁽¹⁾	$	5,868		$	30,281
Acreage at end of period		122,132			193,875			306,136

(1)

Adjusted EBITDA and Free Cash Flow are non-GAAP financial measures. See “—Summary Consolidated Financial and Other Data” and “—Non-GAAP Financial Measures” for more information regarding these non-GAAP measures and reconciliations to the most comparable measures calculated and presented in accordance with GAAP.

(2)	Capital expenditures include costs incurred, inclusive of changes in accounts payable related to capital expenditures, for corporate office furniture and office equipment and costs incurred to install and maintain modest ancillary assets, such as ponds and pits, we own on our land.

Our Proactive Management Strategy

We believe that maximizing the efficient utilization and cash flow generation of our assets is critical to creating long-term value for our shareholders. Our proactive management strategy seeks to optimize the amount of long-term activity utilizing the same surface acreage through our land and SUAs, which entitle us to diverse revenue streams while requiring our customers and operating partners to be responsible for most operating costs and capital expenditures. We actively seek to further our operating partners’ and customers’ development of our land through the expansion of existing infrastructure and operations carried out on our land, as well as identifying novel uses of our land to attract new customers and strategic partners. Existing and additional development on our land augments our ability to attract further incremental activities as new customers are able to utilize existing infrastructure. We expect to enter into SUAs or similar agreements with new or existing customers for any incremental or novel project on our surface acreage, from which we expect to receive surface use or similar fees and other payments in connection with the use of our land or resources. In addition, we generally do not expect to own or operate any such projects or expect to incur any significant capital expenditures in connection with such projects.

We consistently evaluate opportunities to expand the uses of our land to attract customers across a variety of industries. By entering into agreements with our customers and operating partners, such as the Hydrosource Recycling Agreement and the DE Flow WSMA, our land is utilized to address new and existing customers’ needs and monetize our land and resources. For example, these arrangements allow us to scale the existing produced water disposal infrastructure on our land, with the goal of supporting the increasing demands of operators. We recently entered into an AGI and pore space lease and royalty arrangement on our land under which our customer agreed to fund the construction of the AGI wells and lease our pore space in exchange for payment of lease and royalty fees. Additionally, we believe that our large land footprint will allow us to partner with new customers to meet the growing surface, resource, infrastructure and related commercial development needs of the power and other emerging industries in the Permian Basin, which will result in incremental high margin royalty-based cash flows.

Surface Access to Land and its Resources is Critical to Efficiently Develop Energy Assets

Access to land is fundamental to upstream oil and gas development. In addition, oil and gas development and production activities consume and produce large amounts of water and utilize other land resources, such as caliche and sand. During the drilling and completion process, water is used to lubricate and cool the drill bit and remove drilling mud and rock debris. During hydraulic fracturing operations, water is mixed with sand and chemicals and pumped downhole under high pressure to fracture the producing formation. Once a well is completed and begins producing, produced water must be safely and reliably separated, transported and disposed of to maintain production continuity. Using our surface acreage, water and other land resources and produced water infrastructure, we and our operating partners are able to provide the critical resources and infrastructure needed by our customers for the efficient and reliable development of their oil and gas assets in the Permian Basin.

Our land is situated in the prolific Permian Basin, which includes both the Delaware and Midland Basins and is regarded as the premier region for oil and gas development, primarily due to its vast remaining hydrocarbon resources and low break-even costs. Our land sits atop some of the most productive areas in the Delaware and Midland Basins presenting significant oil and natural gas development potential and many decades of remaining inventory for our customers. We believe the location of our land will contribute to durable revenue streams and consistent demand from our customers. The chart below depicts the estimated remaining oil resource and basin resource life of the Delaware Basin, the Midland Basin and other notable basins, according to the U.S. Geological Survey.

Basin Resource Life Comparison

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Source: USGS, Enverus | Note: (1) Resource Life is calculated by dividing USGS Remaining Resource estimate by the trailing twelve-month production rate for the applicable basin or play. (2) Weighted average of the Resource Life of the Delaware Basin (37 years) and Midland Basin (28 years). (3) 2024/25 USGS Remaining Resource Estimates (MMBbl). (4) Other Rockies includes Powder River Basin, DJ and Uinta basins.

Oil and natural gas development in the Permian Basin generates significant and growing volumes of produced water that must be transported, treated, recycled or disposed of to sustain ongoing operations. As activity across the Permian Basin has expanded, produced water volumes have increasingly outpaced available handling and disposal capacity, creating logistical constraints that can impact drilling and completion schedules, operating costs and development efficiency. The chart below illustrates historical and forecasted Permian Basin produced water volumes relative to basin-wide operational handling capacity, underscoring the importance of surface access, infrastructure siting and proximity to disposal and recycling solutions in supporting continued development across the Permian Basin.

Permian Basin Water Volumes by Handling Method vs. Operational Produced Water Handling Capacity

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Source: B3 Insights and Pickering Energy Partners analysis as of June 30, 2025. | Note: Assumes a 20% decrease in basin-wide operational produced water handling capacity to account for logistical inefficiencies within the Permian Basin. Based on the 2023-2024 average number of new produced water handling facilities per year. Sub-plays are limited to two total produced water handling facilities and shallow production wells per section, and there are assumed to be no new shallow production wells drilled. Assumes zero new deep production wells will be drilled.

As depicted below, our land in the Delaware and Midland Basins sits atop multiple layers of stacked oil and natural gas formations, presenting significant oil and natural gas development potential and many decades of remaining inventory for our customers. These horizons represent decades of undeveloped energy resources. Successful and efficient development of these resources will be dependent on access to our land, resources and infrastructure, which allows operators to efficiently drill and complete new wells and manage high-volume produced-water throughput from those wells. We

believe that our portfolio of land, resources and infrastructure will allow us to capture significant revenues through the life cycle of our customers’ oil and gas wells.


Delaware Basin Subsurface Diagram		Midland Basin Subsurface Diagram

Source: Enverus | Note: WOR = Water to Oil Ratio. This ratio compares the amount of produced water relative to the amount of produced oil.

In addition to the large quantities of water needed during drilling and completion of a well, the production phase, which spans multiple years, requires significant produced water handling and disposal infrastructure to safely and reliably separate, transport and dispose produced water in order to maintain production continuity. The oil produced in and around our Midland Basin acreage is accompanied by significant volumes of produced water, averaging approximately 4 barrels of water per barrel of oil, or approximately 80% of total liquids produced from a typical well, according to the New Mexico Oil Conservation Division (the “NMOCD”). This water must be reliably handled in order for these wells to be brought online and remain in production, driving ongoing demand for water handling on acreage in close proximity to the operations of producers. We believe that our land resources and produced water infrastructure are well-situated to handle these large volumes of produced water.

Our produced water handling and disposal infrastructure is operated by our operating partner, DEF Operating, and underpinned by a minimum annual royalty commitment under a long-term contract with a 10-year initial term. Our produced water infrastructure is largely located in the Midland Basin, which benefits from a consistent and favorable regulatory environment and advantaged geologic conditions as compared to the Delaware Basin. Development of produced water disposal wells is regulated at the state level and is required to meet guidelines imposed by the relevant state agencies. Because the Delaware Basin is situated across the Texas–New Mexico state border, the planning, permitting and building of produced water infrastructure is dependent upon the laws and regulations of either Texas or New Mexico. Inconsistent regulations governing produced water reinjection between Texas and New Mexico

have resulted in the transmission of significant quantities of produced water from New Mexico to reinjection locations in Texas, which has led to pore space constraints and geologic issues, such as seismicity and over-pressurization, in certain areas of the Texas Delaware Basin. Meanwhile, the Midland Basin’s location entirely in Texas provides a consistent regulatory environment in addition to advantaged geologic characteristics, which results in a more evenly distributed system for reinjecting produced water across the Midland Basin. Our Midland Basin acreage is located in areas with abundant pore space, low seismicity and reduced over-pressurization concerns, and we believe that the combination of favorable geological characteristics and a consistent regulatory environment complements our existing, permitted and future produced water disposal assets.

At the same time, through our Hydrosource Recycling Agreement, we will facilitate our customers’ sustainability goals through providing treated, blended and recycled water for their operations. Through the Hydrosource Recycled Water Supply Agreement, Hydrosource has access to up to 3 MMBbls/d of produced water from one of the largest water disposal company’s produced water pipeline system in New Mexico. Through these activities, produced water that would otherwise require reinjection is treated, blended and recycled for further use in our customers’ activities. In addition to those activities, as emerging technologies develop, we believe there will be future opportunities for the beneficial reuse of water in residential and municipal, agricultural, industrial and technology, aquifer replenishment and lithium extraction applications, which could provide us with additional revenue opportunities. We evaluate new opportunities on an ongoing basis, and we believe that we are well positioned to take advantage of such opportunities given our extensive infrastructure network.

Our Assets

The map below shows our controlled acreage and selected assets in the Delaware Basin and Midland Basin.

EagleRock Assets

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Source: Enverus, US Department of Transportation

The table below contains information regarding our acreage and assets in each of the Delaware Basin and Midland Basin as of December 31, 2025.


	Combined Acres Owned/ Controlled			Commercial Water Rights and Supply Capacity (Bbls/y)			Current Above Ground Storage Capacity (Bbls)		Mining Sites		SWDs			Produced Water Handling Capacity (MBbls/d)
Delaware Basin		193,875			44,337,513			11,375,000		26		—			—
Midland Basin		112,261	⁽¹⁾		167,802,272	⁽²⁾		16,930,739		3		21	⁽³⁾		400

(1)	Includes up to approximately 70,000 acres in which we will have an interest pursuant to an acreage dedication related to our Midland Basin water infrastructure assets.

(2)	Consists of commercial on-ranch water supply of approximately 101,802,272 Bbls and sourced off-ranch water supply of 66,000,000 Bbls annually.

(3)	Total SWDs consist of 3 in-service off-ranch, 4 permitted off-ranch, 13 royalty-only on-ranch, and 1 permitted royalty-only on-ranch.

dedication related to our Midland Basin water infrastructure assets. We do not own the mineral interests that underlie our surface acreage. Our surface acreage is concentrated in two sub-basins of the Permian Basin, the Delaware Basin in New Mexico and the Midland Basin in Texas. Our critical acreage mass in these prolific sub-basins affords us with broader diversification and optionality to access unique trends in each region while also providing multiple avenues to further grow our platform. Through our land position and integrated infrastructure assets, we generate revenue and royalties from completion and production-based activities, including surface damages, ROWs, easements, commercial water supply and produced water recycling, handling and disposal and other surface and subsurface related activities by leading operators on our owned and controlled acres. As of January 2026, many of the most active operators in the Delaware and Midland Basins were actively drilling or have permits to drill on our surface acreage, including Chevron Corporation, ConocoPhillips Company, Devon Energy Corporation, Diamondback Energy, Inc., Double Eagle, EOG Resources, Inc., ExxonMobil Corporation, Matador Resources Company, Occidental Petroleum Corporation and Permian Resources Corporation. We believe these and other operators have significant remaining inventory of drilling locations to drill on our surface acreage based on information from Enverus.

The table below represents current sources of revenue for our assets in the Delaware and Midland Basins.


Activity	Region	Fee / Royalty Type
Oil & Gas Drilling and Production
Produced and recycled water handling and storage*	All regions	Fixed fee, volume-based royalty
Water sales*	All regions, Off-Ranch	Per barrel fee / royalty
Salt water disposal wells	All regions	Volume-based royalty / surface fee
Sour gas treating	Delaware	Volume-based royalty / surface fee
Roads, pads and access easements	All regions	One-time + recurring fee
Caliche	All regions	Cubic yard-based royalty

Other Land Uses
Agricultural grazing leases	All regions	Lease, fixed fee, royalty
Commercial real estate leases	All regions	Lease

Prior to this offering, produced and recycled water handling and storage have been handled by Hydrosource and DE Flow. Following this offering, water sales handling revenue will be generated through the Hydrosource Recycling Agreement and the DE Flow WSMA. Integrated water handling revenue generated from off-ranch pipeline in the Midland Basin.

The table below represents selected potential future sources of revenue for our assets in the Delaware and Midland Basins.


Potential Future Activities*	Region	Fee / Royalty Type
Oil & Gas Drilling and Production
Sand mining	All regions	Per unit royalty
Solid waste disposal	All regions	Royalty

Other Land Uses
Behind the meter power generation	All regions	Lease, royalty
Wind farm leases	All regions	Lease, royalty
Solar farm leases	All regions	Lease, royalty
Battery storage & microgrids	All regions	Lease, royalty
Data centers	All regions	Lease
Transmission lines	All regions	One-time + recurring fee
Beneficial reuse	All regions	Lease, royalty
CO₂ sequestration	All regions	Lease, royalty
Cryptocurrency mining	All regions	Lease, royalty

We do not currently engage in the activities identified as potential future activities. These activities represent opportunities we may pursue in the future but for which we have no binding agreements, committed capital or definitive development timelines. There can be no assurance that we will pursue any of these activities or that, if pursued, they will generate material revenues. Our ability to pursue these activities is subject to numerous risks and uncertainties, including regulatory approvals, market conditions, customer demand, competition, technological developments and our ability to negotiate favorable commercial terms. See “Risk Factors—Risks Related to Our Business and Operations—We may not be successful in pursuing additional commercial opportunities on our land from non-traditional energy production and other users.”

Delaware Basin Assets

Delaware Basin Land

As of December 31, 2025, we owned or controlled approximately 194,000 acres in and near the core of the Delaware Basin in New Mexico. Our acreage spans across four parcels in Lea and Eddy Counties, New Mexico, which we refer to as the Desert Ram North, Desert Ram South, Limestone and Basin Ranches.

Our Delaware Basin acreage is shown below, together with the estimated ultimate recovery (“EUR”) per foot of lateral length (“EUR/ft”) of producing wells, according to Enverus, as of January 2026. EUR is the total amount of oil and natural gas expected to be recovered over the life of active wells. For comparability purposes, we show EUR/ft because lateral lengths vary, and wells with longer lateral lengths tend to have higher EUR/ft.

Estimated Ultimate Recovery (EUR)

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Source: Enverus

Our Delaware Basin acreage encompasses approximately 37,000 acres of fee land, approximately 64,000 acres of state leased land and approximately 92,000 acres of federal leased land for a total of approximately 194,000 combined acres. This largely contiguous acreage position provides us control to support customers and their operations and allows us to optimize our revenues within the perimeter of the controlled acreage.

Our Delaware Basin land generates revenue primarily by charging fees and royalties for resource sales and surface use and damages. Under our SUAs with operators, substantially all customers that operate on our fee acreage, and in certain instances our controlled surface acres, are obligated to purchase all available resources from us, including water and caliche. In addition, our Delaware Basin acreage has substantial mining operations, including 26 sites for selling caliche and topsoil to various oilfield service providers.

On our Delaware Basin land, we have access to up to 80.8 MMBbls of water per year from various sources. Our commercial water permits with the state of New Mexico permit us to produce and sell up to 44.3 MMBbls of commercial water per year. Our Delaware Basin land possesses a unique geologic water feature under the San Simon Sink, which holds substantial water reserves, and we have an existing lay-flat pipeline from the Texas border to one of our Delaware Basin land positions, along with additional storage infrastructure, that allows us to access an additional 36.5 MMBbls of commercial water per year. Furthermore, we have access to purchase similar off-ranch water volumes from several other suppliers, including the right to obtain up to 3 MMBbls/d of produced water, that may be treated, recycled and supplied to customers. Our Delaware Basin land has approximately 11.4 MMBbls of above ground water storage capacity and operates several trucked water stations that can constantly be refreshed from our water wells, helping us maintain efficiency and flowrate to our customers.

Additionally, our Delaware Basin land has a permit for what would be the fourth largest solid waste facility in the Permian Basin with over 21 million cubic yards of capacity, strategically located in an area of the Delaware Basin that has extensive development opportunities and many decades of remaining inventory, which we believe has the potential to drive future organic revenue growth for us. Under our Hydrosource Recycling Agreement, Hydrosource will have the exclusive right for two years following this offering to develop that facility and, if developed, we expect to receive a royalty equal to approximately 10% of the facility’s revenues. Furthermore, we believe our Delaware Basin land has a significant amount of commercially potent frac sand in areas proximate to upstream development, thereby reducing transportation costs and associated risks.

Activity on our Delaware Basin acreage has remained resilient and continues to capture a growing share of Lea and Eddy Counties’ drilling activity, even as commodity prices have declined. The chart below shows the percentage of total rigs operating in Lea and Eddy Counties that are located on EagleRock acreage each quarter. For example, in the fourth quarter of 2025, approximately 91 rigs were active across Lea and Eddy Counties, of which 20 rigs were operating on EagleRock acreage, representing approximately 22% of total regional activity. Notably, EagleRock’s share of active rigs increased from the mid-teens to over 20% during 2025, demonstrating sustained and growing operator activity on our acreage even during commodity price downturns. In the first quarter of 2026, the rig activity on our Delaware Basin acreage represented 17%, in line with the median share of regional rig activity since 2024.

EagleRock Share of Rigs in Lea & Eddy Counties

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Source: Enverus, EIA

We believe our Delaware Basin land has significant potential for future activity, supported by 558 active horizontal drilling permits from various operators on our controlled acreage. According to NSAI, as of December 22, 2025, approximately 12,743 identified well locations across four formations exist within a 10-mile radius of our surface acreage in our Delaware Basin land. We own approximately 37,000 acres of fee land in New Mexico, and we control approximately 157,000 acres of land through our grazing and mining leases with the State of New Mexico and the Bureau of Land Management (“BLM”). Our leasehold interests in New Mexico state lands are generally grazing and mining leases that grant us rights with respect to the surface for periods ranging from one to five years from inception, and are renewable on an annual basis at our discretion. Under New Mexico law, the holder of an easement or right-of-way is required to compensate the lessee for the reasonable value of any measurable damage incurred upon improvements or other property belonging to the lessee. As the agricultural lessee, we have leased possession and use of the grazing interest. When the surface is excavated or occupied by a surface use implemented by a third party, we receive payments to compensate us for the impairment of value and costs to repair the physical damage. Additionally, our leasehold interests in federal lands with the BLM are

generally grazing leases that grant us rights with respect to the surface for a period of approximately 10 years from inception. As part of our land management strategy, we leverage our total acreage footprint in driving our resource sales through our SUAs to our customers. Where our SUAs grant exclusive rights for commercial resources over land we control, the terms of those SUAs extend to leased land, and our customers are obligated to purchase resources such as water and caliche from us.

Delaware Basin Infrastructure

Our Delaware Basin infrastructure consists of a number of pipelines, pits, ponds and other storage systems used to facilitate our resource sales at strategic points within and around our Delaware Basin acreage. Additionally, our acreage contains significant third-party infrastructure, which facilitates our customers’ activity on our land. The map below illustrates our owned and controlled acreage and infrastructure in the Delaware Basin, and other oil and gas activities in the Delaware Basin.

EagleRock Delaware Basin Assets

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Source: Enverus

The Delaware Basin is characterized by high water production and high water to oil ratios (“WORs”) across formations, which results in significantly more produced water as a byproduct of production activities. Produced water originating in New Mexico generally must be transported to reinjection locations in Texas for disposal or recycled for use in drilling and completion activities. Our Hydrosource Recycling Agreement will position us to meet our customers’ demand for treated, blended and recycled water through Hydrosource’s water recycling infrastructure. Under the Hydrosource Recycling Agreement, we will earn a royalty for each barrel of produced water Hydrosource treats and recycles for oil and gas customers on our land. Our Delaware Basin water infrastructure assets are proximate to areas of high WORs, as depicted in the map below.

Water to Oil Ratios in the Delaware Basin

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Source: Enverus

In addition to oil and gas activity, we believe our Delaware Basin land has significant potential for future electricity transmission development, which we believe will attract new customers to our land as access to electricity increases. For instance, Oncor Electric Delivery Company (“Oncor”) is in the process of developing a 765kV transmission line that is expected to traverse portions of our Delaware Basin acreage, which we anticipate will result in fees for the related easement across our land. In addition, we believe the availability of reliable power connectivity will further expand the uses of our land and allow us to attract new customers. Oncor anticipates the transmission line, if approved by regulators, will be energized by December 2028.

Additionally, the United States Department of Energy is considering designating land that crosses our acreage as a National Interest Electric Transmission Corridor (the “Transmission Corridor”). The map below shows the Transmission Corridor’s extent in Lea and Eddy County with proximity to our Delaware Basin land. We believe any future development of the Transmission Corridor could significantly increase the value and alternative uses of our surface.

EagleRock Delaware Basin Acreage and Transmission Corridor

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Midland Basin Assets

Midland Basin Land

As of December 31, 2025, we owned approximately 42,000 acres in the Midland Basin, which is further supplemented by the DE Acreage Dedication. The Midland Basin benefits from a favorable regulatory environment, extensive midstream connectivity and access to power and transportation infrastructure, which, together with its extensive, deep inventory of drilling locations, make the Midland Basin one of the most prolific areas for ongoing energy development and infrastructure investment. Our Midland Basin acreage spans across owned parcels in Martin, Howard, Reagan, Glasscock and Upton Counties in Texas.

Our Midland Basin land generates recurring revenue from long-term SUAs, water resources and produced water handling and disposal, caliche royalties, surface leases and infrastructure easements supporting upstream, midstream, downstream and power development, and it complements our Delaware Basin acreage by adding scale, geographic balance and exposure to geologic formations that are more conducive to produced water reinjection as compared to our Delaware Basin acreage. Our Midland Basin land has approximately 300 MBbls of refresh flowrate per day or approximately 102 MMBbls per year of commercial water, and a water storage capacity of 16.9 MMBbls, including 5.5 MMBbls of off-ranch storage capacity. Our Midland Basin acreage also benefits from its proximity to Midland and Odessa, Texas, its proximity to the Interstate 20 corridor and several contiguous development corridors. Our Midland Basin land hosts critical ROWs, easements and fee tracts that support ongoing pad development, pipeline construction, power transmission and data infrastructure buildout for both energy and industrial applications in Texas.

Our Midland Basin land also hosts wind lease options with a potential combined 379 MW build-out, which would be supported by a base lease rate and royalty structure, with minimum

projected lease revenue terms of 36 years. Additional income sources from our Midland Basin land include resource sales to customers operating within a certain mile-radius from our land and incremental royalty revenues from our infrastructure in and adjacent to our Midland Basin land that are operated by our operating partner, DEF Operating.

Midland Basin Infrastructure

Our Midland Basin assets also include water supply and produced water infrastructure in and adjacent to our Midland Basin land. Our infrastructure consists of a number of SWDs, water storage facilities, water wells and water pipelines used to facilitate delivery of water for drilling and completion activities, and the handling and disposal of produced water. Our water infrastructure that is adjacent to our Midland Basin acreage position is operated by one of our operating partners, DEF Operating, from which we receive royalty revenue under a long-term contract with a 10-year term and minimum annual royalty commitments. We also expect to receive royalties from Hydrosource in connection with its recycling of produced water sold in and around our land in the Midland Basin. Our produced water infrastructure, with peak handling capacity of approximately 400 MBbls/d, is strategically located in the Midland Basin, which benefits from access to abundant pore space, a favorable regulatory environment and advantaged geologic characteristics. Our supply water and produced water infrastructure portfolio serves numerous major operators, including large, well-capitalized producers with durable development programs, and is supported by 42,000 of our owned acres and the DE Acreage Dedication. The presence of these operators underscores the strategic importance of our assets and presents opportunities to capture incremental revenue streams as development activity continues.

The map below illustrates our acreage and material assets in the Midland Basin.

EagleRock Midland Basin Assets

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Source: Enverus

The Midland Basin is also characterized by high levels of water production across formations. While the Midland Basin’s primary producing formations generally have lower water production and WORs, its upside formations have comparatively higher water production and WORs, which would result in significantly more produced water as a byproduct of production activities over time. Our produced water handling and disposal infrastructure has multiple SWD wells with significant valuable pore space in more stable geologic areas for the development of additional locations across our Midland Basin assets, which will enable us to meet customers’ growing demands for produced water disposal. Our Midland Basin water infrastructure assets are proximate to areas of high WORs, as depicted in the map below.

Water to Oil Ratios in the Midland Basin

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Source: Enverus

concentrated within these high-quality geologic corridors, positioning us to benefit from continued development activity and long-term inventory depth in one of the most attractive oil-weighted regions in North America. The graphic below depicts the EUR/ft of lateral length from oil and natural gas wells on and near our land position, according to Enverus, as of January 2026.

Estimated Ultimate Recovery (EUR)

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Source: Enverus

Our Business Model

diversified group of large, well-capitalized producers and customers. We believe our predominantly fee-based SUAs, along with long-term royalty agreements with minimum annual revenue commitments, will facilitate stable cash flows through a variety of commodity price cycles.

Our Relationship with Our Operating Partners

Our relationships with our operating partners, DEF Operating and Hydrosource, allow us to focus on our land management strategies while we continue to realize the benefits of the available resources and long-term development opportunities on and around our land.

The DE Flow WSMA and Hydrosource Recycling Agreement described below are new agreements that will be entered into in connection with this offering. While the businesses we are acquiring (including DE Flow and Shallow Valley Ranch) have historically generated revenues from water-related activities, the royalty revenue structure described in this prospectus reflects the terms of these new agreements, which will supersede any prior arrangements and govern our relationship with DEF Operating and Hydrosource on a go-forward basis.

Double Eagle

Double Eagle is an independent oil and natural gas company focused on development and production throughout the Permian Basin. The company is backed by equity capital commitments from EnCap Investments L.P. (“EnCap”), Double Eagle Management and other strategic investors. Double Eagle continues to pursue acquisitions and ambitious development programs in the Permian Basin, supported by its strategic partnership with EnCap, strong cash flows through operations, as well as available debt facilities. Additionally, Double Eagle has historically maintained consistent drilling activity through a variety of commodity price cycles, supported by its private ownership structure and flexible capital base.

DEF Operating is a subsidiary of Double Eagle and will be a key operating partner of ours focused on providing critical water infrastructure across all phases of oil and gas development for Double Eagle and neighboring operators. Our DE Flow WSMA will be structured to provide long-term, predictable, largely commodity price-insulated cash flows through fixed-fee and royalty constructs tied to oil and gas activity on the Double Eagle operated acreage footprint. Our relationship will be anchored by a long-term agreement with an initial term of 10 years and minimum annual royalty commitments, which is expected to provide predictable cash flows. DEF Operating’s activities on and around our acreage have historically supported recurring surface royalties under long-term contracts with acreage dedications from the operators.

Hydrosource

Hydrosource is focused on water management and permitting solutions. Our relationship with Hydrosource will support land development, including management of water logistics for completions, recycling and other strategic long-term capital investments that will further optimize the development of our acreage. As our strategic water recycling partner, Hydrosource will promote and manage the sale of treated, blended and recycled water across our land and area of mutual interest to meet the demands of customers, from which we will earn royalties. Additionally, Hydrosource has access to up to 3 MMBbls/d of produced water under the Hydrosource Recycled Water Supply Agreement with one of the largest, well-capitalized produced water disposal companies in New Mexico through 300 access points along such company’s midstream assets co-located on our acreage. Hydrosource currently maintains 1 MMBbls/d of water recycling capacity, and the modular design of its recycling system allows it to move assets and expand capacity.

Our Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our business objectives.

Balanced portfolio with strategically located assets in both the Delaware and Midland sub-basins.

Our diversified portfolio is balanced across the Permian Basin’s two prolific sub-basins, the Delaware Basin in New Mexico and the Midland Basin in Texas, which are the most active and inventory-rich development basins in North America. During the fourth quarter of 2025, oil and gas production from the Permian Basin represented approximately 46% of U.S. lower 48 states production. Large, well-capitalized public and private operators, including Chevron Corporation, ConocoPhillips Company, Devon Energy Corporation, Diamondback Energy, Inc., Double Eagle, EOG Resources, Inc., ExxonMobil Corporation, Matador Resources Company, Occidental Petroleum Corporation and Permian Resources Corporation, operate numerous locations and have a large undrilled inventory of locations on our land, and numerous other large operators frequently utilize our water infrastructure assets, both of which generate royalty revenue streams and contribute to the strength of our portfolio and durability of our revenue streams. Our expansive land footprint and available resource offerings across the Permian Basin also position us to take advantage of future growth opportunities in emerging industries such as power generation, transmission and storage, data centers and associated infrastructure.

Our Delaware Basin surface acreage is located in the core of the Delaware Basin’s lowest cost and most prolific remaining oil and natural gas resources and is primarily operated by large, well-capitalized public operators. The nature of our SUAs and other similar agreements and largely contiguous acreage positions us to benefit from the ongoing development of these resources through royalties that are not directly impacted by commodity prices. Our primary revenue streams on our Delaware Basin land are not directly dependent on access to SWD wells and produced water takeaway systems that may be impacted by potential constraints, including produced water pore space limitations, over-pressurization of subsurface reservoirs and regulatory risks. Instead, a meaningful portion of our Delaware Basin revenue streams result from water and resource sales, including from the beneficial reuse of produced water following treatment and recycling by Hydrosource, with the potential for our pore space to be utilized for AGI.

On our Midland Basin acreage, where regulatory and geologic conditions are more favorable, we have abundant pore space to support our existing SWDs and the development of multiple additional SWDs to support our customers’ growing produced water demand. Our Midland Basin assets also offer diversified exposure to future upstream development through both water resources supply and produced water handling as well as non-oil and gas revenue streams, including potentially from wind leases with a combined 379 MW build-out. Among upstream-related activities, these assets derive a significant portion of their revenue from many large, well-capitalized operators and have balanced exposure to both production and development activity. In addition, our Midland Basin land generates royalties from power infrastructure and other supporting infrastructure development on our land.

Diverse revenue streams underpinned by a large percentage of fee-based royalties and surface use agreements.

Our business model is built on recurring, contracted, long-term, fee-based revenue streams with a diverse group of large, well-capitalized producers and other customers tied to surface use of our

land. We generate revenue from granting ROWs, easements and rights to conduct surface use activities, sourcing and delivering water for completions, handling, transporting, recycling and disposing of produced water, AGI pore space leases and providing access to mining sites for the sale of caliche and topsoil to customers. Many of our SUAs allow us to be the exclusive provider of our resources to upstream operators on our fee land, as well as select lands we control. We will also generate revenue under our Hydrosource Recycling Agreement and DE Flow WSMA when our customers utilize our and our operating partners’ water infrastructure assets, which, in the Midland Basin, will be supported by long-term acreage dedications. These activities support multiple sources of revenue, which are not directly impacted by commodity price volatility and require minimal ongoing operating or maintenance expenditures from us.

Hydrosource’s long-term contracted access to produced water and technical expertise positions us for significant long-term value creation. While beneficial reuse of produced water remains in the conceptual and early-development phase, we believe it holds meaningful economic potential over the coming years. Emerging applications include residential and municipal use, agricultural irrigation, industrial and technology-sector demand, aquifer replenishment and lithium extraction. Together, these opportunities represent a transformative pathway for converting produced water into a scalable, revenue-generating resource.

Multiple potential uses of land, including power and technology, to create long-term revenue streams.

Industrial activity on our land requires the development of infrastructure, which in turn can be used to support a variety of uses beyond the current activity. Our proactive management strategy seeks to optimize the amount of activity utilizing the same surface acreage on our land over the long-term. As a land management company, we facilitate development of our land and resources by seeking to expand existing infrastructure and operations on our land through frequent engagement with our customers, identifying novel uses of our land and resources and attracting potential customers and operating partners to develop new projects on our properties. Additionally, we believe our land is well suited for our entrepreneurial management team to work with customers to provide dedicated surface acres for data center infrastructure, power generation, transmission and storage facilities and related commercial development, which will improve our high margin royalty-based cash flows. In turn, the development on our land augments our ability to attract incremental activities as new customers make use of existing infrastructure. For example, as roads, power and other infrastructure are developed on our acreage, subsequent development by other customers is facilitated.

We generate a significant portion of our cash flows under long-term contracts with customers and operating partners. In the Midland Basin, we expect to generate significant cash flows under our DE Flow WSMA with DEF Operating that will provide for minimum annual royalty payments from our water infrastructure system, which will include supply water sales and produced water handling and disposal. This system is supported by long-term acreage dedications with Double Eagle, which continues to be one of the most active private operators in the Midland Basin. Double Eagle has a proven track record of continuing to develop oil and gas assets in a variety of commodity price environments due to its private ownership structure and flexible capital base. The expansive DE Flow water system allows connections with third parties for continued growth as well. Our Midland Basin water infrastructure system is located in an area with low seismicity, which allows the water infrastructure system to maintain its quality through consistent water sales and produced water handling and disposal. We believe there is significant remaining inventory with attractive break-even economics that will continue to support this asset and our royalty-based revenue stream for the long term. Similarly, our Hydrosource Recycling Agreement will generate consistent revenue and cash flow from the sale of water to producers across all of our acreage and will include a five-year minimum royalty commitment.

In addition to the commercial uses of our land, we retain three partners to oversee an over 1,150 head cattle grazing operation on our land in New Mexico. As a part of these operations, we seek to operate to benefit our land and its wildlife and to partner with local government and other groups to further these goals.

We have an entrepreneurial management team with a track record of building businesses and creating value.

Our management team has several decades of combined experience in the energy industry, with a proven history of value creation specifically in the Permian Basin.

Our management team has sought, and continues to seek, opportunities to efficiently commercialize and optimize our land position. Since commencement of our operations in 2024, our management team has successfully acquired and/or integrated approximately 200,000 acres and the related land management operations, while actively unlocking incremental value by increasing the overall combined profitability of those operations, while also creating or identifying new sources of revenue with minimal capital investment. In addition, we have:

•

consolidated fragmented SUAs with various customers while renegotiating key commercial terms that increased revenue activities on our land;

•

increased our revenue stream through the 15-year, Hydrosource Recycled Water Supply Agreement between Hydrosource and one of the largest produced water disposal companies in New Mexico that allows us and our operating partners access to up to 3 MMBbls/d of produced water that can be treated and/or recycled by Hydrosource and sold to customers on and off our land;

•

increased our land footprint to approximately 236,000 acres across the Permian Basin, which is further supplemented by the DE Acreage Dedication, through the strategic combination of the L&E, Shallow Valley and Double Eagle assets as part of this offering, with the goal of developing one of the largest land management companies that supports oil and gas development in the Permian Basin; and

•

achieved the above strategies while maintaining a strong balance sheet.

Our Business Strategies

Our principal business objective is maximizing risk-adjusted total return to our shareholders by growing Free Cash Flow with minimal capital expenditures and operational risks. We intend to pursue the following business strategies to achieve this objective.

Increase cash flow per share and generate differentiated returns for our shareholders.

We intend to sustainably grow cash flow per share for our shareholders. Because our business model is largely fee-based and capital-light, we expect to generate significant Free Cash Flow relative to our capital investment needs. We believe focusing on per-share cash flow, rather than simply growing volume, aligns our strategy with long-term shareholder returns. We intend to grow per-share cash flow by pursuing high return growth opportunities. We also intend to seek to return capital to our shareholders through dividends, although we have not established a formal dividend policy.

Promote efficient development of our assets through both existing and novel approaches to utilize our land and resources.

We will continue to actively manage and develop our acreage to maximize revenue and identify higher and better uses of our land. We intend to continue to grow our existing diversified revenue streams, which currently include royalties and fees from upstream operations on our acreage, royalties from water recycling and produced water handling and treatment and revenues from the sale of surface resources such as caliche. In addition, through the combination of L&E, Shallow Valley and Double Eagle assets as part of this offering, we will pursue new opportunities to enhance the use of our resources both across the combined footprint and among our operating partners. We also believe revenue generation opportunities exist from ancillary surface use activities, such as sand mining, solid waste disposal and pore space leases. We believe that our ability to offer a single commercial interface for land access, water sourcing and produced water logistics is a competitive advantage that reduces downtime and cost for operators, making our acreage the preferred platform for multi-year development programs for operators. Additionally, the water recycling services offered by our operating partners on our land provide our operators with access to a commercial solution to assist them with managing increasing produced-water volumes, as well as the ability to meet their individual sustainability goals. We will also seek to further develop and grow our non-oil and gas revenue streams, which we believe include traditional and renewable power generation, transmission and storage and data center infrastructure. Our goal is to efficiently increase revenue by maximizing fee-generating activities on the same land while minimizing permitting friction for our customers.

Pursue accretive acquisitions to enhance our asset base.

We intend to reinvest our cash flow accretively into our business by evaluating and pursuing selective acquisitions, potentially including acquisitions from the Existing Owners, that are complementary to our strategy and pursuing our capital-light development strategy on acquired acreage to increase our stable cash flow base. For example, Hydrosource recently acquired approximately 50,000 surface acres in Lea County, New Mexico that is proximate to our existing land holdings in the Delaware Basin. While no agreement or understanding exists between us and Hydrosource with respect to our acquisition of that acreage and no assurance can be given that any such agreement may be reached in the future, we may seek to acquire such acreage from Hydrosource. We intend to target opportunities that create near-term cash flow from the use of our surface acreage and can be quickly commercialized through our existing contract structure without significant incremental capital. We believe disciplined expansion of our land position can unlock new revenue opportunities and strengthen our strategic positioning in the sector. We intend to remain selective and pursue transactions that we believe will be accretive to cash flow per share.

Maintain a prudent balance sheet with capital flexibility.

We intend to maintain a prudent financial profile to preserve strategic flexibility. Our asset-light model allows us to support customer activity without large upfront capital requirements to support development of our acreage. We expect to maintain our balance sheet strength to continue investing in commercializing and optimizing our existing land position, pursue strategic, high-return bolt-on opportunities and return capital to shareholders, including through payment of dividends and/or opportunistic repurchases. Our strategy will continue to focus on growing our land position, a non-depreciable asset, with significant economic cash flow generation for multiple years. We believe maintaining balance sheet discipline positions us to act opportunistically in a basin where surface access, water logistics rights and ROW control are increasingly valuable to operators.

Capitalize on our relationship with Hydrosource and DEF Operating to increase revenue.

Our operating partners, Hydrosource and DEF Operating, operate integrated water midstream systems in the Delaware Basin and Midland Basin. These assets include over 140 miles of pipeline and 6 produced water handling facilities capable of handling over 400 MBbls/d of produced water. Additionally, Hydrosource has access to up to 3 MMBbls/d of produced water under the Hydrosource Recycled Water Supply Agreement.

Our DE Flow System is designed for operational redundancy, customer flow assurance and recycling and redelivery across our Midland Basin position, and we believe it is a leader among the next generation of water handling facilities, including water recycling, enhanced evaporation and desalination facilities, which could potentially provide incremental surface use revenues and water sales royalties to us.

Our relationships with DEF Operating and Hydrosource allow us to focus on our land management strategies while we continue to realize the benefits of the available resources and long-term development opportunities on and around our land. We expect to grow organically alongside Hydrosource and DEF Operating as they increase operational capacities on our surface acreage. For each incremental barrel of sourced or produced water recycled by Hydrosource on our land, we will earn additional revenue while investing minimal capital. We have also been issued a permit to place a solid waste facility on our land, and Hydrosource has a two-year option to develop that facility. Additionally, should we choose to acquire additional surface acreage, we may be able to enhance returns by entering into additional commercial agreements with Hydrosource and/or Double Eagle when our respective business interests align.

Corporate Reorganization

EagleRock was formed as a Texas limited liability company by L&E on December 1, 2025. EagleRock has elected to be treated as a corporation for U.S. federal income tax purposes. EagleRock has not conducted and will not conduct any material business operations prior to the completion of the Corporate Reorganization, other than certain activities related to this offering.

Following the Corporate Reorganization, EagleRock will be the sole managing member of OpCo, will be responsible for all operational, management and administrative decisions relating to OpCo’s business and will consolidate financial results of OpCo and its subsidiaries. OpCo will own all of the outstanding membership interests in our operating subsidiaries and will operate our assets through these various subsidiaries.

In connection with the completion of this offering, the following transactions have occurred, or will occur, in substantially the following order, which are collectively referred to in this prospectus as our “Corporate Reorganization”:

•

OpCo will be formed by EagleRock;

•

Each of L&E, the Shallow Valley Owners and Double Eagle (collectively, the “Existing Owners”) will contribute cash to EagleRock in exchange for 109,725,365 Class B shares;

•

L&E will contribute all of its subsidiaries (other than the Excluded Assets) to OpCo in exchange for 42,716,907 OpCo Units and OpCo’s assumption of the Predecessor Credit Facility (as defined herein);

•

Each of the Shallow Valley Owners and Double Eagle will contribute certain of their subsidiaries to OpCo in exchange for 21,134,393 OpCo Units and 45,874,065 OpCo Units, respectively;

•

Each of EagleRock’s and OpCo’s operating agreements will be amended and restated to facilitate this offering (the transactions set forth in this and the second bullet point above being the “Up-C Reorganization”);

•

Pursuant to a Warrant Exercise Agreement (the “Warrant Exercise Agreement”), each holder of L&E Warrants (including funds and accounts managed by TCW Asset Management Company LLC (“TCW”)), CCLF Holdings (D41) LLC and AWC Aqua, LLC (collectively, the “TCW Entities”) will exercise a portion of its L&E Warrants to purchase L&E units (the “Exercised Warrants”) and forfeit the remaining portion of such warrants (the “Forfeited Warrants”), which will be irrevocably cancelled, immediately following which (i) L&E will distribute 14,940,269 OpCo Units and a corresponding number of Class B shares to the TCW Entities in redemption of the L&E units received in respect of the Exercised Warrants, (ii) each Warrant Agreement will terminate and (iii) certain of such TCW Entities (the “Rollover TCW Entities”) will merge with one or more newly formed subsidiaries of EagleRock and receive one Class A share in exchange for each OpCo Unit (and Class B share) it holds, or an aggregate 4,560,785 Class A shares;

•

EagleRock will issue 17,300,000 Class A shares in this offering to the public, representing 100% of the economic rights in EagleRock, in exchange for the net proceeds of this offering at a price of $18.50 per Class A share (the midpoint of the price range set forth on the cover page of this prospectus);

•

EagleRock will contribute all of the net proceeds from this offering (including any net proceeds from the exercise of the underwriters’ option to purchase additional Class A shares) to OpCo in exchange for a number of OpCo Units equal to the number of Class A shares issued in this offering; and

•

OpCo will use the net proceeds (including any net proceeds from the exercise of the underwriters’ option to purchase additional Class A shares) from this offering, as described in “Use of Proceeds.”

To the extent the underwriters’ option to purchase additional Class A shares is exercised in full or in part, EagleRock will contribute the net proceeds therefrom to OpCo in exchange for an additional number of OpCo Units equal to the number of Class A shares issued pursuant to the underwriters’ option. OpCo intends to use such proceeds as described in “Use of Proceeds.”

After giving effect to the Corporate Reorganization, this offering and assuming the underwriters’ option to purchase additional Class A shares is not exercised:

•

our Existing Owners and the TCW Entities will own all 105,164,580 of our Class B shares (with 27,776,638 Class B shares held by L&E, 45,874,065 Class B shares held by Double Eagle, 21,134,393 Class B shares held by the Shallow Valley Owners and 10,379,484 Class B shares held by the TCW Entities), and the Rollover TCW Entities will own 4,560,785 of our Class A shares, collectively representing 84.3% of our common shares (or 21.3% held by L&E, 35.3% held by Double Eagle, 16.2% held by the Shallow Valley Owners and 11.5% held by the TCW Entities);

•

investors in this offering will own 17,300,000 of our Class A shares, representing 13.3% of our common shares;

•

EagleRock will own an approximate 19.2% interest in OpCo; and

•

our Existing Owners and the TCW Entities will own an approximate 80.8% interest in OpCo, including the indirect interest in OpCo owned by the Rollover TCW Entities (or 21.3% held by L&E, 35.3% held by Double Eagle, 16.2% held by the Shallow Valley Owners and 8.0% held by the TCW Entities).

The diagrams under “—Organizational Structure” below depict a simplified version of our organization and ownership structure immediately before and after giving effect to this offering and the Corporate Reorganization.

For further details regarding the L&E Warrants, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Predecessor Liquidity and Capital Resources—L&E Warrants.”

For further details on our agreements with OpCo and its affiliates, please see “Certain Relationships and Related Party Transactions.”

Recent Developments

Preliminary First Quarter 2026 Financial Results

The following preliminary financial information presents our estimated financial results on a pro forma, as adjusted basis for the three months ended March 31, 2026. This presentation includes ranges for these preliminary financial results because closing procedures for the three months ended March 31, 2026 are not yet complete. These estimated ranges are preliminary and unaudited and are thus inherently uncertain and subject to change.

As customary quarterly close and review procedures as of and for the three months ended March 31, 2026 are completed, there can be no assurance that the final results for this period will not differ from the estimates presented below. During the course of the preparation of our consolidated financial statements and related notes as of and for the three months ended March 31, 2026, we may identify items that could cause our final reported results to be materially different from the preliminary financial estimates presented below. For a discussion of important factors that could cause actual results to differ from our preliminary estimates, see “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

These estimates should not be viewed as a substitute for full interim financial statements prepared in accordance with GAAP. In addition, these preliminary estimates are for informational purposes only and are not necessarily indicative of the results to be achieved as of any future date or for any future period. The preliminary estimated unaudited financial results included in this prospectus have been prepared by, and are the responsibility of, our management. Our independent registered public accounting firm, Deloitte & Touche LLP, has not audited, reviewed, compiled or performed any procedures with respect to the preliminary financial results. Accordingly, Deloitte & Touche LLP does not express an opinion or any other form of assurance with respect thereto.

Set forth below is a range of estimates of our preliminary financial results for the three months ended March 31, 2026 on a pro forma, as adjusted basis:


	Pro Forma, as Adjusted
	Three Months Ended March 31, 2026
(in thousands)	Low		High
Revenue	$	29,551	$	36,117
Net income	$	13,263	$	16,211
Adjusted EBITDA	$	25,745	$	31,467

The following table sets forth a reconciliation (to the midpoint of the low and high ranges set forth above) of our preliminary net income (loss) as determined in accordance with GAAP to Adjusted EBITDA and Adjusted EBITDA Margin for the periods indicated.


	Pro Forma, as Adjusted
($ in thousands)	Three Months Ended March 31, 2026
Net Income (loss)	$	14,737
Adjustments:
Depreciation, depletion, amortization, and accretion		13,634
Interest expense, net		96
Income tax expense (benefit)		1,033

EBITDA	$	29,500

Adjustments:
Transaction-related expenses⁽¹⁾		2,386
Other⁽²⁾		(3,280	)

Adjusted EBITDA	$	28,606

Net income (loss) margin		44.9	%
Adjusted EBITDA Margin		87.1	%

(1)

Transaction-related expenses consist of nonrecurring professional services expenses, including banker fees, legal and professional fees and integration costs directly attributable to completed or contemplated transactions. We do not adjust for ongoing integration or optimization costs unless they are incremental, non-recurring and directly attributable to the transaction.

(2)	Other consists primarily of a nonrecurring gain on sales-type lease and other nonrecurring transactions.

Our Common Shares

Our Second Amended and Restated Company Agreement (the “LLC Agreement”) will provide for two classes of common shares, Class A shares and Class B shares, representing limited liability company interests in us. Only our Class A shares will have economic rights and entitle holders thereof to participate in any dividends our board of directors may declare. Each holder of a Class A share will be entitled to one vote on all matters to be voted on by our shareholders generally. We have applied to list our Class A shares on the NYSE and NYSE Texas under the symbol “EROK.”

Class B shares will not be entitled to participate in any dividends our board of directors may declare but will be entitled to vote on the same basis as the Class A shares. Holders of Class A shares and Class B shares will vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our LLC Agreement. We do not intend to list the Class B shares on any stock exchange. All of our Class B shares will initially be owned by our Existing Owners and the TCW Entities. For a description of the rights and privileges of shareholders under our LLC Agreement, including voting rights, please see “Description of Shares” and “Our LLC Agreement.”

Our Operating Partners

While our relationship with Hydrosource and Double Eagle is a significant strength, it is also a source of potential conflicts. Please see “—Conflicts of Interest” and “Risk Factors.”

Following the completion of this offering, our Existing Owners and the TCW Entities will retain a significant interest in us through their ownership of 105,164,580 Class B shares (and a corresponding number of OpCo Units) and 4,560,785 Class A shares, representing an aggregate 84.3% voting interest in us. Our Existing Owners and the TCW Entities may purchase Class A shares in the offering.

Conflicts of Interest

Although we have established certain policies and procedures designed to mitigate and resolve conflicts of interest, no assurance can be given that these measures will be effective in identifying, eliminating or mitigating all conflicts. These measures rely on, among other things, disclosures, supervisory oversight and information barriers that are inherently limited and may be circumvented or prove ineffective. It is possible that actual, potential or perceived conflicts of interest could give rise to investor dissatisfaction, litigation or regulatory enforcement actions, monetary penalties, reputational harm, restrictions on our activities and adverse effects on our results of operations and financial condition. Conflicts may result in decisions that are not aligned with, or that are less favorable than, those that might have been made absent such conflicts.

Our LLC Agreement will provide that our Existing Owners and their respective affiliates are not restricted from owning assets or prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, our Existing Owners and their respective affiliates may compete with us for investment opportunities and may own an interest in entities that compete with us. We will not have priority rights to any opportunities identified by our Existing Owners or their affiliates, and we may receive a reduced allocation of, or be excluded entirely from, opportunities that they pursue. Any allocation policies or procedures may be discretionary, may change without notice, and may not require our consent. Our LLC Agreement will also provide that we renounce any interest or expectancy in, or in being offered, an opportunity to participate in, any business opportunity that may from time to time be presented to our Existing Owners and their respective affiliates that would otherwise be subject to a corporate opportunity or other analogous doctrine under the TBOC other than any business opportunity that we establish by a preponderance of the evidence resulted from our or our subsidiaries’ confidential information. Our Existing Owners and their respective affiliates and certain of our directors may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. In addition, our directors, officers and employees may have competing demands on their time and attention as a result of their roles with our Existing Owners and their affiliates, which may adversely affect the time devoted to our business. Our Existing Owners and their affiliates may also possess material non-public information with respect to issues or opportunities that, due to legal or contractual constraints or internal information barriers, they cannot share with us. As a result, we may be restricted from pursuing, or may pursue such opportunities without the benefit of, such information. These affiliates may have meaningful access to capital, which may change over time depending upon a variety of factors, including available equity capital and debt financing, market conditions and cash on hand. They may also have different return profiles, fee structures, tax considerations, regulatory constraints, or investment horizons that create incentives to favor their own accounts or other vehicles over us, including through differing pricing, timing, structure, or terms of transactions.

Our key agreements, including our LLC Agreement and the First Amended and Restated Company Agreement of OpCo (the “OpCo LLC Agreement”), were negotiated among related parties, and their respective terms, including fees and other amounts payable, may not be as favorable to us as terms negotiated at an arm’s-length basis with unaffiliated parties. We and our affiliates may enter into additional related-party transactions from time to time, including service, financing, lease, hedging, or other commercial arrangements, and amendments or waivers under existing related-party agreements. Approvals of such matters may be made by persons or bodies that have interests that differ from, or conflict with, those of unaffiliated equityholders, and the standard of review for these determinations may be contractual rather than fiduciary in nature. Fees, expense allocations, and other economic arrangements under related-party agreements may incentivize our affiliates in ways that are not aligned with us. There can be no assurance that any conflicts in connection with related-party transactions will be resolved in our favor.

Redemption Right

Following this offering, under the OpCo LLC Agreement, each holder of an OpCo Unit (other than EagleRock) will, subject to certain limitations, have the right (the “Redemption Right”) to cause OpCo to acquire all or a portion of its OpCo Units (along with the cancellation of a corresponding number of our Class B shares) for, at OpCo’s election, (i) Class A shares at a redemption ratio of one Class A share for each OpCo Unit redeemed, subject to conversion rate adjustments for equity splits, dividends and reclassifications and other similar transactions (“applicable conversion rate adjustments”), or (ii) cash in an amount equal to the Cash Election Amount (as defined herein) of such Class A shares. Redemptions are subject to minimum volume requirements, including that each redemption must involve at least 150,000 OpCo Units (or all OpCo Units then held by the redeeming holder, if less than 150,000), and may generally be exercised no more frequently than once per calendar quarter (subject to exceptions for redemptions in connection with a registered offering pursuant to the Registration Rights Agreement or a Rule 10b5-1 trading plan approved by the Managing Member). Redemptions will also be subject to the conditions, timing, notice and other procedural requirements set forth in the OpCo LLC Agreement and applicable law, which may include blackout periods or other restrictions to ensure compliance with securities and other regulatory requirements. OpCo will determine whether to issue Class A shares or pay cash in an amount equal to the Cash Election Amount in lieu of the issuance of Class A shares based on facts in existence at the time of the decision, which we expect would include the relative value of the Class A shares (including the trading price for the Class A shares at the time), the cash purchase price, the availability of other sources of liquidity (such as an issuance of additional common shares) to acquire the OpCo Units and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, we (instead of OpCo) will have the right (the “Call Right”) to, for administrative convenience, acquire each tendered OpCo Unit directly from the redeeming holder of OpCo Units (“OpCo Unitholder”) for, at our election, (x) one Class A share, subject to applicable conversion rate adjustments, or (y) cash in an amount equal to the Cash Election Amount of such Class A shares. We may exercise the Call Right only if an OpCo Unitholder first exercises its Redemption Right, and an OpCo Unitholder may exercise its Redemption Right beginning immediately following the consummation of this offering, subject to certain limitations in the OpCo LLC Agreement and the expiration of lock-up restrictions. As the sole managing member of OpCo, our decision to pay the Cash Election Amount upon an exercise of the Redemption Right or Call Right may be made by a conflicts committee consisting solely of independent directors. In connection with any redemption of OpCo Units pursuant to the Redemption Right or acquisition of OpCo Units pursuant to the Call Right, a corresponding number of Class B shares held by the redeeming OpCo Unitholder will be automatically cancelled. Redemptions and exchanges will reduce the number of OpCo Units held by persons other than us, increase our direct ownership in OpCo and, to the extent settled in Class A shares, increase the number of publicly traded Class A shares outstanding and the public float.

Our acquisition (or deemed acquisition for U.S. federal income tax purposes) of OpCo Units pursuant to an exercise of the Redemption Right or the Call Right is expected to result in adjustments to the tax basis of the tangible and intangible assets of OpCo, and such adjustments will be allocated to us. These adjustments would not have been available to us absent our acquisition or deemed acquisition of OpCo Units and are expected to reduce the amount of cash tax that we would otherwise be required to pay in the future. The amount and timing of any such tax benefits will depend on a number of factors, including the price at which exchanges occur, the timing of redemptions, the nature and fair market value of the underlying assets at the time of the exchanges and applicable tax rates, and may vary significantly from period to period. The expected tax benefits are subject to the risk that the U.S. Internal Revenue Service could challenge all or part of the tax basis adjustments or the timing or amount of related deductions, and we may not prevail in any such challenge. Any realization of tax benefits may also be affected by future changes in tax law.

Our LLC Agreement will contain provisions effectively linking each OpCo Unit with one of our Class B shares such that Class B shares cannot be transferred without transferring an equal number of OpCo Units and vice versa. Accordingly, transfers, redemptions and exchanges will require corresponding transfers or cancellations, as applicable, and will be subject to the transfer restrictions, consents and other requirements set forth in the OpCo LLC Agreement and our LLC Agreement, as well as applicable securities laws. OpCo Unitholders may be required to provide customary representations and comply with procedural and timing requirements in connection with any redemption or exchange, and may be restricted from effecting redemptions or exchanges during lock-up periods, blackout windows or at times when they are in possession of material non-public information.

For additional information, please see “Certain Relationships and Related Party Transactions—OpCo LLC Agreement.”

Holding Company Structure

Our post-offering organizational structure will allow our Existing Owners to retain a direct equity ownership in OpCo, which will be classified as a partnership for U.S. federal income tax purposes following the offering. Investors in this offering will, by contrast, hold a direct equity ownership in us in the form of Class A shares, and an indirect ownership interest in OpCo through our ownership of OpCo Units. Although we were formed as a limited liability company, we have elected to be taxed as a corporation for U.S. federal income tax purposes.

Pursuant to our LLC Agreement and the OpCo LLC Agreement, our capital structure and the capital structure of OpCo will generally replicate one another and will provide for customary antidilution mechanisms in order to maintain the one-for-one exchange ratio between the OpCo Units and our Class A shares.

For additional information, please see “—Organizational Structure” and “Certain Relationships and Related Party Transactions—OpCo LLC Agreement.”

Organizational Structure

The following diagram reflects our simplified organizational structure immediately following the completion of this offering and the transactions described under “—Corporate Reorganization” (assuming that the underwriters’ option to purchase additional Class A shares is not exercised).

LOGO

*	This diagram is provided for illustrative purposes only and has been simplified by not depicting each individual operating subsidiary. See “—Corporate Reorganization.”

The Class A shares to be issued to the public in this offering will initially represent an indirect minority interest in OpCo. Our Existing Owners and the TCW Entities will initially own approximately 80.8% of the economic interests in OpCo through their ownership of OpCo Units, and our Existing Owners and the TCW Entities will control us and OpCo through their ownership of approximately 84.3% of our outstanding common shares. See “—Basis of Presentation” and “—Conflicts of Interest.”

Concurrently with the closing of this offering, we will enter into (i) the DE Flow WSMA with DEF Operating, which will govern our royalty revenue arrangements with respect to the integrated water infrastructure system in the Midland Basin, and (ii) the Hydrosource Recycling Agreement with Hydrosource, which will govern our royalty revenue arrangements with respect to recycled water activities on our land. These agreements are not depicted in the above graphic but are conditions to closing of this offering.

Summary Risk Factors

Risks Related to Our Business and Operations

•

Our revenues are substantially dependent on ongoing oil and natural gas exploration, development and production activity on or around our land.

•

Our business is difficult to evaluate because we have a limited operating history.

•

Future land acquisitions would expose us to risks associated with acquisitions and the commercialization of additional acreage.

•

Our acreage is located in the Permian Basin, making us vulnerable to risks associated with geographic concentration in a single geographic area.

•

We may not be successful in pursuing additional commercial opportunities on our land from non-traditional energy production and other users.

•

A significant portion of our acreage is held by us through leases from the Bureau of Land Management and the State of New Mexico. If we are unable to renew these leases in the future on similar or favorable terms, or at all, our business and financial condition could be materially and adversely impacted.

•

The construction by customers of new infrastructure on and around our land is subject to regulatory, construction, supply chain and other risks common in the development and operation of facilities and other infrastructure.

•

Rapid or sustained technological change in well completions, water sourcing, recycling and produced-water management could decrease demand for our water sales and produced-water transportation, recycling and handling on or around our land and require us or our operating partners to invest in new or unproven technologies at significant cost.

•

Competition in the energy industry is intense.

•

Sand operations are subject to operating risks that are often beyond the control of the mine operator. These risks can adversely affect production levels and costs, which could adversely affect sand production from our land.

•

Our insurance coverage may not fully cover our losses, and we may in the future encounter increased costs related to, and lack of availability of, insurance.

•

We have identified material weaknesses in our predecessor’s internal controls over financial reporting, and the failure to achieve and maintain effective internal controls over financial reporting could harm our business and negatively impact the value of our Class A shares. If we are unable to remediate these material weaknesses in a timely manner, we could be required to restate financial statements, delay or file late our periodic reports, incur increased audit and

compliance costs, face regulatory scrutiny or litigation, and experience an adverse impact on our reputation, liquidity and cost of capital.

Risks Related to Environmental and Regulatory Matters

•

Oil, natural gas and NGLs operations are subject to various governmental laws and regulations. We generally do not control our customers’ operations on our surface acreage and cannot ensure their compliance with applicable requirements, which may increase our residual exposure notwithstanding contractual indemnities and insurance.

•

Legislation or regulatory initiatives intended to address seismic activity, over-pressurization or subsidence could restrict drilling, completion and production activities, as well as our operating partners’ ability to handle produced water gathered from its customers.

•

Risks Related to Our Financial Condition

•

We are subject to interest rate risk, which may cause our debt service obligations to increase significantly.

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Our obligations under the Credit Facility will be secured by a first priority security interest in substantially all of the assets of OpCo and its restricted subsidiaries.

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We are subject to counterparty credit risk, including nonpayment or nonperformance by our customers.

Risks Related to this Offering, Our Corporate Structure and Our Class A Shares

•

The requirements of being a public company may increase our costs and divert management’s attention from other business concerns, and we may be unable to comply with these requirements in a timely or cost-effective manner.

•

Investors in this offering will experience immediate and substantial dilution of $15.50 per Class A share.

•

Any decision to pay cash dividends in the future will be made in the sole discretion of our board of directors. If we do not pay any cash dividends on our Class A shares following this offering, you may not receive a return on investment unless you sell your Class A shares for a price greater than that which you paid for them.

•

The Existing Owners have the ability to direct the voting of a majority of our common shares and control certain decisions with respect to our management and business. The Existing Owners’ interests may conflict with those of our other shareholders.

•

Our Existing Owners and their respective affiliates are not limited in their ability to compete with us, and may benefit from opportunities that might otherwise be available to us.

•

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

•

The U.S. federal income tax treatment of dividends on our Class A shares to a holder will depend upon our tax attributes and the holder’s tax basis in our Class A shares.

Emerging Growth Company and Smaller Reporting Company Status

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

•

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

•

provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition;

•

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

•

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

•

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

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

•

the last day of the fiscal year in which we have $1.235 billion or more in annual revenues;

•

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

•

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

•

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

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. 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 are also a “smaller reporting company” as defined under the Securities Act. We may continue to be a smaller reporting company even after we are no longer an emerging growth company. We may take advantage of certain scaled disclosures available to smaller reporting companies until the fiscal year following the determination that our common shares held by non-affiliates is $700 million or more, as measured on the last business day of our second fiscal quarter, and our annual revenues are

$100 million or more during the most recently completed fiscal year or our common shares held by non-affiliates is $250 million or more measured on the last business day of our second fiscal quarter.

Controlled Company Status

Because our Existing Owners will initially own 94,785,096 OpCo Units and Class B shares, representing approximately 72.8% of our combined voting power following the completion of this offering and will agree with us, pursuant to the terms of Voting Agreements (each, a “Voting Agreement” and collectively, the “Voting Agreements”), that it and certain of its transferees will vote in favor of all director nominees recommended for election by our board of directors, we expect to be a controlled company as of the completion of this offering under the NYSE and NYSE Texas rules. A controlled company is not required to have a majority of independent directors on its board of directors or to form an independent compensation or nominating and corporate governance committee. As a controlled company, we will remain subject to the Sarbanes-Oxley Act and the rules of the NYSE and NYSE Texas that require us, subject to certain phase-in periods, to have an audit committee composed entirely of independent directors. Under these rules, we must have an audit committee that has one member that is independent by the date that our Class A shares are first traded on the NYSE and NYSE Texas (the “listing date”), a majority of members that are independent within 90 days of the effectiveness of the registration statement of which this prospectus forms a part (the “effective date”) and all members that are independent within one year of the effective date. We expect to have five independent directors upon the closing of this offering.

If at any time we cease to be a controlled company, we intend to take all action necessary to comply with the NYSE and NYSE Texas rules, including by appointing a majority of independent directors to our board of directors and establishing a compensation committee and a nominating and corporate governance committee, each composed entirely of independent directors, subject to a permitted “phase-in” period.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 9655 Katy Freeway, Suite 375, Houston, Texas 77024, and our telephone number at that address is (713) 280-7002. Our website is located at EROK.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

The Offering

Issuer

EagleRock Land, LLC.

Class A shares offered by us

17,300,000 Class A shares (or 19,895,000 Class A shares if the underwriters’ option to purchase additional Class A shares is exercised in full).

Option to purchase additional Class A shares

We have granted the underwriters the option to purchase, exercisable within 30 days from the date of this prospectus, up to an additional 2,595,000 Class A shares from us, at the same terms and conditions set forth above if the underwriters sell more than 17,300,000 Class A shares in this offering.

Class A shares to be outstanding immediately after completion of this offering

24,960,419 Class A shares (or 27,555,419 Class A shares if the underwriters’ option to purchase additional Class A shares is exercised in full).

Class B shares to be outstanding immediately after completion of this offering

105,164,580 Class B shares, or one Class B share for each OpCo Unit held by our Existing Owners and the TCW Entities immediately following this offering. Class B shares vote together as a single class with Class A shares, but do not have any economic rights and holders thereof have no right to receive any dividends. In connection with any redemption of OpCo Units pursuant to the Redemption Right or acquisition of OpCo Units pursuant to the Call Right, a corresponding number of Class B shares will be cancelled.

Voting power of Class A shares after giving effect to this offering

19.2% (or 20.8% if the underwriters’ option to purchase additional Class A shares is exercised in full). The voting power of our Class A shares would be 100% if all outstanding OpCo Units were redeemed (along with the cancellation of a corresponding number of our Class B shares) for newly issued Class A shares on a one-for-one basis.

Voting power of Class B shares after giving effect to this offering

80.8% (or 79.2% if the underwriters’ option to purchase additional Class A shares is exercised in full). The voting power of our Class B shares would be 0% if all outstanding OpCo Units were redeemed (along with the cancellation of a corresponding number of our Class B shares) for newly issued Class A shares on a one-for-one basis.

Voting rights

Each Class A share entitles its holder to one vote on all matters to be voted on by shareholders generally. Each Class B share entitles its holder to one vote on all matters to be voted on by shareholders generally. Holders of our Class A shares and Class B shares vote together as a single class on all matters presented to our shareholders for their vote or approval, except as otherwise required by applicable law or by our LLC Agreement. Please see “Description of Shares” and “Our LLC Agreement.”

Under Shareholder’s Agreements that each of our Existing Owners will enter into with us, our Existing Owners will have the right to designate more than a majority of the members of our board of directors for a potentially extended period of time following the completion of this offering, and, under the Voting Agreements, our Existing Owners have agreed with us to vote all of the common shares that they own in favor of all director nominees recommended for election by our board of directors. As a result, investors in this offering will not be able to elect a majority of our board of directors during such time and will, therefore, have a limited ability to influence the direction of our business. See “Certain Relationships and Related Party Transactions—Shareholder’s Agreements” and “Certain Relationships and Related Party Transactions—Voting Agreements.”

Use of proceeds

We expect to receive $288.2 million of proceeds (or $333.1 million if the underwriters’ option to purchase additional Class A shares is exercised in full) from this offering based upon the assumed public offering price of $18.50 per Class A share (the midpoint of the price range set forth on the cover page of this prospectus), net of underwriting discounts and estimated offering expenses payable by us. See “Underwriting.”

We intend to contribute all of the net proceeds from this offering to OpCo in exchange for newly issued OpCo Units at a per-unit price equal to the per share price paid by the underwriters for our Class A shares in this offering. OpCo intends to use the net proceeds from this offering to repay in full, and terminate, the Predecessor Credit Facility and for general corporate purposes.

If the underwriters exercise their option to purchase additional Class A shares in full, we expect to receive approximately $44.9 million of additional net proceeds based upon the assumed public offering price of $18.50 per Class A share (the midpoint of the price range set forth on the cover page of this prospectus). We intend to contribute all of the net proceeds from any exercise of such option to OpCo in exchange for additional OpCo Units. OpCo intends to use such additional net proceeds to increase the amount of proceeds we will use for general corporate purposes. After the application of the net proceeds from this offering, we will own approximately 19.2% of outstanding OpCo Units (or approximately 20.8% of outstanding OpCo Units if the underwriters’ option to purchase additional Class A shares is exercised in full).

Please see “Use of Proceeds” for a more complete description of the intended use of proceeds from this offering.

Dividend policy

We intend to seek to pay dividends on our Class A shares in amounts determined from time to time by our board of directors. Please see “Dividend Policy.”

Redemption Right

Following this offering, under the OpCo LLC Agreement, each holder of an OpCo Unit (other than EagleRock) will, subject to certain limitations, have a Redemption Right to cause OpCo to acquire all or a portion of its OpCo Units (along with the cancellation of a corresponding number of our Class B shares) for, at OpCo’s election, (i) Class A shares at a redemption ratio of one Class A share for each OpCo Unit redeemed, subject to applicable conversion rate adjustments or (ii) cash in an amount equal to the Cash Election Amount of such Class A shares. Each redemption must involve at least 150,000 OpCo Units (or all OpCo Units then held, if less) and may generally be exercised no more frequently than once per calendar quarter, subject to certain exceptions. OpCo will determine whether to issue Class A shares or pay cash in an amount equal to the Cash Election Amount in lieu of the issuance of Class A shares based on facts in existence at the time of the decision, which we expect would include the relative value of the Class A shares (including the trading price for the Class A shares at the time), the cash purchase

price, the availability of other sources of liquidity (such as an issuance of additional common shares) to acquire the OpCo Units and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, we (instead of OpCo) will have the Call Right to, for administrative convenience, acquire each tendered OpCo Unit directly from the redeeming OpCo Unitholder for, at our election, (x) one Class A share, subject to applicable conversion rate adjustments, or (y) cash in an amount equal to the Cash Election Amount of such Class A shares. We may exercise the Call Right only if an OpCo Unitholder first exercises its Redemption Right, and an OpCo Unitholder may exercise its Redemption Right beginning immediately following the consummation of this offering, subject to certain limitations in the OpCo LLC Agreement and the expiration of lock-up restrictions. As the sole managing member of OpCo, our decision to pay the Cash Election Amount upon an exercise of the Redemption Right or Call Right may be made by a conflicts committee consisting solely of independent directors. In connection with any redemption of OpCo Units pursuant to the Redemption Right or acquisition of OpCo Units pursuant to the Call Right, a corresponding number of Class B shares held by the redeeming OpCo Unitholder will be automatically cancelled.

The OpCo LLC Agreement and our LLC Agreement will contain provisions effectively linking each OpCo Unit with one of our Class B shares such that Class B shares cannot be transferred without transferring a corresponding number of OpCo Units and vice versa.

For additional information, please see “Certain Relationships and Related Party Transactions—OpCo LLC Agreement.”

Directed share program

At our request, the underwriters will reserve up to 10% of the Class A shares being offered by this prospectus for sale at the initial public offering price to our directors, officers, employees and other individuals associated with us and members of their families. The sales will be made by Raymond James & Associates, Inc., an underwriter of this offering, through a directed share program. We do not know if these persons will choose to purchase all or any portion of these reserved Class A shares, but any purchases they do make will reduce the number

of Class A shares available to the general public. Any reserved Class A shares not so purchased will be offered by the underwriters to the general public on the same terms as the other Class A shares. Class A shares purchased by our directors, officers and employees in the directed share program will be subject to lock-up restrictions described in this prospectus. We will agree to indemnify Raymond James & Associates, Inc. against certain liability and expenses, including liabilities under the Securities Act, in connection with the sales of reserved Class A shares. See “Underwriting—Directed Share Program.”

Listing and trading symbol

We have applied for a dual listing of our Class A shares on the NYSE and NYSE Texas under the symbol “EROK.”

Risk factors

You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our Class A shares.

The information above excludes (i) 13,012,499 Class A shares reserved for issuance under our LTIP (as defined herein), which we intend to adopt in connection with the completion of this offering, and (ii) 105,164,580 Class A shares reserved for issuance in connection with any exercise of the Redemption Right or the Call Right. Except as otherwise noted, all information in this prospectus assumes (i) no exercise by the underwriters of their option to purchase additional Class A shares and (ii) no purchase of Class A shares by our directors, officers, employees and other individuals associated with us and members of their families through the directed share program.

Summary Consolidated Financial and Other Data

The following table shows summary historical, pro forma and pro forma, as adjusted financial data for each of the periods indicated. The summary historical consolidated financial data set forth below as of and for the years ended December 31, 2025 and 2024 have been derived from the audited consolidated financial statements of L&E, our predecessor, included elsewhere in this prospectus. The unaudited summary pro forma and pro forma, as adjusted financial data set forth below as of and for the year ended December 31, 2025 has been derived from our Unaudited Pro Forma Condensed Consolidated Financial Statements, which have been prepared in accordance with Article 11 of Regulation S-X, included elsewhere in this prospectus.

The unaudited pro forma statement of operations data set forth below gives effect to the Accelerated Acquisition, the exclusion of the Excluded Assets, the Shallow Valley Contribution and the DE Flow Contribution as if each transaction had occurred on January 1, 2025. The unaudited pro forma balance sheet data set forth below gives effect to the exclusion of the Excluded Assets, the Shallow Valley Contribution and the DE Flow Contribution as if each transaction had occurred on December 31, 2025.

The unaudited pro forma, as adjusted statement of operations data set forth below gives effect to the Accelerated Acquisition, the exclusion of the Excluded Assets, the Shallow Valley Contribution, the DE Flow Contribution, the Up-C Reorganization and this offering and the use of proceeds therefrom as described in “Use of Proceeds” as if each transaction had occurred on January 1, 2025. The pro forma, as adjusted information assumes an initial public offering price of $18.50 per share, the midpoint of the price range set forth on the cover of this prospectus, reflects the deduction of underwriting discounts and commissions and estimated offering expenses payable by us, and assumes no exercise of the underwriters’ option to purchase additional shares. The unaudited pro forma, as adjusted balance sheet data set forth below gives effect to the exclusion of the Excluded Assets, the Shallow Valley Contribution, the DE Flow Contribution, the Up-C Reorganization and this offering and the use of proceeds therefrom as described in “Use of Proceeds” as if each transaction had occurred on December 31, 2025.

The unaudited pro forma and pro forma, as adjusted financial data is presented for illustrative purposes only and is not necessarily indicative of the financial position that would have existed or the financial results that would have occurred if the applicable Pro Forma Transactions or the Pro Forma As Adjusted Transactions had been consummated on the dates indicated, nor are they necessarily indicative of the financial position or results of our operations in the future. The pro forma adjustments, as described in the notes to the Unaudited Pro Forma Condensed Consolidated Financial Statements, are preliminary and based upon currently available information and certain assumptions that our management believes are reasonable. The summary historical consolidated financial data is qualified in its entirety by, and should be read in conjunction with, the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section included in this prospectus and the consolidated financial statements and related notes and other financial information included in this prospectus. Historical results are not necessarily indicative of results that may be expected for any future period.


	Predecessor⁽¹⁾						Pro Forma⁽²⁾			Pro Forma, as Adjusted⁽³⁾
	Year ended December 31,
	2024			2025			2025			2025
	($ in thousands)
Statement of Operations Data:
Revenues
Resource sales	$	14,120		$	55,179		$	65,713		$	65,713
Resource royalties		—			—			—			—
Surface use related revenues		3,120			13,667			21,922			21,922
Surface use royalties		461			3,327			53,803			53,803

Total revenues⁽⁴⁾	$	17,701		$	72,173		$	141,438		$	141,438
Cost of sales (exclusive of depreciation and amortization)	$	4,873		$	20,863		$	19,178		$	19,178
Related party cost of sales		3,438			10,207			—			—
General and administrative expense		2,600			9,834			7,799			65,142
Related party general and administrative expense		198			235			205			205
Depreciation and amortization expense		3,944			14,984			52,808			52,808
Gain on sale of property, plants and equipment, net		(4,954	)		(2,067	)		(3,833	)		(3,833	)

Total operating expenses	$	10,099		$	54,056		$	76,157		$	133,500

Operating Income (Loss)	$	7,602		$	18,117		$	65,281		$	7,938

Interest expense		—			—			—			(385	)
Interest expense—related party		(8,703	)		(21,185	)		(21,185	)		—
Interest income		—			—			109			109
Loss on extinguishment of debt		—			(70,001	)		(70,001	)		(5,123	)

Income from operations before taxes	$	(1,101	)	$	(73,069	)	$	(25,796	)	$	2,539

Income tax expense (benefit)		(26	)		2			2			130

Net income (loss)	$	(1,075	)	$	(73,071	)	$	(25,798	)	$	2,409

Net income (loss) margin		(6.1	)%		(101.2	)%		(18.2	)%		1.7	%
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	907		$	14,138
Investing activities	$	(64,556	)	$	(204,963	)
Financing activities	$	64,711		$	199,090
Operating cash flow margin⁽⁵⁾		5.1	%		19.6	%
Supplementary Non-GAAP Financial and Operating Data:
Adjusted EBITDA⁽⁶⁾	$	7,350		$	35,533		$	118,581		$	118,581
Adjusted EBITDA Margin⁽⁶⁾		41.5	%		49.2	%		83.8	%		83.8	%
Free Cash Flow⁽⁶⁾	$	5,868		$	30,281
Free Cash Flow Margin⁽⁶⁾		33.2	%		42.0	%
Surface Use Efficiency⁽⁷⁾	$	202.3		$	415.6		$	462.0		$	462.0
Total Water Volumes (MMBbls)⁽⁸⁾		19.2			73.0			237.7			237.7
Selected Balance Sheet Data (at end of period):
Cash and cash equivalents	$	1,062		$	9,042		$	—		$	16,818
Total assets	$	86,694		$	282,010		$	1,505,254		$	1,522,239
Non-current liabilities	$	77,521		$	306,594		$	308,018		$	2,537
Total liabilities	$	87,769		$	323,725		$	322,568		$	9,908
Total equity	$	(1,075	)	$	(41,715	)	$	1,182,686		$	1,512,331

(1)

our predecessor’s Consolidated Statement of Operations. The remaining revenues reported on our predecessor’s Consolidated Statement of Operations have been disaggregated between Surface use royalties and Surface use related revenues above.

(2)

Unless otherwise indicated, “pro forma” information reflects the historical financial data of our predecessor, adjusted to give effect to the Pro Forma Transactions. For the year ended December 31, 2025, pro forma statement of operations data give effect to the Pro Forma Transactions as if they had occurred on January 1, 2025; pro forma balance sheet data give effect to the relevant Pro Forma Transactions as if they had occurred on December 31, 2025. See “Unaudited Pro Forma Condensed Consolidated Financial Statements” and the related notes for additional information.

(3)

Unless otherwise indicated, “pro forma, as adjusted” information reflects the Pro Forma As Adjusted Transactions. For the year ended December 31, 2025, pro forma, as adjusted statement of operations data give effect to these transactions as if they had occurred on January 1, 2025; pro forma, as adjusted balance sheet data give effect to these transactions as if they had occurred on December 31, 2025. See “Unaudited Pro Forma Condensed Consolidated Financial Statements” and the related notes for additional information.

(4)	Refer to the Unaudited Pro Forma Condensed Consolidated Financial Statements included elsewhere in this prospectus for additional information on the reclassification of revenues included in the Predecessor’s 2025 financial statements to conform to the line items above.

(5)	Operating cash flow margin is calculated by dividing net cash provided by operating activities by total revenues.

(6)

Adjusted EBITDA, Adjusted EBITDA Margin, Free Cash Flow and Free Cash Flow Margin are Non-GAAP financial measures. See “—Non-GAAP Financial Measures” below for more information regarding these non-GAAP measures and reconciliations to the most comparable measures calculated and presented in accordance with GAAP.

(7)	Surface Use Efficiency is calculated by dividing total revenue by weighted average total surface acreage. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations” below for more information on the calculation and use of this metric.

(8)	See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations” below for more information on the use of this metric.

Non-GAAP Financial Measures

We use certain non-GAAP financial measures to evaluate current and past performance and prospects for the future to supplement our financial information presented in accordance with GAAP. These measures are important indicators used by management to monitor our operating results, evaluate trends, benchmark performance against peers, and inform capital allocation decisions. We also believe these measures are useful to investors, research analysts and others because they provide additional insight into the underlying trends of our business. Non-GAAP financial measures should be considered in addition to, and not as a substitute for or superior to, the corresponding GAAP measures, and may be defined or calculated differently by other companies. We compensate for the limitations of these non-GAAP measures by relying primarily on our GAAP results and by using the non-GAAP measures only as supplemental information.

We present the most directly comparable GAAP measures with equal or greater prominence to the corresponding non-GAAP measures. Reconciliations of each non-GAAP measure to the most directly comparable GAAP measure are provided below for the periods indicated.

Adjusted EBITDA and Adjusted EBITDA Margin

Adjusted EBITDA and Adjusted EBITDA Margin are used by our management and by external users of our financial statements, such as investors, research analysts and others, to assess the

financial performance of our assets over the long term to generate sufficient cash to return capital to equity holders or service indebtedness. We define Adjusted EBITDA as net income (loss) minus interest, taxes, depreciation, amortization, depletion and accretion, which we refer to as “EBITDA” and from which we further deduct share-based compensation, non-recurring transaction-related expenses and other non-cash or non-recurring expenses. We define Adjusted EBITDA Margin as Adjusted EBITDA divided by total revenues.

Management believes Adjusted EBITDA and Adjusted EBITDA Margin are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations from period to period, and against our peers, without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA and Adjusted EBITDA Margin because these amounts can vary substantially from company to company within our industry, depending upon accounting methods, book values of assets, capital structures and the method by which the assets were acquired.

The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to Adjusted EBITDA and Adjusted EBITDA Margin for the periods indicated.


	Predecessor						Pro Forma			Pro Forma, as Adjusted
	Year Ended December 31,
	2024			2025			2025			2025
	($ in thousands)
Net income (loss)	$	(1,075	)	$	(73,071	)	$	(25,798	)	$	2,409
Adjustments:
Depreciation, depletion, amortization and accretion		3,944			14,984			52,808			52,808
Interest expense, net		8,703			21,185			21,076			276
Income tax expense (benefit)		(26	)		2			2			130

EBITDA	$	11,546		$	(36,900	)	$	48,088		$	55,623

Adjustments:
Share-based compensation	$	—		$	—		$	—		$	57,343
Transaction-related expenses⁽¹⁾		758			4,299			4,299			4,299
Loss on extinguishment of debt⁽²⁾		—			70,001			70,001			5,123
Other⁽³⁾		(4,954	)		(1,867	)		(3,807	)		(3,807	)

Adjusted EBITDA	$	7,350		$	35,533		$	118,581		$	118,581

Net income (loss) margin		(6.1	)%		(101.2	)%		(18.2	)%		1.7	%
Adjusted EBITDA Margin		41.5	%		49.2	%		83.8	%		83.8	%

(1)

(2)	Loss on extinguishment of debt consists of a nonrecurring, noncash loss that resulted from the increase in the size of our Predecessor Credit Facility in April 2025.

(3)	Other consists primarily of nonrecurring gain on sale of property, plant and equipment, net and other nonrecurring transactions.

Free Cash Flow and Free Cash Flow Margin

Free Cash Flow and Free Cash Flow Margin are performance measures used by our management and by external users of our financial statements, such as investors, research analysts and others, to assess our ability to generate cash from operations to repay our indebtedness, return capital to our shareholders and fund potential acquisitions without access to external sources of financing for such purposes. To calculate Free Cash Flow, net income is adjusted by the same items discussed above for EBITDA and Adjusted EBITDA and then further adjusted by deducting incurred capital expenditures, which includes changes in accounts payable related to capital expenditures. Free Cash Flow Margin is calculated as Free Cash Flow divided by total revenues.

Management believes Free Cash Flow and Free Cash Flow Margin are useful because they allow for an effective evaluation of both our operating and financial performance, as well as the capital intensity of our business, and subsequently the ability of our operations to generate cash flow that is available to distribute to our shareholders, reduce leverage or support acquisition activities.

The following table sets forth a reconciliation of cash flows from operating activities as determined in accordance with GAAP to Free Cash Flow and Free Cash Flow Margin, respectively, for the periods indicated.


	Predecessor
	Year Ended December 31,
	2024			2025
	($ in thousands)
Net income (loss)	$	(1,075	)	$	(73,071	)
Adjustments:
Depreciation, depletion, amortization and accretion		3,944			14,984
Interest expense, net		8,703			21,185
Income tax expense (benefit)		(26	)		2
Transaction-related expenses⁽¹⁾		758			4,299
Loss on extinguishment of debt⁽²⁾		—			70,001
Other⁽³⁾		(4,954	)		(1,867	)
Capital expenditures		(1,206	)		(5,279	)
Change in accounts payable related to capital expenditures		(276	)		27

Free Cash Flow	$	5,868		$	30,281

Net income (loss) margin		(6.1	)%		(101.2	)%
Free Cash Flow Margin		33.2	%		42.0	%

(1)

(2)	Loss on extinguishment of debt consists of a nonrecurring, noncash loss that resulted from the increase in the size of our Predecessor Credit Facility in April 2025.

(3)	Other consists primarily of nonrecurring gain on sale of property, plant and equipment, net and other nonrecurring transactions.

RISK FACTORS

Investing in our Class A shares involves a significant degree of risk. The risks described below as well as all other information in this prospectus, including the historical and pro forma financial statements and the notes thereto and the matters addressed under the sections titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Cautionary Note Regarding Forward-Looking Statements,” should be considered carefully before deciding to invest in our Class A shares. The risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. The occurrence of any of the following risks or additional risks and uncertainties that are currently deemed immaterial or unknown could have a material and adverse effect on our business, financial condition, liquidity, results of operations, cash flows and prospects. In such an event, the trading price of our Class A shares could decline, and you may lose all or part of your investment.

Risks Related to Our Business and Operations

Our revenues are substantially dependent on ongoing oil and natural gas exploration, development and production activity on or around our land. If E&P companies do not maintain drilling, completion and production activities on or around our land, the demand for the use of our land and resources, as well as the royalties we receive from activities on our land, could be reduced, which could have a material adverse effect on our results of operations, cash flows and financial position.

We are not an E&P company and have limited physical operations on our land. As a result, we have limited ability to influence or control the operation or future development of, or on, our properties. We are dependent on our customers to develop our properties, construct infrastructure and commence other operations on and around our land. Revenue is tied to E&P development intensity and midstream connectivity; delays in drilling, completions, takeaway or recycling demand can reduce volumes and fees. Contract renewals or new surface/easement grants may be delayed or repriced, impacting continuity and economics. We therefore remain exposed to our customers’ development pacing and capital allocation decisions, which we do not control.

The willingness and ability of companies to continue operations and development activities on and around our land is dependent on a variety of factors that are outside of their and our control, including:

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the demand for and supply of oil, natural gas and NGLs;

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prevailing oil, natural gas and NGL prices, and expectations regarding future oil, natural gas and NGL prices;

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capital expenditures, including costs required for drilling, completion and production activities;

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the ability to access, and cost of, capital;

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

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consolidation in the oil and gas industry, which may result in lower overall drilling and completion activity;

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the producers’ expected return on investment on projects and in wells drilled on or around our land as compared to opportunities in other areas;

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the terms of our agreements, which often include renewal and termination provisions that could be exercised adversely, reducing revenues, interrupting operations or increasing costs;

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trade policies of domestic and foreign governments, including the imposition of tariffs and other levies on cross-border movement of goods and services; and

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regulatory developments, including, but not limited to, permitting timelines and outcomes for surface-disturbing activities, air and water authorizations and produced-water handling and disposal.

Many of our SUAs require our customers to use resources from our land, such as caliche, water and sand, for their operations on our land, for which we receive fees. As such, we are substantially dependent on our customers’ operations and/or drilling, completion and production activities by companies on or around our acreage. Similarly, the services our operating partners provide from which we earn royalties and fees are substantially dependent on those same activities. If companies do not maintain such activities on or around our land, their demand for the use of our land and resources and our operating partners’ services will decline, negatively impacting our results of operations, cash flows and financial position. In addition, customers may satisfy obligations through recycling or alternative handling pathways that reduce demand for water or shift produced-water flows away from higher-royalty configurations on our land.

Demand for the use of our land and resources, as well as the services provided by our operating partners, depends substantially on capital spending by producers to construct and maintain infrastructure on and around our acreage and explore for, develop and produce oil, natural gas and NGLs in the area. These expenditures are generally dependent on such producers’ overall financial position, capital allocation priorities and ability to access capital, and their views of future demand for, and prices of, oil, natural gas and NGLs. Volatility in oil, natural gas or NGLs prices (or the perception that oil, natural gas or NGLs prices will decrease) affects such producers’ capital expenditures and willingness to pursue development activities. This, in turn, could lead to lower demand for the use of our land and resources or our operating partners’ services, delays in payment of, or nonpayment of, amounts that are owed to us and cause lower rates and lower utilization of our land. As a result, a significant decrease in the price of oil, natural gas and NGLs or decrease in levels of production of oil, natural gas and NGLs on and around our land could adversely affect our results of operations, cash flows and financial position. Moreover, our agreements generally allow customers discretion over the pace and scope of development, which may accentuate these impacts during periods of commodity price weakness. For additional discussion of commodity price exposure, see “—The willingness of companies to engage in drilling, completion and production activities on and around our land is substantially influenced by the market prices of oil, natural gas and NGLs.”

For the year ended December 31, 2025, on an actual basis, we received revenue from approximately 75 customers, and our top ten customers represented approximately 77.2% of our total revenues. For the year ended December 31, 2025, on a pro forma basis, we received revenue from approximately 115 customers, and our top ten customers represented approximately 74.5% of our total revenues. While we expect these revenue streams to be recurring, our contracts with our significant customers, which represent a large portion of our revenues, often are structured as surface-use and royalty arrangements; however, many of these contracts do not include minimum commitments for land use or water volumes, and where such provisions exist, they may be subject to caps, carve-outs or other limitations. In particular, our Hydrosource Recycling Agreement will include a minimum annual royalty, and also entitle us to per-barrel royalties on certain volumes Hydrosource sells across the Permian Basin, which mitigates, but does not eliminate, volume risk under that agreement. In addition, certain Midland Basin water-infrastructure revenues are supported by long-term acreage dedications and minimum-volume commitments, which will include a minimum annual royalty under our DE Flow WSMA with DEF Operating, an affiliate of Double Eagle. These features mitigate, but do not eliminate, volume risk, and actual activity levels and volumes on or around our acreage will continue to drive our revenues.

As a result, our revenues are dependent on ongoing demand from these customers, which may decrease due to factors beyond our control. Our producers make all decisions as to investments in, and production from, their wells, and our revenues are dependent upon decisions made by such producers, among other factors. For example, we cannot control whether a producer chooses to develop a property or the success of drilling and development activities, which depend on a number of factors under the control of such producer. There can be no assurance that such producers will take actions or make decisions that will be beneficial to us, which could result in adverse effects on our results of operations, cash flows and financial position.

We also depend on operating partners to construct and operate certain water management and related systems on or adjacent to our acreage, including Hydrosource in the Delaware and Midland Basins and DEF Operating in portions of the Midland Basin, and any reduction in activity by their upstream customers, failure to obtain or maintain permits or inability to access ROWs and pore space, could reduce volumes handled on or around our land and adversely affect the royalties and fees we receive.

Although many of our SUAs include long tenors, exclusivity for certain resources and specified fee schedules for surface uses, development pacing, commodity-driven spending, regulatory changes and permitting outcomes can still materially impact customer activity and the timing and level of payments to us. In Texas and New Mexico, state regulators have, at times, limited produced-water handling through Seismic Response Area (“SRA”) measures and permit actions, and future actions could disrupt produced-water handling on or near our land and reduce customer activity levels. Although our acreage is not currently included in any SRA, there can be no assurance this will remain the case. More broadly, permits for produced-water handling and disposal, air emissions, dredge and fill activities and surface-disturbing construction are subject to heightened scrutiny, evolving technical standards and more frequent third-party challenges, which can extend timelines, increase costs or result in permit denials or revocations after issuance. Limitations on obtaining or renewing necessary permits or accessing suitable pore space and rights-of-way near our acreage could divert volumes to areas where we do not earn royalties and materially and adversely affect our results of operations, cash flows and financial position.

The willingness of companies to engage in drilling, completion and production activities on and around our land is substantially influenced by the market prices of oil, natural gas and NGLs, which are highly volatile due to factors beyond our control. A substantial or extended decline in commodity prices may adversely affect our business, financial condition, results of operations and cash flows.

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile. For example, political instability or armed conflicts in oil and gas producing regions have contributed to significant increases and volatility in the price for oil, natural gas and NGLs. Wide fluctuations in oil, natural gas and NGLs prices may result from relatively minor changes in the supply of or demand for oil, natural gas and NGLs, market uncertainty and other factors that are beyond our and our customers’ control, including:

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worldwide and regional economic conditions, including the potential for a recession in the U.S. or worldwide, elevated interest rates and associated policies of the U.S. Federal Reserve Board (“Federal Reserve”);

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the supply and demand for oil, natural gas and NGLs, including a potential increase in Venezuelan oil supply and any related impact on global oil prices and domestic oil production;

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

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U.S. federal, state and local and foreign governmental regulation, including U.S. and international trade policies and any resultant tariffs, and taxes;

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supply chain disruptions;

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the level of oil, natural gas and NGLs exploration, development and production activities;

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the level of oil, natural gas and NGLs inventories;

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prevailing prices, and expectations regarding future prices, on local price indexes in the areas near our acreage;

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

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localized and global supply and demand fundamentals and transportation availability;

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

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weather conditions, such as severe storms, earthquakes and flooding, and other natural disasters;

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technological advances affecting energy consumption, including those related to new and emerging technologies;

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the development, price and availability of alternative fuels;

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speculative trading in oil, natural gas and NGLs derivative contracts;

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increased end-user conservation;

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political and economic conditions in or affecting oil and gas producing regions or countries;

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actions of the Organization of Petroleum Exporting Countries (“OPEC” and collectively with its allies, “OPEC+”), including the ability and willingness of the members of OPEC+ and other exporting nations to agree to and maintain oil price and production controls, including any anticipated increases in supply;

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expectations about future commodity prices; and

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the possibility of terrorist or physical, electronic and cybersecurity breaches and the consequences of any such attacks or breaches.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. From the beginning of 2022 through December of 2025, NYMEX WTI ranged from $55.44 to $123.64 per Bbl, and the NYMEX Henry Hub price of natural gas has ranged from $1.21 to $13.20 per MMBtu. The war in Ukraine, the war between the U.S. and Israel against Iran, the U.S. engagement in Venezuela, elevated interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, recent measures to combat persistent inflation and actions taken by OPEC+ all continue to contribute to economic and oil and natural gas price volatility. In particular, crude oil prices have risen significantly during the spring of 2026 as a result of concerns over supply-related constraints resulting from the war in the Middle East between the U.S., Israel and Iran. As a result of this conflict, significant production shut-ins have occurred and global shipping of crude oil and NGLs has been disrupted. However, the duration of that conflict and the longer term impact on crude oil prices remains uncertain. If the prices of oil, natural gas and NGLs decline, our operations and financial condition may be materially and adversely affected through a reduction in the use of our land and its resources and/or our operating partners’ services. Moreover, while U.S. natural gas prices are correlated with global oil price movements, they are also affected by local weather, transportation and consumption patterns. Further, NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs.

We cannot reasonably predict whether production levels will remain at current levels or the impact the full extent of the events above may have on our industry and our business. In addition, oil, natural gas and NGLs prices may reduce the amount of oil, natural gas and NGLs that can be produced economically by operators on or around our land, which may reduce their willingness to develop our properties and/or use our or our operating partners’ services. Operators on and around our land could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil, natural gas and NGLs in commercially paying quantities. Other significant factors that are likely to continue to affect commodity prices in future periods include, but are not limited to, the effect of U.S. energy, monetary and trade policies, U.S. and global economic conditions and political developments, including the current U.S. administration’s trade, energy and environmental policies, all of which are beyond our control. Our business may also be adversely impacted by any future government rule, regulation or order that may impose production limits, as well as pipeline capacity, storage constraints and transportation delays.

Our business is difficult to evaluate because we have a limited operating history.

Although our predecessor commenced operations in early 2024, we were formed in December 2025 to facilitate this offering and certain transactions related thereto, and our business going forward will be a combination of newly acquired assets from multiple sources. In addition, our predecessor consummated two significant acquisitions since its formation—the Desert Ram Acquisition and the Accelerated Acquisition. As a result, our prior operating history and historical financial statements may not be a reliable basis for evaluating our business prospects or the future value of our Class A shares and may make it difficult to assess our ability to operate profitably. Our future results will be dependent on, among other things, a number of factors and trends discussed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and elsewhere in this prospectus and the risks discussed elsewhere in this “Risk Factors” section, as well as our ability to execute our business model. Our business model may not be successful, and if unsuccessful, we may be unable to modify it in a timely and successful manner.

Because of our limited operating history, our business model and the attractiveness of our land and resources to our customers, as well as the performance of any other future assets, are not yet proven. As a result, it may be difficult to evaluate our business and results of operations to date and to assess our future prospects.

In addition, we may encounter risks, liabilities and difficulties experienced by companies whose performance is dependent upon newly acquired assets, such as unforeseen liabilities or failing to integrate, or realizing the expected benefits of, such assets. As a result of the foregoing, we may be less successful in achieving a consistent revenue base capable of generating cash flows from operations compared with a company that has a longer operating history. 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.

Moreover, our results and cash flows will depend on the development decisions and operating performance of producers and operating partners on and around our acreage, over which we have limited control, and which are affected by factors beyond our control, including commodity price volatility, access to capital, permitting and regulatory developments, supply chain constraints and labor availability. In the Midland Basin, for instance, our produced water handling revenues are supported by long-term arrangements on the DE Flow System with peak handling capacity of approximately 400 MBbls/d; however, producer activity levels, availability of pore space and regulatory constraints on

injection and recycling could materially affect throughput and related royalties and fees. Similarly, our surface-use and resource revenues on our Delaware Basin acreage are influenced by producer drilling, completion and infrastructure activities, which have historically fluctuated with macroeconomic conditions and commodity pricing.

Future land acquisitions would expose us to risks associated with acquisitions and the commercialization of additional acreage.

We may pursue opportunistic future land acquisitions that we expect to complement or expand our current land position. We may not be able to identify attractive acquisition opportunities, and even if we do so, we may not be able to complete the acquisition on commercially acceptable terms, or at all. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or at all, or successfully acquire such identified acreage.

Additionally, we may potentially pursue selective acquisitions from the Existing Owners in the future. For example, Hydrosource recently acquired approximately 50,000 surface acres in Lea County, New Mexico that is proximate to our existing land holdings in the Delaware Basin and we may consider acquiring such acreage from Hydrosource in the future. However, these properties have not been offered to us by Hydrosource, no negotiations have occurred and no agreement currently exists, and there can be no assurance that any such agreement will be reached in the future or that we would have the capital necessary to acquire these assets in the event they were offered to us. Additionally, if any acquisition from the Existing Owners were to be pursued in the future, such acquisition would require approval from a conflicts committee of our board of directors comprised solely of independent and disinterested directors.

The process of integrating acquired acreage may involve unforeseen risks, liabilities and difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to realize the anticipated benefits of our acquisitions could have a material and adverse effect on our results of operations, cash flows and financial position. The successful acquisition and integration of acreage requires an assessment of several factors, including:

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the availability of water and the suitability of the land for produced water handling;

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proximity to recoverable oil, natural gas and NGLs reserves and the level of drilling, completion and production operations of the target acreage;

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presence of minable sand;

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future oil, natural gas and NGLs prices and their applicable differentials;

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potential environmental and other liabilities;

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any restrictive covenants or other use restrictions that would prohibit or restrict the ability to engage in certain activities on the target land; and

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regulatory, permitting and other similar matters.

The accuracy of these assessments is inherently uncertain. Although we will perform a review of the subject acreage that we believe to be generally consistent with industry practices, the accuracy of these assessments is inherently uncertain and may not reveal all existing or potential problems or fully assess their deficiencies and capabilities. Inspections may not always be performed on the totality of such acreage, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems.

Even if we consummate acquisitions that we believe will increase our revenues and cash generated from operations, such transactions could nonetheless reduce our Free Cash Flow and cash flow per share, at least in the near term, and may limit our ability to return capital to shareholders or fund organic growth on our acreage. Any acquisition involves potential risks, including, among other things: the validity of our assumptions regarding surface-related revenues and royalties, including fees and rates under our SUAs, ROWs and easements, and water sourcing, produced water handling, recycling and disposal activities; a decrease in our liquidity from deploying a significant portion of cash generated from operations or borrowing capacity to finance acquisitions; a significant increase in our interest expense or financial leverage if we incur debt to fund acquisitions; the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate; inaccurate assumptions about our overall cost of equity or debt; our ability to obtain satisfactory title to, or adequately defend, the surface estates, ROWs, easements and pore space rights we seek to acquire; constraints on our ability to integrate newly acquired acreage into our commercial framework with operating partners; challenges in hiring, training or retaining qualified personnel to manage and operate a larger platform; and other significant changes, such as impairments of acquired assets, goodwill or other intangibles, asset devaluation or restructuring charges.

Because a significant portion of our future revenue growth is expected to be derived from our operating partners, any development that materially and adversely affects their business, operations or financial condition, including insolvency or bankruptcy proceedings, inability to obtain sufficient financing, mandated regulatory curtailments or suspensions or failure to perform under our agreements, could have a material adverse impact on us.

Our operating partners are expected to play an important role in our financial performance over the long term, and we are indirectly subject to the business risks they face. As a result, any development that materially and adversely affects an operating partner’s business, operations or financial condition, including reductions in upstream customer activity, inability to access capital on acceptable terms, or at all, regulatory delays or denials, loss of key permits, labor or supply chain constraints or counterparty defaults, could reduce volumes handled on or near our acreage, diminish demand for the use of our land and resources, delay or reduce payments owed to us and otherwise have a material adverse impact on our results of operations, cash flows and financial position. Because oil and natural gas wells exhibit declining production profiles, surface activity and associated fees tied to those wells will naturally decline over time, requiring us to proactively backfill demand by repositioning corridors and other surface rights for alternative and non-traditional uses and by structuring our agreements to allow for multiple uses over the life of the acreage.

In particular, we depend on operating partners to construct and operate water management and related systems on or adjacent to our acreage, and any reduction in activity by their upstream customers, failure to obtain or maintain required permits, or inability to access ROWs and pore space, could reduce throughput on such systems and adversely affect the royalties and fees we receive. As wells mature, are shut-in or plugged and abandoned, portions of our land may transition from drilling and completion activities to reclamation or repurposing, which can change the mix and timing of royalties and fees and necessitate incremental remediation or permitting before reuse. Although many of our surface use agreements include long terms, elements of exclusivity and specified fee schedules for surface uses, development pacing, commodity-driven spending, regulatory changes and permitting outcomes can materially impact customer activity and the timing and level of payments to us.

Our operating partners do not own all of the land on which their infrastructure is located, and certain portions of such infrastructure are subject to third-party leases, ROWs and easements. If an operating partner were to lose these rights or be required to relocate its infrastructure, our business could be materially and adversely affected through service interruptions or higher costs that reduce activity levels or delay projects on or around our land. In addition, if our operating partners are unable

to enter into favorable commercial arrangements, obtain sufficient financing, or to obtain necessary regulatory and land use approvals on favorable terms and timelines, they may be unable to construct, expand or operate assets as anticipated, or at all, which could negatively affect our results of operations, cash flows and financial position.

Further, produced water handling and related activities depend on sufficient and reliable access to injection capacity and pore space, as well as regulatory approvals that are subject to change. Constraints in pore space availability, reservoir over-pressurization, seismicity-related curtailments, or new restrictions on injection, recycling or the cross-border movement of produced water, could limit our operating partners’ ability to handle produced water volumes, in turn reducing activity on or around our land and adversely affecting our revenues tied to such activity. These risks may be compounded by commodity price volatility and consolidation among upstream producers, which can alter development plans in our areas and materially affect throughput and surface utilization underlying our fee and royalty streams. In addition, temporary or permanent moratoria, suspensions or other regulatory actions affecting injection or produced water recycling—including induced-seismicity response measures or changes or revocations to existing permits or changes to future permitting regimes—could further constrain throughput and materially affect the timing and level of our fee and royalty streams.

Although our contracts with operating partners and customers may include features such as acreage dedications, specified fee schedules, and minimum-royalty commitments, these provisions do not eliminate the volume, timing and counterparty risks associated with dependence on operating partners and their and our customer base, and contractual protections may include caps, carve-outs or other limitations. Certain contractual protections may also be limited by bankruptcy or insolvency laws, and counterparties may seek to reject, renegotiate or fail to assume our agreements in such proceedings, which could diminish expected volumes and payments notwithstanding such protections. In addition, under a put option agreement between Double Eagle and Hydrosource, Double Eagle has the right to sell, and Hydrosource has the obligation to purchase, DEF Operating if Double Eagle undergoes certain change of control events or at any time following five years from the date of this offering. If Double Eagle exercises such put right, it would cease to be one of our operating partners and we would lose the benefits of that relationship, and Hydrosource, our other operating partner, would become the owner of DEF Operating, which is the party to the DE Flow WSMA and the minimum royalty obligation thereunder. As a result, sustained reductions in operating partner activity, loss of land access rights, inability to obtain or maintain permits or sufficient financing, regulatory or geologic constraints or other adverse developments affecting our operating partners could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We rely on a small number of key individuals whose absence or loss could adversely affect our business, and difficulty attracting and retaining experienced personnel and qualified directors could reduce our competitiveness and prospects for future success.

The successful operation and growth of our business depends to a large extent on a small number of key individuals to whom many integral responsibilities within our business have been assigned. We rely on our key personnel for their knowledge of the energy industry, relationships within the industry and experience in operating a business in our areas of operation. In particular, we depend on the continued services of our senior management team, including our Chief Executive Officer, Greg Pipkin Jr., our President and Chief Financial Officer, Neal H. Shah, and our General Counsel, Robert W. Hunt Jr. The loss of the services of one or more of these key personnel, directors or management team members, including Mr. Pipkin, Mr. Shah or Mr. Hunt, and the inability to recruit or retain additional key personnel, could have an adverse effect on our business. Further, we do not currently have a succession plan for the replacement of, and do not maintain “key-person” life insurance policies on, such key personnel.

In addition, our business and the success thereof is also dependent, in part, on our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated due to competition within the broader energy industry. Other companies may be able to offer better compensation and benefits packages to attract and retain such personnel. If we cannot retain experienced personnel or attract additional experienced personnel, our ability to compete in our industry could be harmed, which could have a material adverse effect on our results of operations, cash flows and financial position.

Our acreage is located in the Permian Basin, making us vulnerable to risks associated with geographic concentration in a single geographic area.

Our acreage is located in the Permian Basin in Texas and New Mexico, making us vulnerable to risks associated with geographic concentration in that basin. In particular, we and our customers may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from oil and natural gas wells in this area, availability of equipment, facilities, personnel or services, market limitations, governmental regulation and political activities, processing or transportation capacity constraints, natural disasters, adverse weather conditions, water shortages or other drought related conditions or interruption of the processing or transportation of produced water, oil, natural gas and NGLs. For example, state regulators in Texas and New Mexico have, at times, limited produced-water handling through SRA measures and permit actions (including the NMOCD’s July 2024 administrative cancellation of pending UIC Class II applications within the 10-mile County Line SRA), and similar actions in the future could disrupt produced-water handling on or near our land and reduce customer activity levels. Although our acreage is not currently included in any SRA, there can be no assurance that this will remain the case. These types of regional regulatory responses-and the underlying induced-seismicity concerns they seek to address-concentrate risk for operators within the Permian Basin relative to other basins.

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Midland Basin and Delaware Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. For instance, producer activity on and around our Midland Basin surface position ties directly to water infrastructure throughput contracts and any slowdown in development pacing, access to pore space, or permitting outcomes could reduce volumes that ultimately flow across our land and impact associated royalties and fees. In the Delaware Basin, localized seismicity management measures and differences between Texas and New Mexico produced-water permitting regimes can similarly affect development cadence on and around our surface position. Additionally, our water sales and other resource royalties may be adversely affected by risks associated with our geographic concentration, including the presence of a limited number of potential customers on or near our land, competition with adjacent landowners to provide an attractive development site for such resources, particularly if such landowners are closer to the location of oil and natural gas development activity, and legislation or regulatory initiatives limiting the utilization or transportation of water and other resources in the Permian Basin. In addition, our Hydrosource Recycling Agreement will include per-barrel royalties tied to recycled-water sales (with minimum annual volumes), such that any region-specific slowdowns or restrictions in the Permian Basin may directly impact our royalty receipts even when activity occurs off-ranch.

Our operations depend upon access to available pore space in subsurface geologic formations for AGI wells and disposal of produced water. Our inability to acquire new pore space or our loss of existing pore space may negatively impact our ability to service new and existing customers.

Our customers handle produced water generated during oil and natural gas operations by constructing produced water handling facilities and injecting such produced water into porous

subsurface geologic formations. We have also experienced increased demand for our pore space for AGI wells, with the first AGI well contracted and projected to commence revenue activities within the next 12 months. The amount of subsurface pore space that is capable of permanently storing injected produced water or acid gas and carbon dioxide is finite. As third parties inject produced water or acid gas and carbon dioxide on our land, we may exhaust the geologic or technical limits of the subsurface strata. In addition, produced-water injection in parts of the Permian Basin has been subject to SRA measures and targeted permit actions, which can reduce or suspend injection in affected areas. For example, on July 11, 2024, the NMOCD administratively canceled 75 pending Class II permit applications within the 10-mile County Line SRA due to seismicity concerns. Although our acreage is not currently within an SRA, similar actions in the future could constrain injection alternatives near our land and heighten competition for available pore space.

Any loss of pore space or injection capacity on our land for technical, geological or regulatory reasons could require our customers to spend significant time and capital to locate, apply for, permit, drill, complete and place into service new produced water handling facilities and to build pipeline infrastructure to transport produced water to such new facilities. Our customers may also look for pore space on land we do not own or control. Permits for new produced water handling facilities could be challenged for a variety of reasons by our customers’ competitors, oil and natural gas producers, landowners or non-governmental organizations. Such regulatory challenges could be successful and prevent our customers from being able to secure access to additional pore space on our land. By way of example, Texas regulators have previously suspended or declined to issue certain deep-zone disposal permits within designated SRAs in response to seismicity, and New Mexico protocols require rate limits and other curtailments after qualifying seismic events; outcomes that can delay or displace new injection capacity even where subsurface pore space exists. While our SWD footprint is concentrated on Midland Basin acreage in Texas, where permitting has generally been more favorable and seismicity lower than in New Mexico, pore-space and pressure limitations still ultimately cap injection capacity and may necessitate recycling or longer-haul solutions if disposal is constrained.

Identified drilling locations, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of December 22, 2025, operators for the acreage associated with our properties have advised us that they have identified more than 3,144 gross horizontal drilling locations across our acreage. These drilling locations represent a significant part of our growth strategy. The ability of operators on our properties to drill and develop identified potential drilling locations will depend on a number of factors, including the availability of capital, seasonal conditions, regulatory changes and approvals, negotiation of agreements with third parties, commodity prices, costs, the generation of additional seismic or geological information, the availability of drilling rigs, drilling results, construction of infrastructure, inclement weather and lease expirations.

Further, identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional analysis of data. We will not be able to predict in advance of drilling and testing whether any particular drilling location will yield production in sufficient quantities for operators to recover drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, the potentially productive hydrocarbon bearing formation may be damaged or mechanical difficulties may develop while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If operators drill dry holes in our current and future drilling locations, our business may be materially harmed. We cannot assure you that the analogies drawn from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or our operators in our areas of operations may not be indicative of future or long-term production rates.

Because of these uncertainties, we do not know if the potential drilling locations identified on our acreage will ever be drilled or if oil or natural gas reserves will be able to be produced from these or any other potential drilling locations, and we have little or no control over the timing of future drilling with respect to our acreage. As such, actual drilling activities with respect to our acreage may materially differ from those presently identified, which could adversely affect our business, financial condition, results of operations and cash available for distribution.

We may not be successful in pursuing additional commercial opportunities on our land from non-traditional energy production and other users.

One of our strategies is to expand the use of our land and sources of revenue beyond what is traditionally associated with oil and gas development. For example, we intend to pursue new potential revenue sources from wind and solar farm leases, battery storage and microgrids, behind the meter power generation, electric transmission lines, data centers, beneficial reuse, cryptocurrency mining and commercial real estate leases. We do not have experience developing many of these commercial opportunities and our efforts to do so may not be successful. We may not be able to correctly identify such commercial opportunities or may be unsuccessful in attracting industry participants to develop projects on our land or to use our resources. The rapidly evolving and competitive nature of many of the industries we are targeting for such development makes it difficult to evaluate the future prospects of these projects. In addition, we have limited insight into emerging trends that may adversely affect the development of such projects on our land, the use of our resources or otherwise, and many of these potential customers, if they were to materialize, would encounter the risks and difficulties frequently experienced by growing companies and project developers in rapidly changing industries, including unpredictable and volatile revenues, increased expenses, an uncertain regulatory environment, novel litigation and corresponding outcomes and changes in business conditions. The viability of this business strategy and the resulting demand for the use of our land and resources by such potential customers will be affected by many factors outside of our control and may not be successful.

A significant portion of our acreage is held by us through leases from the Bureau of Land Management and the State of New Mexico. If we are unable to renew these leases in the future on similar or favorable terms, or at all, or if the activities we and our customers are permitted to conduct on our lands are materially changed or limited, our business and financial condition could be materially and adversely impacted.

As of December 31, 2025, a substantial portion of our land portfolio was held through leases with the Bureau of Land Management (the “BLM”) and the State of New Mexico. As of that date, we owned or controlled approximately 236,000 acres across Texas and New Mexico, including approximately 194,000 acres in the Delaware Basin, of which approximately 157,000 acres are controlled through grazing and mining leases with the State of New Mexico and the BLM, and approximately 37,000 acres are fee acreage. Our leasehold interests on New Mexico state lands are generally grazing and mining leases that grant us certain rights with respect to the surface for initial lease periods ranging from one to five years from inception. Our leasehold interests on federal lands with the BLM are generally grazing leases that grant us rights with respect to the surface for initial lease periods of approximately 10 years from inception. We anticipate renewing each of our existing leases, and any future additional leases, with the BLM and the State of New Mexico in accordance with the terms of each respective instrument; however, there can be no assurance we will be successful in procuring such renewals at all or on attractive terms. These leases do not convey permanent property rights and may be modified, repriced, suspended or not renewed by the issuing agencies based on changes to environmental standards, land use plans or other regulatory criteria.

As the agricultural lessee, we have leased possession and use of the grazing interest of the lands that are subject to the lease. When the surface is excavated or occupied by a surface use implemented

by a third party, we receive payments to compensate us for the impairment of value and costs to repair the physical damage. Additionally, under New Mexico law, the holder of an easement or right-of-way is required to compensate the lessee for the reasonable value of any measurable damage incurred upon improvements or other property belonging to the lessee. These leases form the basis through which we are able to generate fees from our customers that operate on or use our land, as well as generate revenues from the sale of resources present on the acreage we control. On renewal, agencies may impose additional environmental mitigation measures, increase lease rental rates, restrict the timing, area or intensity of permissible activities or alter land use stipulations, any of which could increase our costs or constrain operations. Administrative appeals or litigation challenging agency decisions regarding our leases, rights of way or related approvals could delay planned activities, create uncertainty and result in higher legal and compliance costs. While New Mexico law requires holders of easements or rights of way to compensate the lessee for the reasonable value of measurable damage to the lessee’s improvements or other property, any such compensation may be uncertain, delayed or insufficient to offset lost surface use fees, royalties or broader impacts to our operations.

Our ability to monetize our lands also depends on our customers obtaining and maintaining rights of way and easements, constructing and operating infrastructure and purchasing resources such as water and caliche on or across our acreage. Material restrictions or increased costs on renewal could reduce surface use fees, resource sales and volumetric or other royalty revenues and could require us or our customers to seek alternative locations or permits, increasing costs and delaying projects.

Our surface position is concentrated in the Delaware Basin in southeastern New Mexico, and our leased state and federal tracts are intermingled with our fee acreage and adjacent to third party operations. Constraints or loss of access on leased tracts could reduce utilization of adjacent fee tracts, limit our ability to offer contiguous corridors for rights of way and diminish the value or throughput of infrastructure located on or connected to our lands.

Renewal, modification or assignment of our leases may depend on evolving land use management plans and environmental standards. Changes in political priorities or public policy, including habitat conservation initiatives, drought management measures or greenhouse gas reduction goals, could result in cancellation, suspension or material modification of leases or permits affecting surface disturbing activities, including activities conducted by our customers.

If we are unable to renew our leases with the BLM and the State of New Mexico or applicable state or federal policy or rules regarding land use were to alter the rights granted by such leases, we would lose control of the underlying acreage and the associated fees and royalty revenues generated therefrom, which could adversely impact our business and financial condition. Additionally, if the activities that we and our customers are permitted to conduct on our leased lands are materially changed or limited, our ability to retain existing customers and attract new customers to further develop our surface holdings could be negatively impacted and our business, results of operations and financial condition could be materially and adversely affected as a result.

We intend to receive a portion of our revenues through agreements pursuant to which our customers develop infrastructure on our land. These infrastructure projects involve numerous regulatory, environmental, political and legal uncertainties, including political opposition by environmental groups, local groups and other advocates. Such opposition can take many forms, including the delay or denial of required governmental permits, organized protests, attempts to block or sabotage operations on or around our land, intervention in regulatory or administrative proceedings

related to our customers’ permitting efforts or otherwise involving their assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our customers’ assets or their business. There can be no assurance that such infrastructure will be developed at all or that these projects will be completed on schedule or at an economical cost, and we may not realize the anticipated benefits of such projects.

Our customers may also encounter technical difficulties during the construction of such infrastructure, leading to a reduction in capacity or a shorter useful life. Moreover, our customers may undertake expansion projects to capture anticipated future growth that does not materialize or for which they are unable to acquire new customers. As a result, the new facilities and infrastructure developed by our customers on our acreage may not be able to attract enough demand to achieve their expected investment return, which could materially and adversely affect our results of operations, cash flows and financial position.

In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of operations. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance, and the public may engage in the permitting process, including through intervention in the courts. Broader supply-chain disruptions, driven by changing trade policies, embargoes or customs restrictions, global conflicts, labor unrest or epidemics, can delay materials and equipment availability for pipeline construction and other infrastructure, increasing costs and extending schedules. Negative public perception or changes in governmental policies, priorities or direction could cause the permits our customers require to conduct their operations on and around our land to be withheld, delayed or burdened by requirements that restrict their ability to profitably conduct their business. Any such event that delays or otherwise interrupts the revenues generated by operations on and around our land, or which causes them to make significant expenditures not covered by insurance, could adversely affect payments to us in respect of use of existing infrastructure as well as future development of infrastructure on and around our land.

This offering is conditioned on the occurrence of the Corporate Reorganization, but completion of the Corporate Reorganization and the contributions contemplated in connection with this offering may not occur as currently expected, or at all, which could materially and adversely affect our structure, strategy and the information presented in this prospectus.

The Corporate Reorganization, including the L&E Contribution, the DE Flow Contribution and the Shallow Valley Contribution (collectively, the “Contributions”), is expected to be effected immediately prior to, and is conditioned upon, the consummation of this offering; if this offering is not consummated, the Corporate Reorganization will not be completed. The sequencing and completion of the steps in the Corporate Reorganization may be adjusted for administrative, technical or other reasons, including the timing of required consents and approvals, and remain subject to uncertainties and contingencies outside our control. In addition, actions or decisions by the relevant boards or equityholders of the contributing parties (including withholding or conditioning approvals, changing transaction terms or terminating transaction steps where permitted) could delay, alter or prevent completion of some or all of the Contributions. If any of the Contributions are delayed, altered or fail to occur, our organizational structure, asset base, governance and economic arrangements could differ materially from those described in this prospectus, our pro forma financial information and related disclosures would be rendered inaccurate or require revision and we may need to pursue alternative transactions or strategies, any of which could adversely affect our results of operations, cash flows and financial position.

In connection with the audit of our predecessor’s consolidated financial statements as of and for the year ended December 31, 2025, we identified material weaknesses in our predecessor’s internal control over financial reporting that we are currently working to remediate, which relate to: (a) insufficient segregation of duties in the financial statement reporting and general information technology processes; (b) a lack of sufficient levels of staff with public company, technical accounting, and general information technology experience to maintain proper control activities inclusive of detailed account analysis and reconciliations, and perform risk assessment and monitoring activities; and (c) insufficient general information technology controls, including access, security, and change management controls. 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 the company’s annual or interim financial statements will not be prevented or detected on a timely basis. We have concluded that these material weaknesses in our predecessor’s internal control over financial reporting occurred because our predecessor did not have the necessary business processes, personnel and related internal controls to operate in a manner to satisfy the accounting and financial reporting timeline requirements of a public company.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. Weaknesses affecting our financial close, complex/non-routine transactions (including acquisitions and equity-based compensation), income tax accounting, or information technology general controls could increase the risk of errors in our financial statements that may require correction or restatement and could impair management’s ability to certify the effectiveness of disclosure controls and procedures. As a result of being a public company, we will be required, under Section 404 of the Sarbanes-Oxley Act, to furnish a report by management on, among other things, the effectiveness of our internal control over financial reporting beginning in the year following our first annual report required to be filed with the SEC. This assessment will need to include disclosure of any material weaknesses identified by our management in our internal control over financial reporting. While, as an “emerging growth company,” we are not initially required to obtain an auditor attestation report under Section 404(b), we must still perform a management assessment under Section 404(a) and maintain effective disclosure controls under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), Exchange Act Rules 13a-15 and 15d-15. If we later cease to qualify for exemptions, we will be subject to auditor attestation, which could further increase costs and scrutiny. We will take steps to improve control processes as appropriate, validate through testing that controls are functioning as documented and implement a continuous reporting and improvement process for our internal control over financial reporting. If we identify one or more material weaknesses in our internal control over financial reporting during the evaluation and testing process, we may be unable to conclude that our internal controls are effective. There can be no assurance as to when we will remediate the identified material weaknesses, that our remediation plans will be effective, or that additional material weaknesses will not be identified in the future.

We are focused on designing and implementing effective internal control measures to improve our evaluation of disclosure controls and procedures, including internal control over financial reporting and remediating the material weaknesses identified in our predecessor’s internal controls over financial reporting. We plan to migrate from multiple legacy systems (including QuickBooks) to a new Oracle

NetSuite ERP; implementation challenges may disrupt operations, delay reporting or create control deficiencies. While our remediation plan includes (i) recruiting additional qualified financial reporting and accounting personnel following the completion of this offering to enhance our financial reporting capabilities; (ii) establishing a SOX compliance program and internal audit function (in-house and/or co-sourced) with direct reporting to the audit committee; (iii) enhancing our financial close and reporting processes, policies and controls, including formal documentation, risk assessment and monitoring; (iv) implementing and enforcing information technology general controls over user access, security, change management, backups and logging, and periodic user access reviews; (v) implementing or upgrading enterprise resource planning and related sub-ledger systems and strengthening IT application controls; (vi) enhancing governance over non-routine and complex transactions (including business combinations, equity awards and income taxes) through technical accounting reviews and documented control approvals; and (vii) increasing oversight of and obtaining third-party SOC 1 reports (or equivalent assurance) for critical outsourced service providers and implementing complementary user controls, we cannot assure you that these measures will prevent or avoid potential future material weaknesses. Further, additional weaknesses in our disclosure controls and internal controls over financial reporting may be discovered in the future. Any failure to develop or maintain effective controls or any difficulties encountered in their implementation or improvement could limit our ability to prevent or detect a misstatement of our accounts or disclosures that could result in a material misstatement of our annual or interim financial statements. In such a case, we may be unable to maintain compliance with securities law requirements regarding the timely filing of periodic reports, in addition to the listing requirements of the NYSE and NYSE Texas, and investors may lose confidence in our financial reporting, and our stock price may decline as a result. In addition, control deficiencies could increase audit fees and advisory costs, strain management resources, adversely affect our ability to access the capital markets on acceptable terms, and, in severe cases, lead to debt covenant issues, regulatory investigations, shareholder litigation or delisting risk.

Rapid or sustained technological change in well completions, water sourcing, recycling and produced-water management could decrease demand for our water sales and produced-water transportation, recycling and handling on or around our land, require us or our operating partners to invest in new or unproven technologies at significant cost, and adversely affect our results of operations, cash flows and financial position.

Wide-scale adoption of higher-intensity recycling, beneficial reuse or alternatives to water-based hydraulic fracturing could reduce water demand for completions on our acreage, lower produced-water transport and handling volumes on systems located on or adjacent to our land, or redirect those volumes to infrastructure located off our land. These developments could reduce activity-based surface revenues and per-barrel royalties we receive from our operating partners and customers, including under arrangements that do not include minimum commitments or that are subject to caps, carve-outs or other limitations.

Several operators and service providers are investing in enhanced water recycling and reuse, including treatment of flowback and produced water for recompletion or other industrial uses, and in non-water fracturing techniques utilizing fluids such as propane, carbon dioxide, or nitrogen. If producers on or around our acreage were to shift completions toward higher-recycle designs or waterless fracturing at scale, the demand for our water sales could decline materially, and produced-water gathering and disposal patterns could shift away from facilities on or adjacent to our land, adversely affecting related royalties and fees.

Emerging beneficial-reuse concepts, such as treatment of produced water for industrial processes, non-consumptive agriculture, aquifer or reservoir recharge or technology-sector demand, may, over time, redirect volumes to third-party systems or uses that do not traverse our land or that reduce injection, transportation or handling activity associated with our royalty base, even if such concepts expand the overall market for treated produced water. While we believe beneficial reuse

could create incremental commercial opportunities in the future, the pace, permitting pathways and economics of these applications are uncertain, and commercialization in our areas of operation may not benefit our assets or revenue mix.

Regulatory and permitting dynamics may amplify these technology shifts. In areas affected by seismicity-related constraints, regulators have suspended or limited produced-water injection and established SRAs, which can curtail disposal capacity and accelerate recycling investments by operators. Expanded recycling in response to injection constraints could reduce disposal throughput and associated fees or royalties on systems located on or proximate to our acreage, and prompt producers to re-route volumes to facilities located on third-party lands. In Texas and New Mexico, regulators have implemented protocols and permitting initiatives aimed at addressing seismicity, and additional measures could be adopted in the future that further restrict disposal locations, depths, rates or total volumes. Any of these actions could alter the economics of produced-water handling on our land and increase customers’ incentive to adopt lower-water or waterless completion technologies.

Even where demand persists, our ability to participate in future water-technology trends may depend on access to permits, pore space, ROWs, and long-lead infrastructure. The finite nature of subsurface pore space and evolving preferences for acid-gas or carbon-dioxide injection could compete with or crowd out produced-water disposal, requiring our operating partners to develop alternative facilities on or off our land at higher cost, with extended lead times, or subject to third-party land control. If suitable pore space, ROWs, or permits cannot be obtained on favorable terms near our acreage, volumes could migrate to areas where we do not earn royalties, and our revenues could decline.

Our commercial arrangements mitigate, but do not eliminate, these risks. Certain Midland Basin water-infrastructure revenues are supported by acreage dedications, minimum-volume commitments and long-term agreements, and our Hydrosource Recycling Agreement will include a minimum annual royalty. However, not all agreements contain minimums, and those that do may include caps or other limitations. Even under dedicated or minimum-volume frameworks, customers may satisfy commitments through recycling or alternative handling pathways that reduce brackish water demand or shift produced-water flows away from higher-royalty configurations on our land.

If producers in our areas of operation broadly adopt higher-recycle completions, waterless fracturing or other completion technologies that reduce water intensity, our brackish water sales could decline, potentially on short notice and without compensation under our agreements. Likewise, if produced-water throughput to facilities on or adjacent to our acreage decreases due to seismicity-driven operating limits, beneficial-reuse programs, permitting delays or denials or competition for pore space from other subsurface uses, our surface-use revenues and per-barrel royalties from gathering, transportation, recycling and disposal could be adversely affected. In each case, we and our operating partners could face pressure to invest in new treatment, recycling, desalination or delivery technologies to remain competitive, and such investments may require significant capital, involve execution and permitting risk or fail to generate returns commensurate with the cost. Any of these outcomes could have a material adverse effect on our results of operations, cash flows and financial position.

Inadequate water supplies could have a material adverse effect on our revenues.

One of our significant sources of revenue is the sale of water for use in oil, natural gas and NGLs drilling and completion operations. Our ability to meet the existing and future demand for water depends on an adequate supply of such water from our acreage. Additionally, regulatory restrictions on the use of water and the development of water wells, lack of available water rights, drought, overuse of sources of water, protection of threatened species or habitats or other factors may limit the availability of water. No assurance can be given that we will be able to produce enough water to fully satisfy future customer demand.

If we are unable to produce adequate water supplies, our results of operations, cash flows, and financial position may be adversely affected by, among other things, the following:

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a reduction in the amount of water we sell and reduced revenues therefrom;

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an increase in operating costs; and

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an increase in capital expenditures associated with building pipelines to connect to alternative sources of water supply, new wells to replace those that are no longer in service or are otherwise inadequate to meet the needs of customers, and reservoirs and other facilities to conserve or reclaim water.

We may or may not be able to recover increased operating and capital costs as a result of water shortages on a timely basis, or at all.

Competition in the energy industry is intense, which may adversely affect our and our customers’ and operating partners’ ability to succeed.

The energy industry is intensely competitive, and our customers and operating partners (including Hydrosource and Double Eagle) compete with other companies that may have greater resources. Many of these companies explore for and produce oil, natural gas and NGLs, conduct midstream and refining operations, engage in the recycling and reuse of produced water, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue operational activities during periods of low oil, natural gas and NGLs market prices. Our customers’ and operating partners’ larger and better capitalized competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than they can, which would adversely affect their competitive position. Our customers and operating partners may have fewer financial and human resources than many companies in their industry and may be at a disadvantage in bidding for developmental, transportation, gathering or exploratory prospects, conducting water recycling activities, expanding water recycling infrastructure, and producing or servicing oil, natural gas and NGLs properties. Furthermore, the oil and natural gas 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 customers or, in the case of consolidation amongst our customers, may choose to focus their operations on areas outside of our properties. In addition, our ability to acquire additional properties upon which potential customers may operate in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Other risks as a result of competition and evolving markets may include but are not limited to: pricing pressure driven by new competition; volatile and/or unexpected operating and maintenance costs; lack of sufficient customers or loss of significant customers for the new line of business; increased regulation, including with respect to environmental and geological uses and impacts on industry operations; and uncertainty regarding outsourced third-parties, including our operating partners, providing water treatment recycling services.

We do not operate the sand mines on our land, but certain of our customers may do so in the future. Customers who conduct such operations may be subject to risks normally encountered in the mining industry generally and the sand mining industry in particular. These risks include:

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changes in the price and availability of transportation, natural gas or electricity;

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unanticipated ground, grade or water conditions;

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unforeseen issues with sand quality or suitability for use in oil and gas completion operations;

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unusual or unexpected geological formations or pressures;

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pit wall failures or surface rock falls;

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inclement or hazardous weather conditions;

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environmental hazards contamination and industrial accidents;

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changes in applicable laws and regulations (or the interpretation thereof);

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inability to maintain necessary permits or mining or water rights;

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restrictions on blasting operations;

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inability to obtain necessary mining or production equipment or replacement parts;

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fires, explosions or industrial accidents or other accidents;

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technical difficulties or key equipment failures;

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labor disputes;

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late delivery of supplies; and

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facility shutdowns in response to environmental regulatory actions.

Any of these risks could result in damage to mining properties or production facilities, personal injury, environmental damage, delays in mining or processing, losses or possible legal liability. Any prolonged downtime or shutdowns of mining properties or production facilities could have a material adverse effect on our results of operations, cash flows and financial position.

In addition, transportation and related logistics costs are a significant component of the total delivered cost of sand for oil and natural gas operations. As a result, the cost of transporting sand to the well site is a key factor in our customers’ purchasing decisions. The development of additional in-basin sand mines that are closer to areas of drilling activity could reduce demand for sand produced from our land. For example, a number of companies have announced plans to develop or acquire, are currently developing or expanding, or have recently acquired or completed sand mine projects in the Permian Basin that may be closer to ongoing development activity. Any such reduction in demand for sand from our land could materially affect our results of operations, cash flows and financial position.

Interruption of our customers’ supply chains could negatively impact our business and operations as well as reduce our revenues.

Our business model depends on the timely execution of drilling, completion, water management, midstream buildout and other infrastructure and extraction activities conducted by our customers and operating partners on and around our acreage in the Permian Basin. Any material interruption in our customers’ supply chains, including shortages, delays or increased costs for critical inputs and services, could reduce activity levels on or around our land, delay construction and development and decrease the royalties and fees we earn, thereby adversely affecting our results of operations, cash flows and financial position. Our customers rely on third party goods and services to drill and complete wells and to construct and operate gathering, produced water handling, recycling and disposal systems, power and grid interconnections and other infrastructure on our land, including drilling and completion equipment, pipe, pumps, electrical gear, chemicals, sand and proppant, caliche and road materials, heavy construction equipment and trucking and pipeline services, as well as skilled labor. Disruptions can arise from interruptions in service by third party providers or common carriers, congestion in regional logistics networks, tariffs and other trade restrictions, embargoes or customs

rules, social or labor unrest, natural disasters, epidemics or pandemics, and political disputes or military conflicts, any of which can materially disrupt our customers’ supply chains. If these materials and services are unavailable when needed, are delayed, or can only be procured at uneconomic prices, our customers may defer, curtail or resequence operations, which would negatively impact payments to us under our surface use agreements, water sales, produced water royalties and other revenue streams.

Because a substantial portion of our revenues is activity linked, arising from surface use fees, easements and rights of way, brackish water sales, produced water transportation, recycling and disposal royalties and resource sales such as caliche, extended procurement delays or shortages for our customers can directly reduce the number, pace or scale of projects undertaken on our land. Our operating partners’ systems and commitments amplify this exposure. In the Midland Basin, our DE Flow System has peak handling capacity of approximately 400 MBbls/d and is backed by long-term acreage dedications and minimum volume commitments, but sustained supply chain constraints affecting pipeline, pump, electrical or disposal well equipment could limit throughput growth, delay tie ins or expansions or require reprioritization of projects, thereby reducing royalties and fees we expect to receive. Our Hydrosource Recycling Agreement will include a minimum annual royalty, and it will entitle us to per barrel royalties on certain recycled-water volumes sold across the Permian Basin, but equipment shortages, permitting delays, or inability to procure chemicals, power, trucking or commissioning services at reasonable rates could still defer or diminish activity and related payments to us. Regulatory and permitting constraints, including seismic response plans in Texas and New Mexico and produced water permitting practices, can further slow system adjustments, and weather and natural disasters can restrict site access, damage infrastructure or disrupt power and transportation networks, which together can delay construction and reduce handled volumes and near term revenues.

For example, a frac crew may be deferred because high pressure pumps or replacement parts are unavailable, which would reduce contemporaneous water sales and related surface use fees. Likewise, a delay in procuring electric transformers or switchgear needed to energize a water recycling facility could postpone ramp up of produced water handling volumes and associated royalties, and a shortage of pipe and valves could delay a produced water lateral tie in across our rights of way, deferring throughput and payments under our customers’ contracts. In addition, trade policy actions by the U.S. federal government or foreign governments, including tariffs, sanctions or other restrictions on cross-border movement of equipment and materials, and retaliatory measures, can increase costs, reduce availability and dampen activity levels and demand for the use of our land and resources, while macroeconomic volatility, including interest rates, commodity prices and consolidation among upstream operators, can influence capital allocation and procurement in ways that intensify constraints or extend lead times. Although our agreements often include fee schedules, exclusivity on resources or minimum commitments for certain services, none of these terms fully insulates us from the timing and volume impacts that follow extended supply chain disruptions, and prolonged or severe disruptions could materially and adversely affect our results of operations, cash flows and financial position.

Operational disruptions on or around our land from weather, natural disasters, terrorism or other similar causes could impact our results of operations, cash flows and financial position.

Operational disruptions on or around our land may arise from a wide range of acute and chronic events, including severe weather and climate-related events (such as extreme heat, winter storms and freezes, drought, heavy rainfall and flooding, hail and high winds and tornadoes), geologic events (including earthquakes), wildfires and smoke, power grid instability and outages, cyber-physical attacks, terrorism, sabotage, vandalism, civil unrest or other similar causes. These events could damage or destroy infrastructure located on or near our land, including roads, pad sites, electric transmission and distribution lines, water sourcing and disposal systems, communications networks

and our customers’ gathering, processing and transportation infrastructure, and could result in evacuation orders, road closures, curtailments and extended downtime, any of which could disrupt operations on or around our land.

Additionally, our land is located in the Permian Basin, which is susceptible to periods of extreme heat, high winds and dust storms, intense thunderstorms, hail, flash flooding and winter freezes, as well as seismicity that may be associated with regional subsurface activities. These conditions could limit access to our land or facilities for extended periods, interrupt utility service (including electricity and water) and damage or otherwise impair our customers’ wells, tanks, gathering lines, processing facilities and other infrastructure. In addition, emergency response constraints, workforce safety stand-downs, third-party force majeure declarations and supply chain interruptions (including shortages of steel, sand, chemicals, fuel and replacement parts) could extend related downtime and increase repair costs. Such disruptions could materially and adversely affect our results of operations, cash flows and financial position.

Broader regional or global incidents—such as public health emergencies, pandemics or epidemics; prolonged power or telecommunications outages; or geopolitical conflicts—could similarly disrupt our or our customers’ businesses by restricting access to our land, reducing workforce availability, limiting contractor and supplier capacity, constraining the availability or increasing the cost of critical materials and services and curtailing demand or timing for our customers’ production and development activities.

Any such destruction of or damage to infrastructure or interruptions of operations could materially and adversely affect our results of operations, cash flows and financial position. Moreover, insurance may not be available, sufficient or collectable to cover all resulting losses or increased costs (including higher deductibles, exclusions for certain perils or premium increases upon renewal). Repeated or severe events could also prompt changes in laws, regulations, permitting practices or land-use restrictions applicable to our land or our customers’ operations, which could increase their costs, impose additional operational constraints or delay development. Finally, prolonged disruptions could adversely affect our relationships with customers and counterparties and could lead to disputes or litigation over performance, access, remediation obligations or force majeure, each of which could further impact our financial condition and results of operations.

We or our customers may be unable to obtain and renew permits necessary for operations, which could materially and adversely affect our results of operations, cash flows and financial position.

Our or our customers’ ability to conduct operations is subject to a variety of required permits from various governmental authorities, which may limit such operations, including those associated with oil and natural gas drilling, completion and production activities, disposal or transport of produced water and other hazardous materials or wastes, construction, stormwater, water use, air emissions, mining, and other activities that may be conducted in association with operations on our land. The public often has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. In addition, governmental authorities at the federal, state and local levels often retain significant discretion over these types of permits and may exercise that discretion based on shifting governmental policies, priorities and direction. Accordingly, permits required to conduct our or our customers’ operations may not be issued, maintained or renewed, may not be issued or renewed in a timely fashion or may involve requirements that restrict our or our customers’ ability to economically conduct operations. Limitations on our or our customers’ ability to conduct operations due to the inability to obtain or renew necessary permits or similar approvals could materially and adversely affect our results of operations, cash flows and financial position.

In particular, permits for produced water handling and disposal, air emissions, dredge and fill activities and surface-disturbing construction have become subject to heightened scrutiny, evolving technical standards and more frequent third-party challenges, which can extend timelines, increase costs or result in permit denials or revocations after issuance. In Texas and New Mexico, regulators have adopted seismic response measures and other directives that restrict or suspend certain produced water injection activities within designated areas, and future expansions of these measures could materially limit operations on or around our land, even where facilities previously operated in compliance with prior permits and practices. Moreover, changes in federal and state species-protection regimes and habitat designations, as well as local land-use controls, can impose additional permit conditions, seasonal timing restrictions or area-specific prohibitions that constrain drilling, infrastructure development and waste-handling activities on or adjacent to our acreage. Agencies also retain broad discretion to require enhanced monitoring, mitigation and reporting, or to reopen permits based on new information or policy priorities, which can increase compliance costs and delay development schedules for projects that are integral to our revenue streams. Finally, citizen suits, administrative appeals and other litigation can stay, overturn or narrow permits and approvals, even where applicants have satisfied all regulatory prerequisites, resulting in interruptions to operations, increased legal and consulting expenses and the need to redesign projects or seek alternative sites and ROWs.

The deterioration of the financial condition of our customers could adversely affect our business, and the termination of activities on or around our land by one or more significant customers could materially and adversely affect our results of operations, cash flows and financial position.

For the year ended December 31, 2025, on a pro forma basis, revenues from each of Double Eagle and Devon Energy Corporation individually comprised more than 10% of our total revenues and collectively represented 41.0% of our total revenues. Matador Production Company, Targa Resources Corp., MPLX LP and Chevron Corporation individually each comprised 17.1%, 14.1%, 11.3% and 10.6% of accounts receivable and collectively represented 53.1% of our outstanding accounts receivables at such date on a pro forma basis. For the year ended December 31, 2024, our predecessor’s revenues from Matador Production Company, Coterra, Permian Resources Operating LLC and EOG Resources Inc. each individually comprised more than 10% of our total revenues and collectively represented 68% of our total revenues. Matador Production Company and Texas Pacific Water Resources LLC individually each comprised approximately 59% and 10% of accounts receivable and collectively represented approximately 69% of our outstanding accounts receivables at December 31, 2024. No other customer accounted for more than 10% of our total revenues or outstanding accounts receivable.

We expect to continue to depend on key customers to support our revenues for the foreseeable future, and although most of our customers on our land are under long-term contracts, each of these customers has the right to reduce or cease operations on our acreage at their sole discretion under certain circumstances, as our contracts with such customers generally do not contain minimum commitment provisions for land use or brackish water volumes to be purchased. See “Business—Customers; Material Contracts and Marketing” for further information on our agreements with these customers. The loss of revenue derived from any of these customers’ operations on our land could adversely affect our results of operations, cash flows and financial position. During times when the oil and natural gas markets weaken, our customers are more likely to experience financial difficulties, including generating less cash flow due to lower oil and natural gas prices and being unable to access or receive favorable terms in connection with debt or equity financing, which could result in a reduction in our customers’ activities on or around our land. Furthermore, the determination by a customer to initiate or maintain activities on or around our land largely depends on the location of our surface acreage relative to the nature and location of such customer’s operations and such customer’s need for the use of our land and resources. Our customers are limited to entities operating on and around our acreage in the Permian Basin.

We cannot assure you that any of our customers will continue to do business with us. If these customers do not maintain their activities on or around our land, their demand for use of our land and resources will be reduced. The loss of revenue from key customers, failure to renew contracts upon expiration, or a sustained decrease in demand by key customers could result in a substantial loss of revenues and could materially and adversely affect our results of operations, cash flows and financial position.

The unavailability, high cost or shortages of equipment, raw materials, supplies or personnel may restrict or result in increased costs for our customers related to their operations on and around our land.

The energy industry is cyclical, which can result in shortages of equipment, raw materials, supplies and personnel. When shortages occur, the costs and delivery times of equipment and supplies increase and demand for, and incentive costs and wage rates of, qualified personnel also rise with increases in demand. In addition, capital and operating costs in the energy industry have generally risen during periods of increasing commodity prices as operators seek to increase production to capitalize on higher commodity prices. 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, the operators on and around our land rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. The cost of oilfield services typically fluctuates based on demand for those services, and the increase in commodity prices and supply constraints due to tariffs, the conflicts in Ukraine and the Middle East, elevated interest rates and associated policies of the Federal Reserve or otherwise, have increased the cost of oilfield services. While we believe the operators on and around our land currently have strong relationships with the oilfield service companies they contract with, there is no assurance that such operators will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. If such operators are unable to secure the equipment and supplies they require at reasonable costs, our financial condition and results of operations could suffer.

Because a substantial portion of our revenues is activity-linked, extended procurement delays or shortages for our customers can directly reduce the number, pace or scale of projects undertaken on or around our land and diminish the royalties and fees we earn, even where we have long-term agreements, acreage dedications or minimum commitments. For example, a frac crew may be deferred because high-pressure pumps or replacement parts are unavailable, which would reduce contemporaneous water sales and related surface-use fees; a delay in procuring electric transformers or switchgear needed to energize a water recycling facility could postpone ramp-up of produced-water handling volumes and associated per-barrel royalties; and a shortage of pipe and valves could delay a produced-water lateral tie-in across our rights of way, deferring throughput and payments under our customers’ contracts. Broader supply-chain disruptions, including tariffs, sanctions or other trade restrictions, embargoes or customs rules, social or labor unrest, natural disasters, epidemics or pandemics, and political disputes or military conflicts, can materially disrupt our customers’ supply chains and elevate costs, further dampening activity levels and demand for the use of our land and resources. Although our commercial arrangements often include specified fee schedules, exclusivity on certain resources and, in some cases, minimum-volume commitments, these provisions do not eliminate the timing and volume risks associated with supply-chain constraints, and prolonged or severe disruptions could materially and adversely affect our results of operations, cash flows and financial position.

We may experience delays in the payment of royalties and fees and be unable to replace customers or operators on our land that do not make required payments to us, and we may not be able to terminate our agreements with defaulting customers or operators that declare bankruptcy.

We may experience delays in receiving royalties, fees and other payments from our customers or operators on our land. A failure on the part of a customer or operator to make royalty payments typically gives us the right to enforce payment obligations under the agreement and/or terminate the agreement. With respect to a customer or operator that is subject to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), our right to enforce or terminate the agreement for any defaults, including nonpayment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt customer or operator would have a substantial period of time to decide whether to ultimately reject or assume our agreement, which could prevent the execution of a new agreement or the assignment of the existing agreement to another customer or operator. In the event that the customer or operator rejected the agreement, 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 agreement with a new customer or operator, the replacement customer or operator may not achieve the same levels of activity on or around our land at the same price as the customer or operator it replaced.

Additionally, we are subject to the risk of loss resulting from nonpayment or nonperformance by our customers of their respective obligations. Although we maintain policies and procedures to limit such risks, our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them of their respective obligations, and our inability to collect on outstanding receivables or find substitute customers could have an adverse effect on our results of operations, cash flows and financial position. A decline in oil, natural gas and NGLs prices could negatively impact the financial condition of our customers and sustained lower prices could impact their ability to meet their obligations to us. Further, our contract counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent one or more of our contract counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the Bankruptcy Code. Any material nonpayment or nonperformance by our contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could adversely affect our results of operations, cash flows and financial position.

The fees charged to customers under our agreements for the gathering, transportation or handling of all our resources may not escalate sufficiently to cover increases in costs.

Though we incorporate inflation escalators in most of our long-term customer contracts, contractual provisions providing for inflation escalators in certain contracts are subject to caps, which may limit the amount of any single pricing increase, and may also vary as to the commencement date of such increases and the timing and calculation of the applicable adjustment. As a result, inflation may outpace the revenue adjustments provided by those provisions. Our customers 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 customers 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 customers’ 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 the revenues received in respect of our customers’ operations on or around our land and consequently our business, results of operations and financial condition.

We and our customers may be subject to claims for personal injury and property damage, catastrophic events, and those related to contamination resulting from our customers’ operations, which could have a material and adverse effect on our results of operations, cash flows and financial position.

We and our customers may be subject to hazards and operational risks associated with their operations, which include, or may in the future include, oil and natural gas drilling, completion and production activities, sand mining, production and distribution of water, water handling, waste disposal, construction and operation of non-hazardous oilfield reclamation and solid waste facilities, power storage, microgrids, fuel stations, battery, wind and/or solar facilities, and any other operations, including our associated operations, that may occur on our properties now or in the future. These hazards may include the risk of fire, explosions, blowouts, seismic events, surface cratering, uncontrollable flows of oil, natural gas, NGLs and produced water, pipe or pipeline failures, abnormally pressured formations and pore spaces, casing collapses and environmental hazards such as oil and NGL spills, natural gas leaks and ruptures or discharges of toxic gases, release of hazardous materials into the environment and worker health and safety issues. The occurrence of any of these events could result in interruption of our customers’ operations or substantial losses to us and our customers 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 could have a material adverse effect on our results of operations, cash flows and financial position.

Litigation arising from operations on our properties may cause us to be named as a defendant in lawsuits asserting potentially large claims, including claims for defense, indemnity, and exemplary damages. Our business entails frequent interaction with landowners, regulators and E&P counterparties that can give rise to disputes, including access, damages or environmental claims. We generally seek indemnity from our customers for liabilities arising from their operations on our land, and we maintain what we believe is customary and reasonable insurance to protect our business against these potential losses, but such indemnity and insurance may not be adequate to cover our liabilities, and we are not fully protected or insured against all risks.

Subject to certain exceptions, our customers assume responsibility for, including control and removal of, all other pollution or contamination that may result from their operations on our properties. We may have liability in such cases if we are grossly negligent or commit willful acts, or as owners of the land under laws that impose strict, joint and several liability for pollution clean-up, such as CERCLA (as defined herein). Our customers generally agree to indemnify and defend us against claims relating to contamination resulting from their operations and related closure and remedial obligations, damage or loss of a well, reservoir, geological formation, underground strata or water resources, or the loss of oil, natural gas, mineral or water, but sometimes such indemnity and defense is subject to exceptions for claims for gross negligence or willful misconduct, and we may not be able to collect under these indemnities if the applicable customer is in financial distress. Our customers also generally assume responsibility for claims arising from their employees’ personal injury or death, or the damage or loss of their property, to the extent that their employees are injured or their properties are damaged by operations on our properties, but sometimes such indemnity and defense is subject to exceptions for claims resulting from our gross negligence or willful misconduct, and we may not be able to collect under these indemnities if the applicable customer is in financial distress. Further, we might not succeed in enforcing such contractual risk allocation or might incur an unforeseen liability falling outside the scope of such risk allocation.

The occurrence of any of these events could result in interruption of our customers’ operations or substantial losses to us or our customers, which could materially and adversely affect our results of operations, cash flows and financial position.

Our insurance coverage may not fully cover our losses, and we may in the future encounter increased costs related to, and lack of availability of, insurance.

While we maintain insurance coverage at levels that we believe are reasonable and prudent for a Permian Basin-focused land management company, our policies are subject to deductibles, self-insured retentions, exclusions and sublimits, including for pollution, cyber, named storms and seismic events, and certain risks may be uninsurable or uneconomic to insure at desired limits. We can provide no assurance that our current levels of insurance will be sufficient to cover any losses that we have incurred or may incur in the future, whether due to these retentions, coverage challenges or other limitations, and proceeds, if any, may not be paid in a timely manner. Moreover, we may not be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable, including as insurers raise rates or reduce capacity for traditional energy-related risks.

Our business model depends heavily on activities conducted by our customers and operating partners on and around our surface acreage, and although our contracts generally require them to carry specified insurance, name us as an additional insured on a primary and non-contributory basis, provide waivers of subrogation and furnish evidence of coverage, such obligations are subject to carve-outs (including for our gross negligence or willful misconduct), counterparty credit risk and claims-made program limitations. As a result, we cannot guarantee continuous compliance or that such policies will respond to all losses. We also generally seek indemnities from customers for liabilities arising from their operations, but those indemnities may be limited or unenforceable and, if a counterparty is in financial distress, may not be collectible.

Because our acreage is located in the Permian Basin, our exposure to extreme weather and natural hazards, such as storms, floods, tornadoes, droughts, wildfires and seismic events, can increase the likelihood of property damage and operational interruptions that may fall within policy exclusions, sublimits or elevated deductibles, or for which insurance may be unavailable. In addition, our growing reliance, and that of our customers and vendors, on information technology systems supporting activities such as produced water handling, sourcing and delivery, and rights-of-way administration exposes us to cyber incidents. While we maintain commercially reasonable safeguards, cyber risks are evolving and may exceed available insurance, particularly where policies include cyber sublimits or exclusions. If a significant event were to occur and its consequences were not covered by insurance or not fully insured, or if payment of a major insurance claim were significantly delayed or denied, our results of operations, cash flows and financial position could be materially and adversely affected.

Cyber incidents or attacks targeting systems and infrastructure used by the energy and infrastructure sectors, or systems we and third-parties use to administer surface access, SUAs, easements, ROWs and water midstream activities on and around our acreage, may adversely impact our operations, and a cyber incident or systems failure could result in information theft, data corruption or operational disruption and our results of operations, cash flows and financial position may be adversely impacted.

We and our customers increasingly rely on uninterrupted information technology systems and digital technologies to operate our respective businesses. This reliance extends to the majority of our and our customers’ operations, from monitoring and managing critical infrastructure to processing and storing proprietary and sensitive information, including systems supporting activities on and around our acreage, such as produced water gathering and disposal (including SWDs), water sourcing and

delivery, recycling facilities, pipeline and power transmission ROWs, wind leases and other infrastructure. Our information technology systems and networks, and those of our customers, vendors and other business partners, are subject to damage or interruption from cyberattacks, power outages, computer and telecommunications failures, catastrophic events, such as natural disasters or acts of war or terrorism, usage errors by our employees or other personnel and other events unforeseen or generally beyond our control. Damage or interruption to information technology systems could result in significant costs and may lead to significant liability, loss of critical data, reputational damage and disruptions to services or operations.

Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Cyber incidents, including deliberate attacks, have increased in frequency globally, with energy-related assets particularly at risk. Due to the critical nature of these assets, any such attack on energy infrastructure could result in widespread service disruptions and challenges in maintaining public trust. The U.S. government has issued public warnings that specifically indicate energy assets could be targets of cybersecurity threats. Our technologies, systems and networks, and those of our customers, affiliates, vendors and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized access, release, gathering, monitoring, corruption, misuse or destruction of proprietary, personal and other information, or other disruption of business operations. Any such event could lead to significant liability, loss of critical data, reputational damage and disruptions to our services or operations.

While we have implemented and maintain commercially reasonable security measures and safeguards, such security measures and safeguards may not be sufficient to protect against an attack. We do not own or operate most of the infrastructure on our land, which increases our dependence on the cybersecurity and operational resilience of third parties. Attackers are increasingly using advances in technologies, such as artificial intelligence and encryption bypasses that may evade our efforts. Emerging artificial intelligence technologies may improve or expand the capabilities of malicious third parties in a way we cannot predict at this time, including being used to develop new hacking tools, exploit vulnerabilities, obscure malicious activities and increase the difficulty of detecting threats. Moreover, some of our networks and systems are managed by third-party service providers and are not under our direct control. We regularly enter into transactions with third parties, some of whom may have less sophisticated electronic systems or networks and may be more vulnerable to cyberattacks. Our reliance on these third parties means that any vulnerability in their systems could propagate to our own systems, increasing our risk exposure despite our internal controls.

In addition, certain cyber incidents, such as surveillance, ransomware, deepfake-based social engineering attacks, and credential stuffing, may remain undetected for some period of time, and cybersecurity incidents and attacks are continually evolving and unpredictable. As cyber incidents and attacks continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. While we utilize various procedures and controls to reduce the risk of the occurrence of cyber incidents, there can be no assurance that our business, finances, systems and assets will not be compromised in a cyber incident. Any failure or perceived failure to detect or respond effectively to a cybersecurity incident could lead to significant liability, undermine shareholder and stakeholder trust and negatively impact business continuity. Furthermore, we are subject to an evolving regulatory landscape, including state, federal and international data privacy laws that require rigorous cybersecurity standards and standards relating to artificial intelligence. Compliance with various data privacy and cybersecurity regulations may impose significant costs, and any perceived or actual failure to comply could result in regulatory penalties, litigation and reputational harm.

The Unaudited Pro Forma Condensed Consolidated Financial Statements, and any other pro forma data, included herein are based on a number of preliminary estimates and assumptions and our actual results of operations, cash flows and financial position may differ materially.

The Unaudited Pro Forma Condensed Consolidated Financial Statements, and any other pro forma or pro forma, as adjusted information included in this prospectus, are based on numerous preliminary estimates and assumptions and are presented for illustrative purposes only. Our actual results of operations, cash flows and financial position following the contemplated transactions may differ materially and adversely from such pro forma or pro forma, as adjusted information. The pro forma and pro forma, as adjusted presentations reflect the effects of specific transactions and structuring steps, including the Accelerated Acquisition, the exclusion of the Excluded Assets, the Shallow Valley Contribution, the DE Flow Contribution, the Up-C Reorganization and this offering, as well as the application of the net proceeds therefrom as described under “Use of Proceeds,” and are not necessarily indicative of the results that would have been achieved had those transactions occurred on the dates assumed, nor are they indicative of our future results. Our pro forma information is derived from historical financial statements of L&E (our predecessor), and incorporates transaction accounting and reclassification adjustments to conform presentations across L&E, Accelerated, DE Flow and Shallow Valley. These adjustments are preliminary, based on currently available information and management assumptions that we believe are reasonable, but actual purchase accounting and conforming adjustments could differ materially once final valuations and alignments are completed. The Unaudited Pro Forma Condensed Consolidated Financial Statements have been prepared with the predecessor as the accounting acquirer under GAAP using the acquisition method in accordance with ASC 805 and fair value concepts under ASC 820, and reflect preliminary estimates of the fair value of assets to be acquired and liabilities to be assumed. These estimates are subject to change during the measurement period (which may extend up to one year from each acquisition date) as additional information becomes available, and any such changes could materially affect future depreciation, amortization, deferred taxes, goodwill, intangible asset values and related expenses.

Because the pro forma, as adjusted presentations assume this offering and the Up-C Reorganization occurred at specified dates, they embed assumptions regarding corporate structure, equity ownership and non-controlling interest that may not reflect our actual post-offering capitalization over time, particularly as OpCo Unitholders exercise redemption or exchange rights and our relative interest in OpCo increases, which may reduce comparability with historical or pro forma periods. The pro forma, as adjusted information assumes an application of net offering proceeds that includes repayment and termination of our Predecessor Credit Facility and funding for general corporate purposes. Changes in actual offering size, pricing, exercise of the underwriters’ option to purchase additional Class A shares, timing of closing or changes in the planned uses of proceeds would result in material differences from the pro forma balance sheet, capitalization and earnings profiles presented. Our pro forma, as adjusted tax provision reflects an assumed blended statutory tax rate associated with our election to be taxed as a corporation. Actual effective tax rates may differ due to changes in tax laws, regulations, apportionment, state mix, valuation allowances, permanent differences or the final purchase accounting for acquired assets and liabilities. The pro forma presentations necessarily exclude various incremental operating expenses and one-time costs, including certain public company costs, integration and transition costs and systems alignment expenses associated with combining the contributed assets and entities. Our actual results after the Pro Forma Transactions will reflect such costs and may therefore be less favorable than the unaudited pro forma information. The Accelerated Acquisition financing, warrant issuances and subsequent modifications, as well as any fair value changes for liability-classified warrants, could result in earnings volatility or differences from pro forma assumptions if accounting conclusions or fair value measurements differ from preliminary estimates.

Our pro forma results incorporate adjustments related to the exclusion of the Excluded Assets and the inclusion of the DE Flow Contribution and Shallow Valley Contribution. If the final terms,

closing dates, fair value determinations, asset performance or integration outcomes differ from the assumptions reflected in the pro forma information, our actual revenues, margins, depreciation and amortization and cash flows could vary materially. Pro forma presentations rely on historical carve-out financial statements for certain contributed businesses and on reclassification adjustments to align accounting policies and presentation. Inaccuracies, limitations or subsequent updates to such historical financial statements, or differences in finalized policy alignments, could materially change the effects reflected in our unaudited pro forma financial information. In addition, assumptions embedded in our pro forma liquidity and capitalization, including the availability and expected use of the Credit Facility, our anticipated cash needs and our projected ability to fund operations and potential dividends from Free Cash Flow, are inherently uncertain and depend on factors outside our control, including activity on our acreage and broader market conditions. Adverse developments could require different financing strategies than those reflected in the pro forma presentations. For these reasons, investors should not place undue reliance on the Unaudited Pro Forma Condensed Consolidated Financial Statements or other pro forma, or pro forma, as adjusted information. Future results may differ from the pro forma information and the differences may be material and adverse.

Title to the properties in which we have an interest may be impaired by title defects.

Title defects can arise in numerous ways that may not be apparent from public records or typical broker-level examinations, including gaps or breaks in the chain of title; conflicting conveyances and reservations of mineral, royalty, overriding royalty or non-participating royalty interests; unrecorded liens or claims; heirship, probate or estate matters; survey or boundary discrepancies; prior lease terminations or expirations; pooling, unitization or spacing irregularities; and failures to properly record, authorize or index instruments in applicable counties or agencies. Any such defect may result in challenges to our ownership, curative costs, delays in development on or around our land, or the loss or dilution of our interests. Even when defects are identified, curative actions may be impracticable, costly or time-consuming, and there is no assurance we will be able to obtain satisfactory remedies. Curing title defects can require additional title work, new conveyances, ratifications, stipulations, corrective instruments, quiet title actions or other litigation, consents from third parties or governmental authorities, and payment of consideration to adverse claimants, any of which may delay commercial arrangements and increase transaction or operating costs. Moreover, sellers may be unwilling or unable to provide effective indemnities or other protection against all or part of identified problems, and title insurance may be unavailable or limited in scope. Our operations depend on a mosaic of surface and easement interests assembled over time; defects, competing claims, restrictive terms or challenges by counterparties could interrupt operations, increase costs or reduce revenues. Disputes regarding surface damages, access or use restrictions can be frequent and costly in our operating areas, and an adverse outcome could affect service availability or pricing. Title deficiencies can directly affect our revenues and liquidity.

New trade policies, such as tariffs, could adversely affect our operations, costs, and business.

There is currently significant uncertainty regarding the future relationship between the United States and various other countries arising from changes that may be implemented by the current presidential administration, including with respect to trade policies, treaties, tariffs, taxes, and other limitations on cross-border operations. Any actions taken by the United States’ federal government that restrict or otherwise impact the economics of trade—including tariffs, trade barriers, or other similar measures—could have the potential to disrupt existing supply chains and trigger retaliatory efforts by other countries, including the imposition of tariffs, raising taxation, setting foreign exchange or capital controls, or establishing embargos, sanctions, or other import/export restrictions, thereby negatively impacting our business, both directly and indirectly. These developments, or the perception that more of them could occur, may materially adversely affect the global economy and stability of global financial markets, potentially reducing trade and depressing economic activity. Such changes in international

trade policies may result in direct impact to our business or that of our operators through increased costs, changes in business prospects or operating results, which could adversely affect our financial condition. The extent of such impacts cannot be predicted at this time.

Risks Related to Environmental and Regulatory Matters

Oil, natural gas and NGLs operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our customers, and failure to comply could result in our customers incurring significant liabilities, either of which may impact our customers’ willingness to operate on our surface acreage and may subject us to strict, as well as joint and several, liability for contamination resulting from such failure, even if we do not have control over such operations. We generally do not control our customers’ operations on our surface acreage and cannot ensure their compliance with applicable requirements, which may increase our residual exposure notwithstanding contractual indemnities and insurance.

The value of the revenues we receive from the use of our surface acreage and resources by our customers is substantially based on the level of oil and natural gas drilling and production and transportation and gathering activities with respect thereto. Our customers’ level of activities on our surface acreage is subject to various federal, state and local governmental laws and regulations that may change from time to time in response to economic and political conditions. Matters subject to these laws and regulations include drilling operations, production, gathering, transportation and distribution activities, water sourcing and disposal, air emissions, discharges or releases of pollutants or wastes, storage, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil, natural gas and NGLs. More recently, certain state agencies have implemented seismic-response measures and permitting constraints that affect produced-water injection and related recycling, which can curtail drilling and completion cadence on or around our acreage.

In addition, the production, handling, storage, gathering and transportation of oil, natural gas and NGLs as well as the remediation, emission and disposal of oil, natural gas and NGLs wastes, by-products thereof and other substances and materials produced or used in connection with oil, natural gas and NGLs operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of worker safety and health, natural resources and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions on our customers, including administrative, civil or criminal penalties, permit, license or authorization revocations or suspensions, requirements for additional pollution controls, imposition of cleanup and site restoration costs and liens, and injunctions limiting or prohibiting some or all of our customers’ operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, species protection and waste management, among other matters.

Laws and regulations governing E&P activities may also affect production levels. Certain of our customers must comply with federal, state and local laws and regulations governing conservation matters, including:

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provisions related to the unitization or pooling of oil and natural gas properties;

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the establishment of maximum rates of production from wells;

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the spacing of wells;

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the plugging and abandonment of wells; and

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the removal of related production equipment.

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations. The Pipeline and Hazardous Materials Safety Administration has completed several regulatory actions over the last few years, consistent with the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020, which significantly expanded reporting and safety requirements for operators of gas gathering pipelines, including previously unregulated pipelines. Compliance with such regulations may require increased capital costs for third-party oil, natural gas and NGLs transporters. These transporters may attempt to pass on such costs to our customers, which in turn could affect the profitability of our surface acreage. Our customers must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent our customers are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.

Moreover, under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties owned by us even if a customer’s operations caused the contamination. In addition, our customers may be liable for the remediation of contamination at currently or formerly operated facilities and facilities of third parties that received waste generated by our customers’ operations, regardless of whether such contamination resulted from the conduct of others or from consequences of actions that were in compliance with all applicable environmental laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, safety and health impacts of the operations of our customers. While we seek to mitigate any potential liability we may have through indemnification, customary insurance policies and remediation activities, in each case, required under our contracts, as well as reliance on state funded programs (such as the Texas Railroad Commission’s (the “TRRC”) Orphan Well Program) for coverage of plugging and abandonment liabilities, if any of our customers declared bankruptcy or if our insurance policies did not fully cover such liabilities, we may not be fully protected. Additionally, although we generally have rights to inspect our property and the operations thereon, we may not become aware of all environmental, safety and health matters. The trend of more expansive and stringent environmental legislation and regulations applied to extractive industries, such as those in which our customers engage, could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental actions are taken that restrict our customers’ operations or impose more stringent and costly operating requirements, our customers’ operations could face increased costs and potential curtailment of operations, which consequently could indirectly materially and adversely affect our business, cash flows, prospects, financial condition or results of operations. Please read “Business—Regulation of Environmental and Occupational Safety and Health Matters” for a description of the laws and regulations that affect our customers and that may affect us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause certain of our customers to incur increased costs, additional operating restrictions or delays and a reduction in potential drilling locations. Any such impacts could, in turn, reduce activity levels and related payments on or around our surface acreage.

Certain of our customers engage in hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas and NGLs from dense subsurface rock formations. The process involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. We do not operate our customers’ wells and therefore have limited ability to influence their compliance with evolving hydraulic fracturing requirements.

Currently, hydraulic fracturing (other than that using diesel) is generally exempt from regulation under the Underground Injection Control (“UIC”) program of the U.S. Safe Drinking Water Act (the “SDWA”) and is typically regulated by state oil and gas commissions or similar agencies. While our customers 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. In addition, the U.S. Congress (“Congress”) from time to time has considered legislation to amend the SDWA to remove the exemption currently available to hydraulic fracturing, which would place additional regulatory burdens on hydraulic fracturing operations including requirements to obtain a permit prior to commencing operations adhering to certain construction requirements, to establish financial assurance and to require reporting and disclosure of the chemicals used in those operations. If enacted, these changes could require permit acquisition prior to completions, redesign of job plans and equipment, and extended timelines to obtain or modify authorizations. This legislation has not been enacted.

Several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the U.S. Environmental Protection Agency (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. In addition, the BLM finalized two rules in April and May 2024, increasing royalty rates, rentals and minimum bids, and updating the agency’s interpretation of its mandate that conservation is a use of federal land on par with mineral extraction and other uses (“Public Lands Rule”). In September 2025, the Department of the Interior announced its proposal to rescind the Public Lands Rule. Further, in May 2025, the BLM announced a policy designed to expedite the oil and gas leasing process on public lands. In July 2025, the One Big Beautiful Bill Act (“OBBB Act”) was signed into law, which included provisions directing expanded and expedited oil and gas leasing, removing restrictions on leasing and decreasing the royalty rate. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Agency actions and legislative initiatives can be subject to judicial challenges, stays or reversals, creating uncertainty around timing and compliance obligations for operators planning completions.

Moreover, some states, including Texas, have adopted, and other states are considering adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. Further, state and local governmental entities have exercised the regulatory powers to regulate, curtail or in some cases prohibit hydraulic fracturing. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. Some jurisdictions have pursued set-back requirements, traffic and noise limitations, or ballot initiatives that effectively limit or preclude completions in proximity to populated or environmentally sensitive areas, which could reduce the number of economic locations near our acreage. Expanded disclosure mandates or registry reporting may also increase compliance costs and raise trade-secret and supply-chain considerations for our customers and their service providers.

Increased regulation and attention given to the hydraulic fracturing process, including the disposal of produced water gathered from drilling and production activities, could lead to greater opposition to, and litigation concerning, oil, natural gas and NGLs production activities using hydraulic fracturing techniques in areas where we own surface acreage and/or mineral and royalty interests. Permitting challenges under environmental review statutes and private litigation seeking injunctive relief can delay or disrupt drilling and completion schedules, which may defer or reduce surface-use payments to us. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil, natural gas and NGLs, including from the development of

shale plays, or could make it more difficult for such customers to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in certain of our customers’ completion of new oil and natural gas wells on our properties and an associated decrease in the production attributable to our interests, which could have a material adverse effect on our business, financial condition and results of operations. In addition, tighter constraints on hydraulic fracturing or related water management could reduce demand for our water sales, ROWs and other surface services even where drilling continues.

Our operating partners handle produced water in connection with customers’ drilling and production operations pursuant to permits issued by governmental authorities overseeing such produced water handling activities. While these permits are issued pursuant to existing laws and regulations, these legal and regulatory requirements are subject to change, which could result in the imposition of more stringent permitting or operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such produced water handling activities. For example, there exists a growing concern that the injection of produced water into certain produced water handling facilities triggers seismic activity in certain areas, including New Mexico and Texas, where our surface acreage is located. This has led to the creation of operator-led response plans in certain areas in New Mexico or Texas by the NMOCD and the TRRC, respectively, which can include the TRRC suspending or declining to issue produced water handling permits, restrictions on the amount of material that can be handled or requiring producers to cease disposal in certain produced water handling facilities and in areas within the vicinity of seismic events. Regulators may also require enhanced seismic monitoring, pressure management plans, maximum allowable surface pressures, volumetric caps, step-rate testing, or temporary shut-ins for produced water handling facilities in affected areas. Because we do not operate these facilities, our ability to ensure compliance or to mitigate resulting curtailments is limited, notwithstanding contractual rights and indemnities.

State and federal regulatory agencies are continuing to study the possible linkage between oil and natural gas activity and induced seismicity. The U.S. Geological Survey has identified Texas and New Mexico as two of six states with the most significant hazards from induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that produced water handling operations have caused seismic events, caused damage to neighboring properties or otherwise violated state and federal regulations related to waste disposal. Adverse outcomes in such proceedings, or expanded enforcement, could result in injunctions, monetary penalties, mandatory facility modifications or shutdowns, and increased insurance and compliance costs. In response to these concerns, regulators in some states have imposed, or are considering imposing, additional requirements, including requirements regarding produced water handling permits, to assess the relationship between seismicity and the use of such produced water handling facilities. For example, the TRRC previously published a rule governing permitting or re-permitting of produced water handling facilities that would require, among other things, the submission of information on seismic events occurring within a specified radius of the produced water handling facility location, as well as logs, geologic cross sections and structure maps relating to the water handling area in question. On certain occasions, state regulatory agencies have suspended produced water handling facilities within the boundaries of certain SRAs. Although our acreage is not currently included in any SRA, there can be no assurance that all or a portion of our acreage will not be included in an SRA in the future. Separately, in November 2021, the NMOCD implemented protocols requiring producers to take various actions within a specified proximity of certain seismic activity, including a requirement to limit injection rates if a

seismic event of a certain magnitude occurs within a specified radius of a produced water handling facility. Further, on July 11, 2024, the NMOCD announced the administrative cancellation of 75 pending permit applications for UIC Class II wells within the 10-mile County Line SRA, due to the potential for increased seismicity within the area. Constraints of this nature can accelerate shifts toward recycling and re-routing of produced water, potentially increasing costs for customers and reducing throughput or activity on or near our acreage. The adoption and implementation of any new laws or regulations that restrict our customers’ ability to handle produced water gathered from E&P companies, by limiting volumes, fees, produced water handling facility locations or otherwise, or requiring us to shut down produced water handling facilities, could limit existing operations and future development activity in affected areas by our customers, including Hydrosource, and reduce their demand for the use of our land, resources and water management solutions, which could have a material adverse effect on our results of operations, cash flows and financial position.

Additionally, studies have linked hydraulic fracturing related activities with subsidence and expansion. Both the injection of produced water into produced water facilities and the extraction of water, oil, natural gas or mineral resources from the ground can result in surface subsidence and uplifts caused by changes underground (such as, but not limited to, loss of volume and pressure depletion). Such changes underground have been linked to various geological and environmental hazards, such as alteration of local ecosystems and impacts upon local communities, including a potential increase in seismic activity and the formation of sinkholes. In response, agencies or local authorities may require geotechnical studies, elevation and microseismic monitoring, corrective action plans, bonding or mitigation, or impose site-specific restrictions on injection or extraction activities. Any new laws or regulations that may be adopted and implemented with respect to addressing subsidence and expansion risks may lead to restrictions upon our operations, which could have a material and adverse effect on our results of operations, cash flows and financial position. Even where continued operations are permitted, compliance obligations could delay projects, increase costs or reduce available pore space and ROWs, which may shift volumes and activity off our land.

Restrictions on the ability of our customers to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of oil, natural gas and NGLs production during both the drilling and hydraulic fracturing processes. Under many of our SUAs, customers are required to purchase from us or our operating partners the water used in their operations. We source water to fulfill our customers’ needs through a variety of rights and agreements, including the Recycled Water Supply Agreement and the Hydrosource Recycling Agreement. Additionally, our commercial water wells in New Mexico, water infrastructure in Texas and off-ranch water from third-party sources allow us to produce and sell in excess of 200 MMBbls of water per year. On certain areas of our ranches, our customers’ demand for water has exceeded our annual capacity over the last several years.

There can be no guarantee that we will have access to sufficient amounts of water to meet our customers’ needs. If our customers are unable to obtain water to use in their operations from local sources, or if our operators are unable to effectively utilize flowback water, they may be unable to economically drill for, or produce, oil, natural gas and NGLs from our properties, which could have an adverse effect on our financial condition, results of operations and cash flows.

Over the past several years, portions of Texas and New Mexico have experienced drought conditions. As a result of the droughts, 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. Because we generate fee revenue by providing water to our customers, restrictions on the use of water for hydraulic fracturing or other oil and gas operations could have an adverse effect on our financial condition, results of operation and cash flows.

Our reliance on revenue generated from water sales and produced water handling operations exposes us to potential financial and regulatory risks.

There are unique risks associated with handling produced water, and the legal requirements related to handling produced water into a non-producing geologic formation by means of produced water handling facilities are subject to change based on concerns of the public or governmental authorities. In particular, evolving seismic-response measures, pore-space access constraints, and pressure-management directives can limit injection options or require significant operational modifications, even for facilities that previously operated in compliance with permits. There remains substantial uncertainty regarding the handling of produced water by means of produced water handling facilities, the regulation of which could have a material and adverse effect on us, our operating partners or our customers in a manner that cannot be predicted due to such uncertainty. Moreover, not all of our commercial arrangements include minimum-volume commitments or they may be subject to caps or carve-outs, which limits protection against volume and timing risk if customers curtail or re-route water flows. These include liabilities related to the handling, treatment, storage, disposal, transport, release and use of radioactive materials, which could be in produced water, and uncertainties regarding the ultimate, and potential exposure to, technical and financial risks associated with modifying or decommissioning produced water handling facilities. Produced water and related residuals may contain naturally occurring radioactive material and technologically enhanced NORM hydrogen sulfide, or other constituents subject to evolving standards, and any reclassification of certain wastes or tightening of exposure limits could increase compliance and disposal costs and restrict available outlets. Federal or state regulatory agencies could require the shutdown of produced water handling facilities for safety reasons or refuse to permit the restart of any facility after unplanned or planned outages. Agencies may also mandate enhanced monitoring, bonding or financial assurance, corrective action plans, and expanded reporting, which can increase operating costs and extend restart timelines. New or amended safety and regulatory requirements may give rise to additional operational and maintenance costs and capital expenditures. In addition, increased third-party challenges to permits, seismic-event investigations, and citizen suits can delay approvals, impose interim operating limits, or result in permit revocations or narrowed authorizations. Additionally, aging equipment or facilities may require increased capital expenditures to keep produced water infrastructure operating efficiently or in compliance with applicable laws and regulations. Such equipment is also likely to require periodic upgrading and improvement to maintain compliance. Supply-chain constraints, long-lead times for critical components (including pumps, automation, and electrical gear), and grid-power availability can further delay repairs, expansions or recommissioning and increase costs. Although the safety record of produced water handling generally has been very good, accidents and other unforeseen problems have occurred and may occur in the future. Spills, releases or pipeline failures could trigger remediation obligations, third-party claims, regulatory enforcement, and interruption of service, and available insurance may be subject to exclusions, sublimits, higher retentions, or limited availability in affected markets. The consequences of any major incident could be severe and may result in loss of life or property damage. Further, cybersecurity incidents or operational technology failures affecting our operating partners’ systems could disrupt produced-water gathering, treatment and disposal activities, delay billing and settlement processes, and increase compliance and remediation costs. Any of these developments, or sustained reductions in handled volumes due to recycling, beneficial reuse or regulatory constraints, could materially and adversely affect our results of operations, cash flows and financial position.

A series of risks arising out of the threat of climate change could result in increased operating costs for our customers, limit the areas in which oil, natural gas and NGLs production may occur, and reduce demand for traditional energy sources and the services related to the production and transport thereof, which could have a material adverse effect on their business, which in turn could have a material adverse effect on our business.

The operations of our customers and their service providers and end-line customers are subject to a series of regulatory, political, litigation and financial risks associated with the threat of climate change, including the production, processing, transportation, gathering and handling of traditional energy sources and the emission of greenhouse gases (“GHGs”). We do not operate our customers’ assets and have limited ability to influence their compliance or mitigation strategies.

At the federal level, no comprehensive climate change law or regulation has been implemented to date, though the Inflation Reduction Act of 2022 (“IRA 2022”) advances numerous climate related objectives, including funding and incentives for research and development of low-carbon energy production methods, carbon capture and other programs directed at addressing climate change. The IRA 2022 includes a methane emissions reduction program for petroleum and natural gas sources through a methane emissions fee. In November 2024, the EPA promulgated a rule implementing the methane emissions fee, although in February 2025, Congress voted to eliminate the rule under the Congressional Review Act. Additionally, in the OBBB Act, Congress delayed the implementation of the methane emission charge until 2034. We cannot predict if the Trump Administration and/or Congress may take further action to repeal or revise this requirement of the IRA 2022; 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 customers’ costs of development, which could be significant. Related legislative and agency actions are subject to change and legal challenge, creating planning uncertainty and potential delays for projects on or around our land.

In addition, the EPA has adopted new rules under the federal Clean Air Act (the “CAA”). In December 2023, the EPA issued a final rule that established Subpart OOOOb implementing more stringent rules for GHG (in the form of a limitation on emissions of methane) and volatile organic compound (“VOC”) emissions for new, modified and reconstructed facilities in the crude oil and natural gas source category and Subpart OOOOc as first-time existing source standards of performance for methane and VOC emissions for the oil and natural gas source category. However, in March 2025, the EPA announced plans to reconsider Subparts OOOOb and OOOOc, in line with the Trump Administration’s deregulatory agenda. In July 2025, the EPA extended the compliance deadlines for certain provisions provided in Subparts OOOOb and OOOOc. Litigation challenging EPA’s interim final rule extending such compliance deadlines for new and existing oil and gas sources remains pending. Even where certain deadlines have been extended, operators may still incur material monitoring, repair and equipment costs and face enforcement exposure.

Various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs and restriction of GHG emissions. Certain measures may also tighten air permitting or flaring limits, affecting completion timing and costs. Although it is not possible at this time to predict how new laws or regulations that may be adopted or issued to address GHG emissions would impact our business or our customers’ operations, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our or our customers’ equipment and operations could require us or our customers to incur costs to reduce emissions of GHGs associated with operations, as well as delay or restrict the ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect the demand for natural gas, oil and NGLs, which may also adversely affect our operations and financial results. Prolonged drought or flooding can

constrain water sourcing, damage roads and ROWs and delay surface-use activities that generate our fees and royalties.

Furthermore, we and our customers have been and could be impacted in the future by the effects of weather volatility. Climate variability predictions have forecasted increases in the frequency and duration of droughts, extreme temperature variability, decreases in water supply and changes in water usage patterns, increases in the frequency and severity of extreme weather events (including storms, wildfires and other natural disasters) and the costs to reduce risks associated therewith and changes in meteorological and hydrological patterns, all of which could adversely impact our and our customers operations and involve various risks of physical damage. For example, in the winter of 2022, many oil and gas operators were impacted by abnormal winter conditions that temporarily adversely affected production. In addition, weather-related forced stoppages at processing, storage and pipeline facilities operated by our customers or counterparties with which our customers contract for services may also adversely affect our operations and financial results.

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

Increased attention to climate change, conflicting societal expectations on companies to address climate change and other environmental and social impacts, investor and societal expectations regarding voluntary sustainability disclosures and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our and our customers’ products and services, reduced profits, increased investigations and litigation and negative impacts on our or our customers’ suppliers and customers, which may ultimately have adverse impacts on our or our customers’ business, such as our and our customers’ access to the capital markets as well as the value of our Class A shares. Increased attention to climate change and environmental conservation, for example, may result in demand shifts from oil and natural gas products and services to alternative forms of energy outside the scope of our customers’ businesses. 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 our and our customers’ causation of, or contribution to, the asserted damage, or to other mitigating factors.

Some organizations that provide information to investors on corporate governance and related matters have developed rating and proxy voting recommendation processes for evaluating companies on their approach to sustainability concerns. Such ratings and proxy advisory services are used by some investors to inform their investment and voting decisions. While such ratings do not impact all investors’ investment or voting decisions, unfavorable ratings and any activism directed at shifting funding away from companies with traditional energy-related assets could lead to increased negative investor sentiment toward us, our customers and our industry as a whole and to the diversion of investment to other industries, which could have a negative impact on our access to, and costs of, capital. Several states either proposed or passed new laws requiring additional disclosure from proxy advisory firms concerning factors influencing their proxy advisory services, especially when those factors extend beyond traditional financial or pecuniary analyses (such as sustainability matters). These new or proposed laws face legal challenges, including Texas SB 2337 providing public companies headquartered or domiciled (or considering redomiciling) in Texas with such additional protections, but enforcement of which by the Texas Attorney General has been enjoined by the U.S. District Court for the Western District of Texas pending trial. Further, institutional lenders may, of their own accord, decide not to provide funding for traditional energy companies based on climate change related concerns, which could affect our or our customers’ access to capital for operations. Additionally, insurers may decide to raise rates and/or cease insuring us or our customers based on climate change-related concerns.

Additionally, certain public statements with respect to sustainability matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities, as well as other parties, related to the risk of potential “greenwashing,” in other words, 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.

Certain employment practices and social initiatives are the subject of scrutiny by both those advocating for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business. More recent political developments could mean that we face increasing criticism or litigation risks from certain anti-sustainability parties, including various governmental agencies. Consideration of sustainability-related factors in our decision-making could be subject to increasing scrutiny and objection from such anti-sustainability parties. As a result, we may face increased litigation risk from private parties and governmental authorities related to our sustainability-related efforts.

The results of operations of our customers, as well as producers on or around our land, may be materially impacted by efforts to transition to a lower-carbon economy, which could have a material adverse effect on our business, results of operation, cash flows and financial position.

Concerns over the risk of climate change have increased the focus by global, regional, national, state and local regulators on GHG emissions, including carbon dioxide emissions, and on transitioning to a lower-carbon future. A number of countries and states have adopted, or are considering the adoption of, regulatory frameworks to reduce GHG emissions. These regulatory measures may include, among others, adoption of cap-and-trade regimes, carbon taxes, increased energy efficiency standards, prohibitions or reductions on the sales of new automobiles with internal combustion engines, and tax credits, incentives or mandates for battery-powered automobiles and/or wind, solar or other forms of alternative energy. These include laws such as the IRA, which appropriates significant federal funding for renewable energy initiatives and amends the federal CAA to impose a first-time fee on the emission of excess methane from sources required to report their GHG emissions to the EPA. In May 2024, the EPA issued a final rule to implement the IRA’s 2022 methane fee, however, on March 14, 2025, a joint Congressional resolution disapproved the EPA’s 2024 rule, and the rule is no longer in effect. While the future implementation or repeal of all or a portion of the IRA is uncertain at this time, it is possible that additional changes in the future could impact our results of operation and those of our customers. Compliance with changes in laws, regulations and obligations relating to climate change could result in increased costs of compliance for our customers on or around our land or costs of consuming oil and natural gas for such products, and thereby reduce demand for the use of our land and resources, which could reduce our profitability. Changes in laws and regulations may also result in delays or increased costs associated with obtaining permits needed for oil and natural gas operations. Additionally, our customers on or around our land could incur reputational risk tied to changing customer or community perceptions of our customers’ or their customers’ contribution to, or detraction from, the transition to a lower-carbon economy. These changing perceptions could lower demand for oil and natural gas products, resulting in lower prices and lower revenues as consumers avoid carbon-intensive industries, and could also pressure banks and investment managers to shift investments and reduce lending.

Separately, banks and other financial institutions, including investors, may decide to adopt policies that restrict or prohibit investment in, or otherwise funding, us or our customers on or around our land based on climate change-related concerns, which could affect our and our customers on or around our land’s access to and cost of capital for potential growth projects. This trend is, however,

generally declining. Additionally, insurers may decide to raise rates and/or cease insuring us or our customers on or around our land based on climate change-related concerns.

Approaches to climate change and transition to a lower-carbon economy, including government regulation, company policies and consumer behavior, are continuously evolving. For example, in October 2023, the State of California adopted several laws that require disclosure on various climate risks, targets, and metrics; however, both laws are currently subject to litigation. Any such disclosure or other climate-related requirements like these laws or similar that we may become subject to could require us or our customers to incur significant costs and additional attention from management, including for the establishment of additional controls, given the relatively novel nature of such reporting. At this time, we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on us or our customers’ financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and natural gas industry may affect our results of operations, cash flows and financial position.

Our business and financial results could be disrupted by natural or human causes beyond our control.

Our business and financial results could be disrupted by natural or human causes beyond our control. Our revenues depend on natural and environmental conditions affecting operations that result in royalties and utilize our water services, many of which occur on or around our acreage in the Permian Basin. As a result, our business is subject to disruption from natural or human causes beyond our control, including severe storms, flooding, tornadoes, drought and aquifer declines, wildfires, earthquakes (including induced seismicity), system failures and power outages, pipeline disruptions, environmental incidents such as oil and produced-water spills, accidents, terrorism or sabotage, civil unrest, political events, war and epidemics or pandemics. Any of these events could cause material adverse effects on oil and natural gas production and associated infrastructure on or adjacent to our land, which in turn could negatively impact our results of operations, cash flows and financial position. Our geographic concentration in the Permian Basin heightens exposure to regional weather, natural disaster and infrastructure constraints relative to diversified operators.

Physical and regulatory responses to induced seismicity in Texas and New Mexico can disrupt produced-water handling and curtail activity on or near our acreage, including through SRA measures such as suspensions, volumetric limits and rate restrictions for injection. In July 2024, the NMOCD administratively canceled 75 pending UIC Class II permit applications within the 10-mile County Line SRA due to seismicity concerns, and the TRRC has pursued initiatives since 2021 to reduce injection volumes and suspend certain deep injection within SRAs. Although our acreage is not currently within an SRA, there is no assurance this will remain the case, and similar or expanded actions could constrain injection alternatives near our land, increase competition for pore space, and shift volumes away from locations that generate royalties for us. In addition, our customers’ ability to conduct activity that generates our revenues depends on access to adequate water supply and pore space and on timely permits for water sourcing, produced-water handling, air emissions and surface-disturbing construction. Prolonged drought, overuse of aquifers, habitat protections and local water-district restrictions can limit availability or increase costs, and heightened regulatory scrutiny can delay, limit or revoke permits, all of which can disrupt operations and payments to us.

Broader operational, supply-chain and power-system disruptions affecting our customers and operating partners can reduce activity levels on or near our land and delay projects that generate surface-use fees, water sales and produced-water royalties. Our indirect exposure to construction, operational and environmental hazards, including fires, explosions, blowouts, seismic events, pipeline failures and spills or releases, as well as cybersecurity risks to energy infrastructure and third-party systems, can cause interruptions, remediation obligations, investigations, penalties, third-party claims

and increased insurance and compliance costs; insurance may have deductibles, exclusions and sublimits, may not cover all interruptions, and proceeds may be delayed or insufficient. Evolving climate-related physical risks, including increased frequency and severity of storms, droughts, wildfires, flooding and extreme temperature variability, and associated resilience costs may constrain water sourcing, damage infrastructure and increase downtime at midstream and power assets utilized by our customers, reducing the activity levels that drive our revenues.

Current and future restrictions on our customers’ operations intended to protect certain species of wildlife may adversely affect their ability to expand certain existing operations and/or limit their ability to use our land, including the limitation of drilling activities, development of infrastructure and disposal operations.

In the United States, the Endangered Species Act (the “ESA”) and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). These measures may include seasonal timing restrictions, buffer zones, survey and monitoring obligations, and participation in Habitat Conservation Plans or Candidate Conservation Agreements with Assurances. To the extent species that are listed or protected under the ESA or the MBTA, respectively, or similar state laws live in the areas where we own surface acreage and/or mineral and royalty interests and our customers operate, our customers’ abilities to conduct or expand operations could be limited, or our customers could be forced to incur material additional costs. Because we do not control our customers’ operations, our ability to influence their compliance approach or mitigation strategy is limited. For example, in May 2024, the U.S. Fish and Wildlife Service (“FWS”) issued a final rule listing the dunes sagebrush lizard as endangered under the ESA, although that listing decision has been challenged. In November 2022, the FWS formally listed two distinct population segments of the lesser prairie-chicken under the ESA, but in March 2025, the U.S. District Court for the Western District of Texas vacated the rule for the northern district population segment. In April 2024, the FWS and the National Marine Fisheries Service (“NMFS”) finalized three rules that revise regulations for classifying species and designating critical habitat, interagency cooperation and protecting endangered and threatened species. In April 2025, the FWS and the NMFS proposed a rule to rescind the regulatory definition of “harm” to species under the ESA, which includes habitat modification. In addition, in April 2025, the U.S. Department of the Interior reinstated a 2017 legal opinion that determined that the MBTA’s prohibitions on pursuing, hunting, taking, capturing and killing migratory birds do not apply to accidental or incidental taking or killing of migratory birds. Agency policies and judicial decisions in these areas have shifted over time, and certain states maintain their own incidental-take prohibitions, creating additional uncertainty and potential compliance obligations.

The identification or designation of previously unprotected species, or the redesignation of a species from threatened to endangered, in areas on or around our land and/or mineral and royalty interests could cause our customers’ operations to become subject to operating restrictions or bans, including restrictions of future development activities in the subject areas, or cause our customers to incur additional costs associated with their operations on our surface acreage or with respect to our mineral and royalty interests, which could have a material adverse effect on our results of operations, cash flows and financial position. Critical habitat designations and federal “consultation” requirements where a federal nexus exists can further delay permits and require compensatory mitigation (including conservation banking or off-site habitat projects), which may limit activity on or near our acreage.

Risks Related to Our Financial Condition

We may be unable to generate sufficient cash to service all of our indebtedness and financial commitments and any future indebtedness could adversely affect our financial condition.

As of December 31, 2025, on an actual basis, we had $265.6 million of total debt outstanding, exclusive of $35.1 million of unamortized debt premium (discount) and issuance costs, net, and on a pro forma, as adjusted basis, we had no debt outstanding and $1.8 million of unamortized debt issuance costs. Our ability to make scheduled payments on, or to refinance, our indebtedness and financial commitments depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions, including financial, business and other factors beyond our control, and may vary significantly from year to year. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods and we may be unable to generate sufficient cash flow to permit us to pay the principal, premium, if any, and interest on our indebtedness. Any insufficiency may impact our business.

If our cash flows and capital resources are insufficient to fund debt and other obligations, we may be forced to reduce or delay capital expenditures, sell assets, seek to raise additional capital or refinance or restructure our indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be on unfavorable terms, including at higher interest rates, and may require us to comply with more restrictive covenants. The terms of our existing or future debt instruments may restrict us from adopting some of these alternatives. We cannot assure you that any refinancing or restructuring would be possible, that any assets, including land, could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to us or that additional financing could be obtained on favorable terms, if at all. In addition, any failure to service our debt, including paying interest or principal on a timely basis, would likely result in a reduction of our credit rating, if any, which could harm our ability to incur additional indebtedness. In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt.

Our indebtedness could have important consequences for you and significant effects on our business, including:

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increasing our vulnerability to adverse changes in general economic, industry and competitive conditions and limiting our ability to address such changes;

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requiring us to dedicate a substantial portion of our cash flow from operations to make payments on our indebtedness, thereby reducing the availability of our cash flow to fund general company and other purposes, including capital expenditures and dividend payments;

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restricting us from exploiting business opportunities and making strategic land acquisitions;

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making it more difficult to satisfy our financial obligations, including payments on our indebtedness, and contractual and commercial commitments;

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disadvantaging us when compared to our competitors that have less debt;

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complying with covenants contained in the documents governing such indebtedness may require us to meet or maintain certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our industry, such as being able to take advantage of acquisition opportunities when they arise; and

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increasing our borrowing costs or otherwise limiting our ability to borrow additional funds for the execution of our business strategy.

Finally, the agreements governing our outstanding indebtedness limit our ability to incur additional debt, but such agreements do not prohibit us from doing so. As a result, we could incur more indebtedness in the future, which would exacerbate the foregoing risks.

We are subject to interest rate risk, which may cause our debt service obligations to increase significantly.

If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and we would be required to devote more of our cash flow to servicing our indebtedness.

In March 2022, the Federal Reserve began, and continued through 2023, to raise interest rates in an effort to curb inflation. Although the Federal Reserve reduced benchmark interest rates three times in 2025, to the extent such rates remain elevated, we may continue to experience further financing cost increases if interest rates on borrowings, credit facilities and debt offerings increase compared to previous levels. Changes in interest rates, either positive or negative, may also affect the yield requirements of investors who invest in our Class A shares, and the elevated interest rate environment could have an adverse impact on the price of our Class A shares or our ability to issue equity or incur debt for acquisitions or other purposes.

We anticipate entering into a new credit facility following this offering that we expect will be secured by substantially all of the assets of OpCo and its subsidiaries. If we fail to comply with the restrictions and covenants in such credit facility or our future debt agreements, there could be an event of default under the terms of such agreements, which could result in an acceleration of payment and the potential loss of those assets.

We anticipate that we will use a portion of the net proceeds from this offering to repay in full, and terminate, the Predecessor Credit Facility. Following the completion of this offering, we anticipate that OpCo and certain of our other subsidiaries will enter into a new senior secured revolving credit facility (the “Credit Facility”) providing up to $200.0 million in revolving credit commitments, which will be administered by JPMorgan Chase Bank, N.A. The obligations under the Credit Facility will be secured by a first-priority lien on substantially all of the assets of OpCo and the Guarantors (as defined therein), including equity interests in the subsidiaries of OpCo, subject to customary exceptions and exclusions, and will be guaranteed by all material existing and future direct and indirect wholly owned domestic subsidiaries of OpCo. As a result, substantially all of our acreage, which as of December 31, 2025 consisted of approximately 236,000 surface acres across Texas and New Mexico, and our other assets, including our interests in our water infrastructure and other property, will be encumbered by first-priority mortgages (deeds of trust) and related security interests to secure the Credit Facility.

The Credit Facility will contain certain customary affirmative and negative covenants, which, among other things, will restrict the ability of OpCo and its restricted subsidiaries, subject to certain exceptions, to incur debt, grant liens, make restricted payments and investments, issue equity, sell or lease assets, dissolve or merge with another entity, enter into transactions with affiliates or restrictive agreements, change their business, prepay debt and amend their organizational documents and material agreements. In addition, OpCo will be required to comply with certain financial maintenance covenants, including a maximum net total leverage ratio of no greater than 3.50x (with maximum cash netting of up to $25.0 million if any loans are outstanding; if no loans are outstanding, all unrestricted cash and cash equivalents on the balance sheet of OpCo and its restricted subsidiaries and with a step up to 4.00x for a certain period after a material permitted acquisition) and a minimum interest coverage ratio of at least 2.75x. The Credit Facility will also contain customary events of default, including the failure of OpCo and the other loan parties to comply with the various financial, negative and affirmative covenants under the Credit Facility, subject to the cure provisions set forth therein. It will also include a customary holding company covenant applicable to us.

A breach of compliance with any restriction or covenant in the Credit Facility or any of our future debt agreements could result in a default under the terms of the applicable agreement, and our ability to comply with such restrictions and covenants may be affected by events beyond our control, including prevailing economic and competitive conditions, changes in commodity prices, changes in law and regulation, and other factors affecting the energy sector. As a result, we cannot assure you that we will be able to comply with these restrictions and covenants. A default could result in acceleration of the indebtedness and a declaration of all amounts borrowed due and payable, which could have an adverse effect on us and negatively impact our ability to borrow. Because the Credit Facility will be secured by substantially all of the assets of OpCo and its subsidiaries, in the event of an event of default, the administrative agent may, with the consent of or at the direction of the required lenders, terminate the commitments and declare all outstanding loans and accrued interest and fees under the Credit Facility to be immediately due and payable. In addition, the administrative agent may enforce its security interests over OpCo and its subsidiaries assets that secure the obligations under the Credit Facility, take control of such assets and business, force us, OpCo and its subsidiaries to seek bankruptcy protection, or force us, OpCo or its restricted subsidiaries to curtail or abandon our or their current business plans. The loss of such assets, which constitute substantially all of our property, including the surface acreage and water infrastructure that generate our revenues, would have a material adverse effect on our business, results of operations, cash flows and financial position and could result in the loss of all, or a part of, your investment in our Class A shares.

If an acceleration occurs, OpCo may be unable to make all of the required payments and may be unable to find alternative financing. Even if alternative financing were available at that time, it may not be on terms that are favorable or acceptable to us, including as a result of higher interest rates or more restrictive covenants. Additionally, we may not be able to amend the Credit Facility or such future agreements governing our indebtedness or obtain necessary waivers on satisfactory terms. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time, and any refinancing of our indebtedness could be on unfavorable terms.

Our obligations under the Credit Facility will be secured by a first priority security interest in substantially all of the assets of OpCo and its restricted subsidiaries.

We expect that amounts borrowed pursuant to the terms of the Credit Facility will be secured by substantially all of OpCo’s and its restricted subsidiaries’ present and after-acquired assets. Additionally, we expect that the obligations under the Credit Facility will be jointly and severally guaranteed by OpCo and its material subsidiaries.

As a result of the above, in the event of the occurrence of a default under the Credit Facility, the administrative agent may enforce its security interests (for the ratable benefit of the lenders under the Credit Facility and the other secured parties) over OpCo’s and/or its restricted subsidiaries’ assets that secure the obligations under the Credit Facility, take control of such assets and business, force us, OpCo or its restricted subsidiaries to seek bankruptcy protection, or force us to curtail or abandon our current business plans. If that were to happen, you may lose all, or a part of, your investment in our Class A shares.

Changes to applicable tax laws and regulations, exposure to additional income tax liabilities, changes in our effective tax rates or an assessment of taxes resulting from an examination of our income or other tax returns could adversely affect our results of operations, cash flows and financial position, including our ability to repay our debt.

We are subject to various complex and evolving U.S. federal, state and local taxes. U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect, and may have an adverse effect on our results of operations, cash flows and financial position, including our

ability to repay our debt. The passage of tax legislation or other similar changes in U.S. federal income tax laws could adversely affect our results of operations, cash flows and financial position.

Changes in our effective tax rates or tax liabilities could also adversely affect our results of operations, cash flows and financial position. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

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

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

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expansion into future activities in new jurisdictions;

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

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tax effects of share-based compensation.

In addition, an adverse outcome arising from an examination of our income or other tax returns could result in higher tax exposure, penalties, interest or other liabilities that could have an adverse effect on our results of operations, cash flows and financial position.

We are subject to counterparty credit risk. Nonpayment or nonperformance by our customers could have an adverse effect on our results of operations, cash flows and financial position.

We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers of their respective obligations. Although we maintain policies and procedures to limit such risks, our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them of their respective obligations and our inability to collect on outstanding receivables or find substitute customers could have an adverse effect on our results of operations, cash flows and financial position. A decline in oil and natural gas prices could negatively impact the financial condition of our customers and sustained lower prices could impact their ability to meet their obligations to us. Further, our contract counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent one or more of our contract counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the Bankruptcy Code. Any material nonpayment or nonperformance by our contract counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could adversely affect our results of operations, cash flows and financial position.

We have a history of, and plan for, significant financing transactions; our capital structure includes significant indebtedness the terms of which may constrain us, and we intend to use offering proceeds to repay indebtedness.

We have incurred and amended material debt facilities to fund acquisitions and operations, including a $72.0 million term loan and a revolving credit facility and a subsequent $204.0 million term financing tied to the Accelerated Acquisition; indebtedness and related covenants may limit flexibility and increase refinancing risk. The incurrence of additional indebtedness would result in increased fixed payment obligations and could also result in certain restrictive covenants, such as limitations on our ability to incur additional debt, limitations on our ability to acquire additional acreage and other operating restrictions that could adversely impact our ability to conduct our business and may result in liens being placed on our assets. If we were to default on such indebtedness, we could lose such assets. The use of initial public offering proceeds to repay the Predecessor Credit Facility reduces cash available for operations and growth and increases our exposure to market conditions at pricing.

Risks Related to this Offering, Our Corporate Structure and Our Class A Shares

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act, and the requirements of the Sarbanes-Oxley Act, may increase our costs and divert management’s attention from other business concerns, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the NYSE and NYSE Texas rules, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

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institute a more comprehensive compliance function;

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comply with rules promulgated by the NYSE and NYSE Texas;

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prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

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accurately implement and interpret GAAP;

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institute and enforce new internal policies, such as those relating to insider trading; and

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involve and retain to a greater degree outside counsel and accountants in the above activities.

Upon becoming a reporting issuer, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act, which will require management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of internal controls over financial reporting. Although we will be required to disclose changes made in our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal controls over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. Additionally, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” or a “smaller reporting company” under the applicable federal securities laws. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2031, if we are no longer a “smaller reporting company.” Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements will strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

Investors in this offering will experience immediate and substantial dilution of $15.50 per Class A share.

The initial public offering price of $18.50 per Class A share (the mid-point of the price range set forth on the cover page of this prospectus) exceeds our pro forma, as adjusted net tangible book value of $3.00 per Class A share. Based on the assumed initial public offering price of $18.50 per Class A share, shareholders will incur an immediate and substantial dilution of $15.50 per Class A share in the as adjusted net tangible book value per share. This dilution results primarily because our assets are recorded at their historical cost in accordance with GAAP, and not their fair value. Please see “Dilution.”

Future sales of Class A shares, or the perception that such sales may occur, may depress our share price, and any additional capital raised through the sale of equity or convertible securities may dilute your ownership in us.

We may in the future issue additional securities. The potential issuance of such additional shares may result in the dilution of the ownership interests of the holders of our Class A shares and may create downward pressure on the trading price of our Class A shares.

In addition, we have granted registration rights to all of our Existing Owners and the TCW Entities which cover (i) all of the 105,164,580 Class B shares, and an equal number of OpCo Units, and (ii) all of the 4,560,785 Class A shares that they will own following this offering. Such Existing Owners and TCW Entities may exercise their rights under the registration rights agreement in their sole discretion, subject to certain restrictions, and sales pursuant to such rights may be material in amount and occur at any time. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.” The sales of substantial amounts of our Class A shares (including Class A shares underlying Class B shares held by the Existing Owners or the TCW Entities) or the perception that these sales may occur could cause the market price of our Class A shares to decline and impair our ability to raise capital. We also may grant additional registration rights in connection with any future issuance of our capital stock.

We cannot predict the size of future issuances of our Class A shares or securities convertible into or redeemable, exercisable or exchangeable for Class A shares or the effect, if any, that future issuances and sales of shares of our Class A shares will have on the market price of our Class A shares.

Our ability to pay dividends to our shareholders may be limited by our holding company structure, contractual restrictions and regulatory requirements.

After this offering, we will be a holding company and will have no material assets other than our equity interest in OpCo, and we will not have any independent means of generating revenue. To the extent OpCo has available cash we intend to cause OpCo to make (i) generally pro rata distributions to all OpCo Unitholders, including us, in an amount at least sufficient to allow us to pay taxes, (ii) at the election of certain OpCo Unitholders, additional distributions in an amount generally intended to allow such OpCo Unitholders to satisfy their respective income tax liabilities with respect to their allocable share of the income of OpCo (based on certain assumptions and conventions), which additional distributions may be made on a pro rata basis to all OpCo Unitholders (including us) or a non-pro rata basis to OpCo Unitholders (other than us) in redemption of OpCo Units from such holders and (iii) non-pro rata distributions to us in an amount sufficient to cover our public company and other overhead expenses. In addition, as the sole managing member of OpCo, we would expect to cause OpCo to make pro rata distributions to all of its unitholders, including to us, in an amount sufficient to allow us to fund dividends to our shareholders in accordance with our dividend policy, to the extent our board of directors declares any such dividend. OpCo, however, is a distinct legal entity and may be

subject to legal or contractual restrictions that, under certain circumstances, may limit our ability to obtain cash from it. If OpCo is unable to make distributions, we may not receive adequate distributions, which could materially and adversely affect our results of operations, cash flows, financial position and ability to fund any dividends.

Although we expect to seek to pay dividends on our Class A shares, we are not obligated to do so. We have not adopted a formal written dividend policy nor have we adopted a dividend policy to pay a fixed amount of cash each quarter in respect of each Class A share or to pay an amount based on the achievement of, or amount derivable based on, any specific financial metrics. Any future dividends are within the absolute discretion of our board of directors. Our board of directors has not declared any dividends and may determine not to declare any dividends in the future. Our board of directors will take into account general economic and business conditions, our financial condition and results of operations, our cash flows from operations and current and anticipated cash needs, our capital requirements, legal, tax, regulatory and contractual restrictions, and implications of such other factors as our board of directors may deem relevant in determining whether, and in what amounts, to pay such dividends. In addition, our debt agreements may limit the amount of distributions that OpCo’s subsidiaries can make to OpCo and OpCo can make to us and the purposes for which distributions could be made. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Pro Forma Liquidity and Capital Resources—Pro Forma Debt Instruments” for further discussion of our debt agreements. Accordingly, we may not be able to pay dividends even if our board of directors would otherwise deem it appropriate. Please see “Dividend Policy,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Pro Forma Liquidity and Capital Resources” and “Description of Shares.”

Any decision to declare and pay cash dividends in the future will be made in the sole discretion of our board of directors. We have not adopted a formal written dividend policy. In addition, our ability to pay cash dividends is, and may be, limited by covenants of any current or future outstanding indebtedness we or our subsidiaries incur. Any return on investment in our Class A shares may be solely dependent upon the appreciation of the price of our Class A shares on the open market, which may not occur.

For more information about these restrictions, see “Dividend Policy.” There can be no assurance that we will pay dividends in the future or continue to pay any dividends if we do commence paying dividends. Any decision to pay dividends will depend on many factors, including but not limited to our financial condition, earnings, capital requirements, contractual covenants, legal requirements, regulatory constraints, industry practice, ability to access capital markets and other factors deemed relevant by our board of directors. Investors in this offering should make any investment in our Class A shares without reliance on payment of any future dividend.

Upon completion of this offering, the Existing Owners will initially own an aggregate of 94,785,096 Class B shares representing 72.8% of our voting power (or 71.4% of our voting power if the underwriters’ option to purchase additional Class A shares is exercised in full). The Existing Owners may also purchase Class A shares through the directed share program, which would increase their voting power.

The Existing Owners, by virtue of their director designation rights under the Shareholder’s Agreements and voting power under the Voting Agreements, each as described below, will be able to control matters requiring shareholder approval, including the election of directors, changes to our organizational documents, approval of acquisition offers and other significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A shares will be able to affect the way we are managed or the direction of our business. The interests of the Existing Owners with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other shareholders.

Furthermore, prior to the completion of this offering, we expect to enter into Shareholder’s Agreements with each of our Existing Owners, providing that our Existing Owners will have the right to designate members of our board of directors. Although none of our Existing Owners will be permitted to individually designate a majority of our board of directors, the terms of the Shareholder’s Agreements will result in the Existing Owners being able to collectively designate a majority of our board of directors for a potentially extended period of time following the completion of this offering. The Shareholder’s Agreements will provide, subject to compliance with applicable law and NYSE and NYSE Texas rules, for so long as any Existing Owner, and its affiliates and certain transferees, beneficially owns at least 30%, 20% and 10% of our outstanding common shares, such Existing Owner shall be entitled to designate three directors, two directors and one director, respectively, for nomination to our board of directors. If the size of the board of directors is increased or decreased from seven directors, each Existing Owner’s nomination rights will be proportionately adjusted. Of the directors designated by each of L&E and Double Eagle, at least two of each such Existing Owner’s designees (or if such Existing Owner is designating only one director, such designee) must qualify as “independent” for purposes of serving on the Audit Committee. So long as an Existing Owner is entitled to designate one or more directors and notifies the board of directors of its desire to remove, with or without cause, any director previously designated by it to the board, we are required to take all necessary action to cause such removal.

See “Certain Relationships and Related Transactions—Shareholder’s Agreements.”

Pursuant to separate Voting Agreements, each Existing Owner will agree with us that it and certain of its transferees will vote all of the common shares that it owns in favor of all director nominees recommended for election by our board of directors. As a result, investors in this offering have a limited ability to influence the direction of our business. See “Certain Relationships and Related Party Transactions—Voting Agreements.”

The Existing Owners’ substantial ownership of our common shares may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other shareholders to approve transactions that they may deem to be in the best interests of our company. Moreover, the Existing Owners’ concentration of share ownership may adversely affect the trading price of our Class A shares to the extent investors perceive a disadvantage in owning shares of a company with a significant shareholder.

In addition, the Existing Owners may have different tax positions from us that could influence their decisions regarding whether and when to support the disposition of assets and the incurrence or refinancing of new or existing indebtedness. In addition, the determination of future tax reporting positions, the structuring of future transactions and the handling of any challenge by any taxing authority to our tax reporting positions may take into consideration the Existing Owners’ tax or other considerations, which may differ from the considerations of our other shareholders.

We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us.

We have historically entered into transactions with our operating partners, each of which will be an affiliate of ours following the completion of this offering. Related party transactions create the possibility of conflicts of interest. Although we have established certain policies and procedures designed to mitigate and resolve conflicts of interest, there can be no assurance that these policies and procedures will be effective in doing so. It is possible that a conflict of interest could have a material adverse effect on our liquidity, results of operations and financial condition.

Our Existing Owners and their respective affiliates are not limited in their ability to compete with us, and may benefit from opportunities that might otherwise be available to us.

Our LLC Agreement will provide that our officers and directors and their respective affiliates and our Existing Owners and their respective affiliates (each an “Unrestricted Party”), are not restricted from owning assets or prohibited from engaging in other businesses or activities, including those that might be in direct competition with us, and that we renounce any interest or expectancy in any business opportunity that may from time to time be presented to them that would otherwise be subject to a corporate opportunity or other analogous doctrine under the TBOC. In addition, the Unrestricted Parties may compete with us for investment opportunities and may own an interest in entities that compete with us. In particular, our LLC Agreement, subject to the limitations of applicable law, will provide, among other things, that (i) the Unrestricted Parties may conduct business that competes with us and may make investments in any kind of property in which we may make investments, and (ii) if any of the Unrestricted Parties acquire knowledge of a potential business opportunity, transaction or other matter, they have no duty, to the fullest extent permitted by law, to communicate such offer to us, our shareholders or our affiliates.

We may refer any conflicts of interest or potential conflicts of interest involving any of the Unrestricted Parties to a conflicts committee, which must consist entirely of one or more independent directors, for resolution. Additionally, we anticipate that our board of directors will adopt a written related party transactions policy relating to the approval of related party transactions, pursuant to which any such transactions, including transactions with the Unrestricted Parties, will be reviewed and approved or ratified by our Audit Committee or such conflicts committee or pursuant to the procedures outlined in any such policy.

Our Existing Owners may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunities. Furthermore, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. Furthermore, our Existing Owners are not required to utilize facilities located on our land in connection with any business opportunities, whether currently existing or arising in the future, and may pursue development opportunities with competing landowners or pursue an alternative land position without informing us of such opportunity or offering such opportunity to us. This renouncing of our interest and expectancy in any business opportunity may create actual and potential conflicts of interest between us and our Existing Owners, and result in less than favorable treatment of us and our shareholders if attractive business opportunities are pursued by our Existing Owners, for their own benefit rather than for ours.

Additionally, our operating partners, which are affiliated with certain of the Existing Owners, may have interests that deviate from ours in the day-to-day operation of their respective businesses. For example, Double Eagle may sell the upstream assets that underlie the DE Acreage Dedication in the

future in its discretion. If such a sale were to occur, pursuant to the terms of a put option agreement between Double Eagle and Hydrosource, Double Eagle has the right to sell, and Hydrosource has the obligation to purchase, DEF Operating. If Double Eagle exercises such put right, it would cease to be one of our operating partners and we would lose the benefits of that relationship. In addition, our other operating partner, Hydrosource, would become the owner of DEF Operating, which is the party to the DE Flow WSMA and the minimum royalty obligation thereunder. In addition, Double Eagle may exercise the put option at any time following five years from the date of this offering.

Certain provisions of the TBOC and our LLC Agreement provide additional protections for our officers, directors and affiliates and limit the ability of shareholders to bring derivative claims or submit proposals at our annual meeting. As a result, our shareholders may be disadvantaged as compared to shareholders of Delaware corporations.

Certain provisions of the TBOC and our LLC Agreement may make it more difficult for our shareholders to bring claims against us, our directors and officers, or to submit proposals for consideration at meetings of our shareholders, as compared to the rights typically available to shareholders of a Delaware corporation. For example, pursuant to our LLC Agreement, each shareholder has waived any right to trial by jury in any action, proceeding or counterclaim concerning claims, including derivative claims, that are based on, arise from, or are related to our internal affairs, including fiduciary duty breaches. In addition, our LLC Agreement provides that, in order to institute a derivative proceeding, a shareholder must beneficially own a number of shares equaling greater than 2.5% of our outstanding shares, which is in addition to the other requirements for derivative proceedings set forth in the TBOC. This ownership threshold is more restrictive than what is generally required under Delaware law to bring a derivative action. The aforementioned waiver of jury trial and derivative proceeding provisions would not apply to claims brought to enforce a duty or liability created by the Exchange Act or the Securities Act. Furthermore, the TBOC provides a presumption that a manager of a limited liability company acted on an informed basis, in good faith and with the honest belief that the action taken was in the best interests of the company, which may make it more difficult for shareholders to successfully challenge actions taken by our board of directors.

Additionally, pursuant to our LLC Agreement, no shareholder or beneficial owner of shares, or group of shareholders or beneficial owners of shares, may submit a matter for consideration at an annual or special meeting of our shareholders, other than director nominations and procedural resolutions that are ancillary to the conduct of the meeting, unless such shareholder, beneficial owner or group holds a number of common shares, determined as of the date of submission of the proposal, equal to at least (i) $1 million in market value or (ii) 3% of our outstanding common shares. Such shareholder, beneficial owner or group must also have held such number of common shares for a continuous period of at least six months before the date of the meeting, hold such common shares throughout the entire duration of the meeting and solicit the beneficial owners of Class A shares representing at least 67% of Class A shares entitled to vote on the proposal. These requirements are significantly more burdensome than the ownership thresholds applicable to shareholder proposals of Delaware corporations under SEC Rule 14a-8 and may effectively prevent many of our shareholders from submitting proposals for our annual meetings. These provisions of the TBOC and our LLC Agreement may discourage or make it more difficult for our shareholders to pursue legal claims or present proposals for shareholder action, which, taken together, could limit the ability of shareholders to influence our governance.

Certain of our directors and officers, who are responsible for managing our business, may hold positions of responsibility with other entities, including those that are in the energy industry. The existing and potential positions held by these directors and officers may give rise to fiduciary or other duties that are in conflict with the duties they owe to us and may also otherwise require attention and time that could otherwise be devoted to our business. Although we expect that our directors and officers will initially spend a significant amount of their time on matters involving our business, we expect that they will also spend time on matters relating to other entities in which they are involved, including the Existing Owners. The ultimate allocation of our directors’ and officers’ time among us and such other entities will be subject to a variety of factors, including operational and business considerations. These directors and officers may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, such directors and officers may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and, as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our or your best interests.

A significant reduction by the Existing Owners of their ownership interests in us could adversely affect us.

We believe that the Existing Owners’ ownership interest in us provides them with an economic incentive to assist us in being successful. Upon the expiration of the lock-up restrictions on transfers or sales of our securities following the completion of this offering, the Existing Owners will not be subject to any obligation to maintain their ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce their ownership interest in us. If the Existing Owners sell all or a substantial portion of their ownership interests in us, they may have less incentive to assist in our success and its affiliate(s) that are expected to serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our results of operations, cash flows and financial position.

The U.S. federal income tax treatment of dividends on our Class A shares to a holder will depend upon our tax attributes and the holder’s tax basis in our Class A shares, which are not necessarily predictable and can change over time, and could cause taxable gain or loss on the sale of our Class A shares to be more or less than expected.

We have not adopted a formal written dividend policy. Dividend payments of cash or property to holders of our Class A shares, if any, will constitute “dividends” for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent such distribution amounts exceed our current and accumulated earnings and profits, such distributed amount will be treated as a non-taxable return of capital to the extent of a holder’s tax basis in our Class A shares and thereafter as capital gain from the sale or exchange of such shares.

If a holder sells its Class A shares, the holder will recognize a gain or loss equal to the difference between the amount realized and the holder’s tax basis in such Class A shares. To the extent that the amount of our dividends is treated as a non-taxable return of capital as described above, such dividends will reduce a holder’s tax basis in the Class A shares. Consequently, such excess dividends

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will result in a corresponding increase in the amount of gain, or a corresponding decrease in the amount of loss, recognized by the holder upon the sale of the Class A shares or subsequent dividends with respect to such shares. Please read “Material U.S. Federal Income Tax Considerations for Non-U.S. Holders—Gain on Sale or Other Taxable Disposition of Class A Shares” for a further discussion of the foregoing. Additionally, with regard to U.S. corporate holders of our Class A shares, to the extent that a dividend on our Class A shares exceeds both our current and accumulated earnings and profits and such holder’s tax basis in such shares, such holders would be unable to utilize the corporate dividends-received deduction (to the extent it would otherwise be applicable to such holder) with respect to the gain resulting from such excess dividend.

Prospective investors in our Class A shares are encouraged to consult their tax advisors regarding the tax consequences of receiving dividends on our Class A shares that are not treated as dividends for U.S. federal income tax purposes.

The Internal Revenue Service (“IRS”) Forms 1099-DIV that our shareholders receive from their brokers may over-report dividend income with respect to our Class A shares for U.S. federal income tax purposes, and failure to report dividend income in a manner consistent with the IRS Forms 1099-DIV may cause the IRS to assert audit adjustments to a shareholder’s U.S. federal income tax return. For non-U.S. holders of our Class A shares, brokers or other withholding agents may overwithhold taxes from dividends paid, in which case a shareholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to claim a refund of the overwithheld taxes.

To the extent we make any payments of cash or property to holders of our Class A shares, such payments with respect to our Class A shares will constitute “dividends” for U.S. federal income tax purposes only to the extent of our current and accumulated earnings and profits. Dividends we pay in excess of our earnings and profits will not be treated as “dividends” for U.S. federal income tax purposes; instead, they will be treated first as a tax-free return of capital to the extent of a shareholder’s tax basis in their Class A shares and then as capital gain realized on the sale or exchange of such shares. We may be unable to timely determine the portion of our dividends that is a “dividend” for U.S. federal income tax purposes.

For a U.S. holder of our Class A shares, the IRS Forms 1099-DIV may not be consistent with our determination of the amount that constitutes a “dividend” for U.S. federal income tax purposes or a shareholder may receive a corrected IRS Form 1099-DIV (and may therefore need to file an amended federal, state or local income tax return). We will attempt to timely notify our shareholders of available information to assist with income tax reporting (such as posting the correct information on our website). However, the information that we provide to our shareholders may be inconsistent with the amounts reported by a broker on IRS Form 1099-DIV, and the IRS may disagree with any such information and may make audit adjustments to a shareholder’s tax return.

For a non-U.S. holder of our Class A shares, “dividends” for U.S. federal income tax purposes will be subject to withholding of U.S. federal income tax at a 30% rate unless an applicable income tax treaty provides for a lower rate or the dividends are effectively connected with conduct of a U.S. trade or business. Please read “Material U.S. Federal Income Tax Considerations for Non-U.S. Holders—Dividends and Other Distributions.” In the event that we are unable to timely determine the portion of our dividends that is a “dividend” for U.S. federal income tax purposes, or a shareholder’s broker or withholding agent chooses to withhold taxes from dividends in a manner inconsistent with our determination of the amount that constitutes a “dividend” for such purposes, a shareholder’s broker or other withholding agent may overwithhold taxes from dividends paid. In such a case, a shareholder generally would have to timely file a U.S. tax return or an appropriate claim for refund in order to obtain a refund of the overwithheld tax.

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

We, all of our directors, all of our executive officers, the Existing Owners and the TCW Entities, and certain of their respective affiliates, will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our Class A shares or securities convertible into or redeemable, exercisable or exchangeable for Class A shares, including OpCo Units and Class B shares, for a period of 180 days following the date of this prospectus. Please see “Underwriting” for more information on these agreements. If the restrictions under the lock-up agreements are waived, then the Class A shares, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our Class A shares to decline and impair our ability to raise capital.

For as long as we are an emerging growth company and/or a smaller reporting company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and executive compensation disclosure. We are classified as an “emerging growth company” under the JOBS Act, and currently intend to take advantage of the following exemptions. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We currently intend to take advantage of the exemptions described above. We have also elected to use the extended transition period for complying with new or revised accounting standards under Section 102(b)(2) of the JOBS Act. This election allows us to delay the adoption of new or revised accounting standards that have different effective dates for public and private companies until those standards apply to private companies. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.235 billion of revenues in a fiscal year, have more than $700.0 million in market value of our Class A shares held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

Additionally, we qualify as a “smaller reporting company” as defined in Item 10(f)(1) of Regulation S-K under the Securities Act. Smaller reporting companies may take advantage of certain reduced disclosure obligations, including, among other things, omitting certain executive compensation disclosure and providing only two years of audited financial statements in their periodic reports and registration statements. We will remain a smaller reporting company until the last day of the fiscal year in which: (i) the market value of our common shares held by non-affiliates is $250 million or more as of the end of that fiscal year’s second fiscal quarter; or (ii) our annual revenues are $100 million or more during such completed fiscal year and the market value of our common shares held by non-affiliates is $700 million or more as of the end of that fiscal year’s second fiscal quarter. To the extent we elect to take advantage of such reduced disclosure obligations, it may also make comparison of our financial statements with other public companies difficult or impossible.

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To the extent that we rely on any of the exemptions available to emerging growth companies and/or smaller reporting companies, you will receive less information about our financial position, executive compensation and internal control over financial reporting than issuers that are not emerging growth companies or smaller reporting companies. Our election to rely on these exemptions may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of such exemptions. If some investors find our Class A shares to be less attractive as a result, there may be a less active trading market for our Class A shares and our Class A share price may be more volatile.

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

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

The market price of our Class A shares may be volatile or may decline regardless of our operating performance, which could cause the value of your investment to decline.

Even if a trading market develops, the market price of our Class A shares may be highly volatile and could be subject to wide fluctuations. Securities markets in general experience significant price and volume fluctuations that have often been unrelated to the operating performance of particular companies. As such, this market volatility, as well as general economic, market or political conditions, could reduce the value of our Class A shares regardless of our results of operations. In the past, following periods of volatility in the overall market and/or in the value of a company’s securities, securities class action litigation has often been instituted against these companies. Such litigation, if instituted against us, could result in substantial costs and a diversion of our management’s attention and resources.

The trading market for our Class A shares will also depend in part on the research and reports that securities or industry 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 shares and other securities would be negatively affected. If such analysts do cover us, they may downgrade our Class A shares due to our operating results being below the expectations of such analysts and investors as a result of a number of potential factors, including variations in our quarterly operating results or dividends, if any, to holders of our Class A shares, additions or departures of key management personnel, failure to meet analysts’ earnings estimates, publication of research reports about our industry, litigation and government investigations, changes or proposed changes in laws or regulations or differing interpretations or enforcement thereof affecting our business, adverse market reaction to any indebtedness we may incur or securities we may issue in the future, changes in market valuations of similar companies or speculation in the press or investment community, announcements by our competitors of significant contracts, acquisitions, dispositions, strategic partnerships, joint ventures or capital commitments, adverse publicity about the industries in which we participate or individual scandals, and in response the market price of our Class A shares could decrease significantly. The trading volume of our Class A shares may decline, and you may be unable to resell your shares of Class A shares at or above the initial public offering price.

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The initial public offering price of our Class A shares may not be indicative of the market price of our Class A shares after this offering. In addition, an active, liquid and orderly trading market for our Class A shares may not develop or be maintained, and our Class A share price may be volatile.

Prior to this offering, our Class A shares were not traded on any market. After this offering, there will be only 17,300,000 publicly traded Class A shares. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Our trading liquidity may also be adversely affected by our structure as a limited liability company, which generally would prevent us from being directly included in certain major stock market indices. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A shares could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A shares, you could lose a substantial part or all of your investment in our Class A shares. The initial public offering price for our Class A shares will be negotiated between us and the representatives of the underwriters, based on numerous factors which we discuss in “Underwriting,” and may not be indicative of the market price of our Class A shares after this offering. The market price of our Class A shares may decline below the initial public offering price. Consequently, you may not be able to sell our Class A shares at prices equal to or greater than the price paid by you in this offering.

The following factors could affect our Class A share price:

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quarterly or annual variations in our financial and operating results, or those of other companies in our industry;

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the public reaction to our press releases, our other public announcements and our filings with the SEC;

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strategic actions by us or our competitors, including announcements of significant contracts or acquisitions;

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changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

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speculation in the press or investment community;

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the failure of research analysts to cover our Class A shares;

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sales of our Class A shares by us or other shareholders, or the perception that such sales may occur;

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changes in accounting principles, policies, guidance, interpretations or standards;

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additions or departures of key management personnel;

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actions by our shareholders;

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general market conditions, including fluctuations in oil and natural gas prices;

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domestic and international economic, legal and regulatory factors unrelated to our performance; and

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the realization of any risks described under this “Risk Factors” section.

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

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The market price of our Class A shares could be adversely affected by sales of substantial amounts of our Class A shares in the public or private markets or the perception in the public markets that these sales may occur, including sales by the Existing Owners after the exercise of the Redemption Right.

After this offering, we will have 24,960,419 Class A shares and 105,164,580 Class B shares outstanding, assuming no exercise of the underwriters’ option to purchase additional Class A shares. The Class A shares sold in this offering will be freely tradable without restriction under the Securities Act, except for any Class A shares that may be held or acquired by our directors, officers or affiliates, which constitute “control securities” under the Securities Act. Any Class A shares purchased by the Existing Owners in this offering pursuant to the directed share program or received by the Existing Owners or the TCW Entities upon their exercise of the Redemption Right will be subject to resale restrictions under a 180 day lock-up agreement with the underwriters and certain additional lock-up restrictions pursuant to the Registration Rights Agreement. Each of the lock-up agreements with the underwriters may be waived in the discretion of certain of the underwriters. Sales by the Existing Owners or the TCW Entities after the exercise of the Redemption Right or sales by other large holders of our Class A shares in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our Class A shares or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to the Existing Owners and the TCW Entities. Alternatively, we may be required to undertake a future public or private offering of Class A shares and use the net proceeds from such offering to purchase an equal number of OpCo Units, with the cancellation of a corresponding number of Class B shares, from the Existing Owners. Please read “Shares Eligible for Future Sale.”

We may sell additional Class A shares in subsequent offerings. Sales of substantial amounts of our Class A shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A shares.

We cannot predict the size of future issuances of our Class A shares or securities convertible into Class A shares or the effect, if any, that future issuances and sales of our Class A shares will have on the market price of our Class A shares.

We expect to be a “controlled company” within the meaning of the NYSE and NYSE Texas rules and, as a result, will qualify for and intend to rely on exemptions from certain corporate governance requirements.

Because our Existing Owners will initially own 94,785,096 OpCo Units and Class B shares, representing approximately 72.8% of our combined voting power following the completion of this offering, and will agree with us, pursuant to the terms of the Voting Agreements, to vote in favor of all director nominees recommended for election by our board of directors, we expect to be a controlled company as of the completion of this offering under the Sarbanes-Oxley Act and the NYSE and NYSE Texas rules. A controlled company is not required to have a majority of independent directors on its board of directors or to form an independent compensation or nominating and corporate governance committee. As a controlled company, we will remain subject to the Sarbanes-Oxley Act and the rules of the NYSE and NYSE Texas that require us, subject to certain phase-in periods, to have an audit committee composed entirely of independent directors. Under these rules, we must have an audit committee that has one member who is independent by the listing date, a majority of members that are independent within 90 days of the effective date and all members that are independent within one year of the effective date. We expect to have five independent directors upon the closing of this offering. Further, under these rules, a controlled company may elect not to comply with certain NYSE and NYSE Texas corporate governance requirements, including the requirements that:

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a majority of the board of directors consists of independent directors as defined under the rules of the NYSE and NYSE Texas;

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the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

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the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

These requirements will not apply to us as long as we remain a controlled company. A controlled company does not need its board of directors to have a majority of independent directors or to form independent compensation and nominating and governance committees. Following this offering, we intend to utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to shareholders of companies that are subject to all of the rules of the NYSE and NYSE Texas. Please see “Management” for additional information. If at any time we cease to be a controlled company, we intend to take all action necessary to comply with the Sarbanes-Oxley Act and the NYSE and NYSE Texas rules, including by appointing a majority of independent directors to our board of directors and establishing a compensation committee and a nominating and corporate governance committee, each composed entirely of independent directors, subject to a permitted “phase-in” period.

Our LLC Agreement, as well as Texas law, will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A shares and could deprive our investors of the opportunity to receive a premium for their shares.

Our LLC Agreement will authorize our board of directors to issue preferred shares without shareholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption prices and liquidation preferences of such series. If our board of directors elects to issue preferred shares, it could be more difficult for a third party to acquire us.

In addition, certain provisions of our LLC Agreement could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our shareholders. Among other things, upon completion of this offering, such provisions of our LLC Agreement include:

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providing that after the Existing Owners no longer have the right, pursuant to the Shareholder’s Agreements, to appoint a majority of our board of directors (the “Trigger Event”), our board of directors will be divided into three classes that are as nearly equal in number as is reasonably possible and each director will be assigned to one of three classes, with each class of directors elected for a three-year term to succeed the directors of the same class whose terms are then expiring. If at the time of the Trigger Event, any of the directors are designees of Double Eagle, such designees shall, at Double Eagle’s election, be classified as members of the third class of directors;

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prohibiting cumulative voting in the election of directors;

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providing that after the Trigger Event, the affirmative vote of the holders of not less than 66 2/3% in voting power of all then-outstanding common shares entitled to vote generally in the election of our board of directors, voting together as a single class, will be required to remove any director from office, and such removal may only be for “cause”;

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providing that after the Trigger Event, all vacancies, including newly created directorships, may, except as otherwise required by the terms of the Shareholder’s Agreements or, if applicable, the rights of holders of a series of preferred shares, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum, or by a sole remaining director;

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providing that after the Trigger Event, shareholders will not be permitted to call special meetings of shareholders;

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providing that after the Trigger Event, our shareholders may not act by written consent and may only act at a duly called annual or special meeting;

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establish advance notice procedures with respect to shareholder proposals and nominations of persons for election to our board of directors, other than nominations made by or at the direction of our board of directors or any committee thereof; and

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providing that a majority of our board of directors is expressly authorized to adopt, or to alter or repeal our LLC Agreement.

Further, as a Texas limited liability company, we are also subject to provisions of Texas law that may impair a takeover attempt that our shareholders may find beneficial. For additional information, see “Our LLC Agreement—Anti-Takeover Effects of Texas Law and Our LLC Agreement.” Any provision of our LLC Agreement or Texas law that has the effect of delaying or preventing a change in control could limit the opportunity for our shareholders to receive a premium for their common shares and could also affect the price that some investors are willing to pay for our Class A shares.

Our LLC Agreement will designate the Business Court in the Eleventh Business Court Division of the State of Texas (or, if the Business Court in the Eleventh Business Court Division of the State of Texas lacks jurisdiction, the U.S. District Court for the Southern District of Texas, or, if the U.S. District Court for the Southern District of Texas lacks jurisdiction, the district courts of Harris County, Texas) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders (excluding claims under the federal securities laws for which the U.S. District Court for the Southern District of Texas will be the sole and exclusive forum), which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees, other personnel or agents.

Our LLC Agreement will provide that unless we consent in writing to the selection of an alternative forum, the Business Court in the Eleventh Business Court Division of the State of Texas (or, if the Business Court in the Eleventh Business Court Division of the State of Texas lacks jurisdiction, the U.S. District Court for the Southern District of Texas, or, if the U.S. District Court for the Southern District of Texas lacks jurisdiction, the district courts of Harris County, Texas) will be the exclusive forum for the following types of actions or proceedings under Texas statutory or common law:

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any derivative action or proceeding brought on our behalf;

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any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, other employees or agents to us or our shareholders;

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any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the TBOC or our LLC Agreement; and

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any action asserting a claim against us or any director or officer or other employee of ours for any other entity claims (as defined in Section 2.115 of the TBOC).

However, such forum selection provision would not apply to claims brought to enforce a duty or liability created by the Exchange Act, the Securities Act or any other claim for which the federal courts have exclusive jurisdiction. Instead, our LLC Agreement will provide that, to the fullest extent permitted by applicable law, the U.S. District Court for the Southern District of Texas will be the sole and exclusive forum for resolving any complaint asserting a cause of action under the Securities Act, the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction.

This choice of forum provision may limit a shareholder’s ability to bring a claim in a judicial forum that it finds more favorable for disputes with us or with our directors, officers, other employees or

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agents, or our other shareholders, which may discourage such lawsuits against us and such other persons, and may result in increased costs for a shareholder to bring a claim. Alternatively, if a court were to find these provisions of our LLC Agreement inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our results of operations, cash flows, and financial position.

There are certain provisions in our LLC Agreement regarding fiduciary duties of our directors, exculpation and indemnification of our officers and directors and the approval of conflicted transactions that differ from the TBOC in a manner that may be less protective of the interests of our public shareholders and restricts the remedies available to shareholders for actions taken by our officers and directors that might otherwise constitute breaches of fiduciary duties.

Our LLC Agreement contains certain provisions regarding exculpation and indemnification of our officers and directors and the approval of conflicted transactions that differ from the TBOC in a manner that may be less protective of the interests of our public shareholders. For example, our LLC Agreement provides that to the fullest extent permitted by applicable law our directors or officers will not be liable to us. In contrast, if we were a corporation formed under the TBOC, a director or officer would be liable to us for (i) breach of the duty of loyalty to us or our shareholders, (ii) an act or omission not in good faith which constitutes a breach of duty or which involves intentional misconduct or knowing violations of the law, (iii) authorization of unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in Section 21.316 of the TBOC, (iv) a transaction from which the director or officer derived an improper personal benefit, or (v) an act or omission for which the liability of a director or an officer is expressly provided for by an applicable statute.

Pursuant to our LLC Agreement and indemnification agreements, we must indemnify our directors and officers for acts or omissions to the fullest extent permitted by law. In contrast, if we were a corporation formed under the TBOC, we could only indemnify directors and officers for acts or omissions if the director or officer acted in good faith and, in the case of conduct in the person’s official capacity as a director, in a manner he or she reasonably believed to be in the best interests of the corporation and, in all other cases, that the person reasonably believed his or her conduct was not opposed to the best interests of the corporation and with respect to any criminal action or proceeding, that such person had no reasonable cause to believe his or her conduct was unlawful.

Accordingly, our LLC Agreement may be less protective of the interests of our public shareholders, when compared to the TBOC, insofar as it relates to the exculpation and indemnification of our officers and directors.

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

We are a holding company and will have no material assets after the completion of this offering other than our equity interest in OpCo. Please see “Corporate Reorganization.” We will have no independent means of generating revenue. To the extent OpCo has available cash and subject to the terms of any debt instruments or other applicable agreements, we intend to cause OpCo to make (i) generally pro rata distributions to OpCo Unitholders, including us, in an amount at least sufficient to allow us to pay our taxes, (ii) at the election of certain holders of OpCo Units, additional distributions in an amount generally intended to allow such OpCo Unitholders to satisfy their respective income tax liabilities with respect to their allocable share of the income of OpCo (based on certain assumptions and conventions), which additional distributions may be made on a pro rata basis to all OpCo

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Unitholders (including us) or a non-pro rata basis to OpCo Unitholders (other than us) in redemption of OpCo Units from such holders and (iii) non pro rata distributions to us in an amount at least sufficient to reimburse us for our corporate and other overhead expenses. In addition, if our board of directors were to determine to pay dividends to holders of Class A shares, we, as the sole managing member of OpCo, would expect to cause OpCo to make pro rata distributions to all of its unitholders, including to us, in an amount sufficient to allow us to fund such dividends to our shareholders in accordance with our dividend policy. Therefore, although we expect to pay dividends on our Class A shares in amounts determined by our board of directors, from time to time, our ability to do so may be limited to the extent OpCo and its subsidiaries are limited in their ability to make these and other distributions to us. To the extent that we need funds and OpCo or its subsidiaries are restricted from making distributions under applicable law or under the terms of any current or future financing or other arrangements or are otherwise unable to provide such funds, our results of operations, cash flows and financial position could be materially and adversely affected.

In certain circumstances, OpCo will be required to make tax distributions to OpCo Unitholders, and such tax distribution may be substantial. To the extent we receive tax distributions in excess of our actual tax liabilities and retain such excess cash, the OpCo Unitholders would benefit from such accumulated cash balances if they exercise their Redemption Right.

Pursuant to the OpCo LLC Agreement, OpCo will make generally pro rata distributions to the OpCo Unitholders, including us, in an amount sufficient to allow us to satisfy our actual tax liabilities. In addition, to the extent OpCo has available cash, OpCo will be required to make additional pro rata tax distributions to all OpCo Unitholders in an amount generally intended to allow the OpCo Unitholders (other than us) to satisfy their assumed tax liabilities with respect to their allocable share of the income of OpCo (based on certain assumptions and conventions and as determined by OpCo). For this purpose, the determination of available cash will take into account, among other factors, (i) the existing indebtedness and other obligations of OpCo and its subsidiaries and their anticipated borrowing needs, (ii) the ability of OpCo and its subsidiaries to take on additional indebtedness on commercially reasonable terms and (iii) any necessary or appropriate reserves.

The amount of such additional tax distributions will be determined based on certain assumptions, including assumed income tax rates, and will be calculated after taking into account other distributions (including other tax distributions) made by OpCo. Additional tax distributions may significantly exceed the actual tax liability for many of the OpCo Unitholders, including us. If we retain the excess cash we receive from such distributions, the OpCo Unitholders would benefit from any value attributable to such accumulated cash balances as a result of their exercise of the Redemption Right. However, we intend to take steps to eliminate any material excess cash balances, which could include, but are not necessarily limited to, a distribution of the excess cash to holders of our Class A shares or the reinvestment of such cash in OpCo for additional OpCo Units.

In addition, the tax distributions that OpCo may be required to make may be substantial, and the amount of any additional tax distributions OpCo is required to make likely will exceed the tax liabilities that would be owed by a corporate taxpayer similarly situated to OpCo. Funds used by OpCo to satisfy its obligation to make tax distributions will not be available for reinvestment in our business, except to the extent we or certain other OpCo Unitholders use any excess cash received to reinvest in OpCo for additional OpCo Units. In addition, because cash available for additional tax distributions will be determined taking into account the ability of OpCo and its subsidiaries to take on additional borrowing, OpCo may be required to increase its indebtedness in order to fund additional tax distributions. Such additional borrowing may adversely affect our results of operations, cash flows and financial position by, without limitation, limiting our ability to borrow in the future for other purposes, such as capital expenditures, and increasing our interest expense and leverage ratios.

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If OpCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and OpCo might be subject to potentially significant tax inefficiencies might result.

Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”), generally provides that a “publicly traded partnership” will be treated as a corporation for U.S. federal income tax purposes. We intend to operate such that OpCo does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, redemptions of OpCo Units pursuant to the Redemption Right (or acquisitions of OpCo Units pursuant to the Call Right) or other transfers of OpCo Units could cause OpCo to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that redemptions or other transfers of OpCo Units qualify for one or more such safe harbors. For example, we intend to limit the number of OpCo Unitholders, and the OpCo LLC Agreement, which will be entered into in connection with the closing of this offering, will provide for limitations on the ability of OpCo Unitholders to transfer their OpCo Units and will provide us, as the managing member of OpCo, with the right to impose restrictions (in addition to those already in place) on the ability of OpCo Unitholders to redeem their OpCo Units pursuant to the Redemption Right to the extent we believe it is necessary to ensure that OpCo will continue to be treated as a partnership for U.S. federal income tax purposes.

If OpCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, significant tax inefficiencies might result for us and for OpCo, including as a result of our inability to file a consolidated U.S. federal income tax return with OpCo. In particular, OpCo would pay U.S. federal (and any applicable state) income tax on its taxable income at the corporate tax rate. Distributions to EagleRock would generally be taxed again as corporate distributions (subject to any applicable corporate dividends received deduction). Because a tax would be imposed on OpCo as a corporation, the amount of cash distributions to us could be substantially reduced, which may cause a substantial reduction in the value of our Class A shares.

We will incur increased costs as a result of being a publicly traded company.

As a publicly traded company, we will incur significant legal, accounting, and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act, as well as rules implemented by the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. As a result, we expect these requirements will increase our legal and financial compliance costs beyond that reflected in the financial statements included in this prospectus.

Forecasts and valuation assumptions underlying our initial public offering are preliminary and subject to change; our performance may not meet expectations.

All financial and operational projections are preliminary management estimates subject to diligence completion and market conditions; actual results and post-initial public offering results may differ materially. We may not achieve targeted margins, utilization or acquisition synergies, and the timing or terms of identified post-initial public offering acquisitions may vary or not occur. If our quarterly or annual operating results fall below the expectations of investors or securities analysts or any forecasts or guidance we may provide to the market, the price of our common shares could decline substantially. Such a share price decline could occur even when we have met any previously publicly stated guidance we may provide. We believe that quarterly or annual comparisons of our financial results are not necessarily meaningful and should not be relied upon as an indication of our future performance.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain “forward-looking statements.” All statements, other than statements of historical fact, included in this prospectus regarding our strategy, future operations, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, words such as “may,” “assume,” “forecast,” “could,” “would,” “should,” “will,” “plan,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget” 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 our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events at the time such statements were made. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the section titled “Risk Factors” included in this prospectus. By their nature, forward-looking statements involve known and unknown risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future. Although we believe that the forward-looking statements contained in this prospectus are based on reasonable assumptions, you should be aware that many factors could affect our actual results of operations, cash flows and financial position and could cause actual results to differ materially from those in such forward-looking statements, including:

•

our customers’ demand for and use of our surface, resources and water infrastructure assets;

•

our ability to enforce our SUA and other agreements with our customers;

•

the success of our operating partners in executing their business strategies, including their ability to construct and operate water infrastructure, attract customers and operate successfully;

•

our customers’ ability to develop our land or potential changes to our customers’ development plans, or any potential acquired acreage to accommodate any future surface use developments;

•

the domestic and foreign supply of, and demand for, energy sources, including the impact of actions relating to oil price and production controls by OPEC+ with respect to oil production levels and announcements of potential changes to such levels;

•

our reliance on a limited number of customers and a particular region for substantially all of our revenues, including the potential conditions of such customers within such region;

•

our ability to enter into favorable contracts regarding surface uses, access agreements and fee arrangements, including the prices we are able to charge and the margins we are able to realize;

•

our ability to maintain leases and permits, including our ability to renew leases on state and federal leased land;

•

changes in state and federal land use policies that change or restrict our right to use state and federal leased land or increase the cost of such leases;

•

our business strategies and our ability to execute thereon, including our ability to attract customers to use our land and resources;

•

commodity price volatility and trends related to changes in commodity prices, and our customers’ ability to manage through such volatility;

•

the level of competition from other companies, including those offering resources that compete with the resources from our land;

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•

changes in the price charged to our customers and availability of services necessary for our customers to conduct their businesses, as a result of oversupply, government regulations or other factors;

•

any planned or future expansion projects by us or our customers;

•

the development of advances or changes in energy technologies or practices;

•

our ability to successfully implement our growth plans, including through future acquisitions of acreage and/or introduction of new revenue streams;

•

the potential deterioration of our customers’ financial condition and their ability to access capital to fund their development programs;

•

the degree to which consolidation among our customers may affect spending on U.S. drilling and completions in the near term;

•

our customers’ ability to obtain necessary supplies, raw materials and other critical components on a timely basis, or at all;

•

our and our customers’ ability to obtain government approvals or acquire or maintain necessary permits, including those related to the development and operation of produced water handling facilities, mines and water wells;

•

operational disruptions and liability related thereto associated with our customers, including those due to environmental hazards, fires, explosions, chemical mishandling or other industrial accidents;

•

our liquidity and our ability to access the capital markets on favorable terms, or at all, which depends on general market conditions, including the impact of inflation, elevated interest rates and Federal Reserve policies and potential economic recession;

•

uncertainty of estimates of resources and minerals, such as oil, natural gas and NGL reserves and production, including those of our customers;

•

the effects of changes in general economic, business or industry conditions, market volatility, including as a result of slowing growth and a potential economic recession, an elevated inflation rate, high interest rates, changes in U.S. and international trade policies and relations, central bank policy and associated liquidity risks;

•

the effects of political instability or armed conflict in oil and natural gas producing regions, which may decrease demand for oil and natural gas or contribute to volatility in the prices for oil and natural gas, which could decrease demand for the use of our land and resources;

•

our level of indebtedness and our ability to service our indebtedness;

•

title defects in the acreage that we acquire;

•

the markets for real estate in the areas in which we operate and own or plan to own real estate, including pricing estimates, availability of land and our ability to acquire such land on favorable terms, or at all;

•

our ability to integrate acquired acreage, and any future acquisitions, and manage related growth;

•

our ability to recruit and retain, or secure the services of, key management and other personnel and service providers;

•

changes in laws and regulations (or the interpretation thereof), including those related to hydraulic fracturing, accessing water, disposing of wastewater, transferring produced water, interstate brackish water transfer, carbon pricing, pipeline construction, taxation or emissions, leasing, permitting or drilling and various other environmental matters;

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•

changes in effective tax rates, or adverse outcomes resulting from other tax increases or an examination of our income or other tax returns and tax inefficiencies;

•

general domestic and international political and regulatory conditions, including actions taken by the federal, state or foreign governments, such as executive orders or new or expanded regulations, including U.S. and international trade policies and tax policies, the OBBB Act and its impact on the IRA, and any action related to surface uses and/or development of our mineral and royalty interests;

•

the severity and duration of world health events, natural disasters or inclement or hazardous weather conditions, including cold weather, droughts, earthquakes, flooding and tornadoes;

•

evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insider or others with authorized access, cyber or phishing-attacks, ransomware, social engineering, physical breaches or other actions; and

•

other factors discussed elsewhere in this prospectus, including in the section titled “Risk Factors.”

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the operation of business in our industry. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. 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.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary note. This cautionary note should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

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USE OF PROCEEDS

The following table illustrates the anticipated use of the proceeds of this offering:


Source of Funds			Uses of Funds
Gross Proceeds from this offering	$	320,050,000	Repayment of Predecessor Credit Facility	$	270,000,000
			General Corporate Purposes	18,226,450
			Underwriting discounts, fees and expenses		31,823,550

Total	$	320,050,000	Total	$	320,050,000

After the application of the net proceeds from this offering, we will own approximately 19.2% of outstanding OpCo Units (or approximately 20.8% of outstanding OpCo Units if the underwriters’ option to purchase additional Class A shares is exercised in full).

Each $1.00 increase or decrease in the assumed public offering price of $18.50 per Class A share (the midpoint of the price range set forth on the cover of this prospectus) would increase or decrease the net proceeds to us from this offering by approximately $16.2 million (or approximately $18.6 million if the underwriters’ option to purchase additional Class A shares is exercised in full) and, as a result, would increase or decrease the amount of proceeds we will use for general corporate purposes by approximately $16.2 million (or approximately $18.6 million if the underwriters’ option to purchase additional Class A shares is exercised in full), assuming that the number of Class A shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting estimated underwriting discounts and estimated offering expenses payable by us. If the proceeds increase due to a higher public offering price or an increase in the number of Class A shares offered, we intend to contribute the additional net proceeds to OpCo in exchange for additional OpCo Units and OpCo intends to use such additional net proceeds to increase the amount of proceeds we will use for general corporate purposes. If the proceeds decrease due to a lower public offering price or a reduction in the number of Class A shares offered, we would contribute a lesser amount of net proceeds to OpCo and receive fewer OpCo Units and OpCo will decrease the amount of proceeds we will use for general corporate purposes.

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As of December 31, 2025, we had $265.6 million of outstanding borrowings under our Predecessor Credit Facility, exclusive of $35.1 million of unamortized debt premium (discount) and issuance costs, net, which matures on April 4, 2029. The weighted average interest rate on the total amount of borrowings outstanding under the Predecessor Credit Facility as of December 31, 2025 was 12.83% in the case of revolving credit borrowings and 12.81% in the case of term loan borrowings. We are currently in compliance with all affirmative and negative covenants under the facility.

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DIVIDEND POLICY

We expect to seek to pay dividends on our Class A shares in amounts determined from time to time by our board of directors.

While we expect to seek to pay dividends, we have not adopted a formal written dividend policy to pay any particular amount of dividends based on the achievement of, or derivable from, any specific financial metrics. Furthermore, we are not contractually obligated to pay any dividends and do not have any required minimum dividend amount, and the Credit Facility will limit our ability to pay dividends. If our board of directors determines to pay dividends in the future, the amount of such dividends may vary from quarter to quarter and may be significantly reduced or eliminated entirely. The actual amount of any dividends we pay may fluctuate depending on our cash flow needs, which may be impacted by the availability of financing alternatives, the need to service any future indebtedness or other liquidity needs, potential acquisition opportunities and general industry and business conditions, including the level of use of our land and its resources. Given our reliance on our customers and their activity on our land, we cannot provide any assurance that we will pay dividends in the future. For more information see “Risk Factors—Risks Related to this Offering, Our Corporate Structure and Our Class A Shares—Our ability to pay dividends to our shareholders may be limited by our holding company structure, contractual restrictions and regulatory requirements.” The declaration and payment of any dividends by us will be at the sole discretion of our board of directors, which may change our dividend policy or discontinue payment of dividends at any time. In determining whether to pay any dividends and the timing and amount thereof, we expect that our board of directors will consider:

•

general economic and business conditions;

•

our financial condition and results of operations;

•

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

•

our capital requirements, including future acreage acquisitions;

•

legal, tax, regulatory and contractual (including under the Credit Facility and future financing arrangements) restrictions and implications on the payment of dividends by us to our shareholders or the payment of distributions by our subsidiaries to us; and

•

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

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CAPITALIZATION

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

•

on an actual basis for L&E, our predecessor;

•

on a pro forma basis to give effect to the exclusion of the Excluded Assets, the Shallow Valley Contribution and the DE Flow Contribution; and

•

on a pro forma, as adjusted basis to give effect to the Pro Forma Transactions and the Up-C Reorganization and this offering at the assumed initial offering price of $18.50 per Class A share (the midpoint of the price range set forth on the cover of this prospectus) and the application of the net proceeds therefrom as described under the section titled “Use of Proceeds.”

The information set forth below is illustrative only and will be adjusted based on the actual public offering price and other final terms of this offering. The table below should be read in conjunction with, and is qualified in its entirety by reference to, the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial information of L&E and our unaudited pro forma condensed consolidated financial information for the periods and as of the dates indicated.


	As of December 31, 2025
	Predecessor			Pro Forma			Pro Forma, as Adjusted
	(in thousands, except number of common shares)
Cash and cash equivalents	$	9,042		$	—		$	16,818

Long-Term Debt:
Predecessor Credit Facility⁽¹⁾		265,610			265,610			—
Credit Facility		—			—			—
Equity:
Common units (2,095 units authorized, 1,195 and 1,000 outstanding as of December 31, 2025 and 2024, respectively)		14,016			—			—
Additional paid in capital—members’ interests		(1	)		—			—
Additional paid in capital—warrants—related party⁽²⁾		18,416			—			—
Additional paid in capital		—			1,272,087			—
Accumulated deficit		(74,146	)		(89,401	)		—
Class A members’ equity; no Class A shares issued or outstanding (actual and pro forma); 24,960,419 Class A shares issued and outstanding (pro forma, as adjusted)		—			—			290,093
Class B members’ equity; no Class B shares issued or outstanding (actual and pro forma); 105,164,580 Class B shares issued and outstanding (pro forma, as adjusted)		—			—			—
Noncontrolling interest⁽³⁾		—			—			1,222,238

Total capitalization	$	223,895		$	1,448,296		$	1,512,331

(1)	The balance of the Predecessor Credit Facility reflects outstanding borrowings as of December 31, 2025, and excludes $35.1 million of unamortized premium. As of May 1, the Predecessor Credit Facility had a payoff balance of approximately $270.0 million.

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(2)

As described in “Corporate Reorganization,” in connection with this offering, each TCW Entity will, pursuant to a Warrant Exercise Agreement, exercise a portion of its L&E Warrants and forfeit the remaining portion, which will be irrevocably cancelled, immediately following which (i) L&E will distribute 14,940,269 OpCo Units and a corresponding number of Class B shares to the TCW Entities in redemption of the L&E units received in respect of the Exercised Warrants, (ii) each Warrant Agreement will terminate and (iii) each of the Rollover TCW Entities will merge with one or more newly formed subsidiaries of EagleRock and receive one Class A share in exchange for each OpCo Unit (and Class B share) it holds, or an aggregate 4,560,785 Class A shares. As a result, the L&E Warrants will no longer be outstanding following this offering. For further details regarding the L&E Warrants, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Predecessor Liquidity and Capital Resources—L&E Warrants.”

(3)

On a pro forma, as adjusted basis, includes the OpCo Units not owned by us, which represent approximately 80.8% of outstanding OpCo Units immediately after this offering. Our Existing Owners will hold a non-controlling economic interest in OpCo. We will hold approximately 19.2% of outstanding OpCo Units immediately after this offering (or approximately 20.8% of outstanding OpCo Units if the underwriters’ option to purchase additional Class A shares is exercised in full).

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DILUTION

Purchasers of the Class A shares in this offering will experience immediate and substantial dilution in the net tangible book value per Class A share for accounting purposes. Our pro forma net tangible book value as of December 31, 2025, after giving effect to the Pro Forma Transactions, was $60.7 million, or $0.54 per Class A share. Pro forma net tangible book value per Class A share is determined by dividing our pro forma, as adjusted tangible net worth (tangible assets less total liabilities) by the total number of Class A shares that would have been outstanding immediately prior to the closing of this offering after giving effect to the Pro Forma As Adjusted Transactions other than this offering and the application of the net proceeds therefrom (assuming that 100% of our Class B shares have been cancelled in connection with a redemption of OpCo Units for Class A shares on a one-for-one basis).

After giving effect to the sale of Class A shares in this offering and further assuming the receipt of the estimated net proceeds from this offering (after deducting estimated underwriting discounts and estimated offering expenses payable by us), our pro forma, as adjusted net tangible book value as of December 31, 2025 would have been $390.3 million, or $3.00 per Class A share. This represents an immediate increase in the net tangible book value of $2.46 per Class A share (assuming that 100% of our Class B shares have been cancelled in connection with a redemption of OpCo Units for Class A shares) to our Existing Owners and the TCW Entities and an immediate dilution (i.e., the difference between the offering price and the as adjusted net tangible book value after this offering) to new investors purchasing Class A shares in this offering of $15.50 per Class A share. The following table illustrates the per Class A share dilution to new investors purchasing Class A shares in this offering (assuming that 100% of our Class B shares have been cancelled in connection with a redemption of OpCo Units for Class A shares on a one-for-one basis):


Public offering price per Class A share		$	18.50
As adjusted net tangible book value per Class A share as of December 31, 2025 (after giving effect to the Pro Forma Transactions)	0.54
Increase per Class A share attributable to this offering and related transactions as described above	2.46

Pro forma, as adjusted net tangible book value per Class A share (after giving further effect to this offering and the related transactions as described above)			3.00

Dilution in pro forma, as adjusted net tangible book value per Class A share to new investors in this offering		$	15.50

The dilution information discussed in this section is illustrative only and will change based on the actual public offering price and other terms of this offering to be determined at pricing. Each $1.00 increase or decrease in the public offering price of $18.50 per Class A share (the midpoint of the price range set forth on the cover of this prospectus) would increase or decrease the net proceeds to us from this offering by $16.2 million (or $18.6 million if the underwriters’ option to purchase additional Class A shares is exercised in full), assuming the number of Class A shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting estimated underwriting discounts and estimated offering expenses payable by us.

The following table summarizes, on a pro forma, as adjusted basis as of December 31, 2025, the total number of Class A shares owned by our Existing Owners and the TCW Entities (assuming that 100% of our Class B shares have been cancelled in connection with a redemption of OpCo Units for Class A shares) and to be owned by new investors in this offering, the total consideration paid, and the average price per share paid by our Existing Owners and the TCW Entities and to be paid by new

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investors in this offering at our initial offering price of $18.50 per Class A share, calculated before deduction of estimated underwriting discounts and estimated offering expenses payable by us.


	Shares Acquired					Total Consideration					Average Price Per Share
	Number		Percent			Amount		Percent			Average Price Per Share
	(in thousands except share and per share amounts)
Existing Owners and TCW Entities		109,725,365		86.4	%	$	991,446		75.6	%	$	9.04
New investors in this offering		17,300,000		13.6	%		320,050		24.4	%		18.50

Total		127,025,365		100	%	$	1,311,496		100.0	%	$	10.32

The information excludes (i) 13,012,499 Class A shares reserved for issuance under our LTIP, which we intend to adopt in connection with the completion of this offering, (ii) 3,099,634 Class A shares issued as bonuses in connection with this offering, and (iii) Class A shares reserved for issuance in connection with any exercise of the Redemption Right or the Call Right.

Except as otherwise noted, all information in this prospectus assumes (i) no exercise by the underwriters of their option to purchase additional Class A shares and (ii) no purchase of Class A shares by our directors, officers, employees and other individuals associated with us and members of their families through the directed share program. If the underwriters’ option to purchase additional Class A shares is exercised in full, the number of Class A shares held by new investors in this offering will be increased to 19,895,000, or 72.2% of the total number of Class A shares outstanding immediately after this offering.

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

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with “Summary—Summary Consolidated Financial and Other Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. Unless otherwise indicated, all references to financial or operating data on a pro forma basis give effect to the Pro Forma Transactions described under “Basis of Presentation” and in the Unaudited Pro Forma Condensed Consolidated Financial Statements 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. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in the sections titled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, actual results may differ materially from those contained in our forward-looking statements. We assume no obligation to publicly update any of these forward-looking statements except as otherwise required by applicable law.

Overview

Our Business

We are a land management company that owns or controls approximately 236,000 acres in the heart of the Delaware and Midland sub-basins within the prolific Permian Basin. In addition, we have an interest in up to approximately 70,000 acres pursuant to an acreage dedication related to our Midland Basin water infrastructure assets. Our acreage is vital to the efficient development of oil and natural gas resources in the Permian Basin and is strategically located to support the growing surface, resource, infrastructure and related commercial development needs of the power and other emerging industries in the Permian Basin. We do not own the oil and gas mineral interests that underlie our surface acreage.

Our assets are situated in the most active oil and natural gas development and production areas in Texas and New Mexico. The Permian Basin is regarded as the premier region for upstream development due to its prolific remaining resource, low break-even costs and robust network of service and infrastructure companies that support upstream activity. The depth and quality of the remaining resource has attracted large, public and well-capitalized producers who have largely consolidated the core of the Midland and Delaware sub-basins. In turn, the abundance of economic and highly reliable energy has underpinned a number of emerging industries within the Permian Basin, including traditional and renewable power generation, transmission and storage and data centers.

Market Condition and Outlook

Over the last several years, the global economy and the oil and natural gas industry have experienced considerable volatility driven by a range of macroeconomic and geopolitical factors. Global conflicts, ongoing ambiguity surrounding tariffs and international trade policies, domestic political developments, elevated inflation, higher interest rates and changing costs of capital have influenced business activity across the energy sector, contributing to broader economic uncertainty that continues to affect short- and long-term development decisions of energy companies.

These conditions, combined with the war in the Middle East involving the U.S., Israel and Iran, as well as other Middle Eastern countries, the situation in Venezuela, OPEC+ actions and evolving global supply-demand fundamentals, have driven increased volatility in commodity prices. From December 31,

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2024, to December 31, 2025, average WTI oil prices decreased approximately 14.7% year-over-year, while average Henry Hub natural gas prices increased approximately 60.2% over the same period. However, in March 2026, as a result of the escalating Middle East conflict, WTI posted price increased to over $94.0 per barrel or 38.0%, since December 31, 2025 as a result of production shut-ins, interruptions in global shipping routes and other uncertainties. Volatility in oil and natural gas prices may have an impact on customer activity levels on our land. If global oil prices continue to increase or remain high, we believe there could be increased oil and gas development activities in the Permian Basin where our acreage and assets are located. However, sustained higher crude oil prices could result in general price increases and ultimately increased cost inflation, which could adversely impact our and our customers’ future profitability if we and they are unable to timely pass-through the cost increases to our customers. Alternatively, resolution of the conflict in the Middle East, particularly if new sources of crude oil supply become available, could result in a decrease in crude oil prices, which could reduce the activity levels of customers on our acreage.

Despite the significant volatility in the global oil market, we believe the outlook for energy and infrastructure development, particularly in the Permian Basin, remains favorable. The focus on energy independence is promoting continued activity in the U.S., which is expected to drive significant investment in infrastructure, especially in the prolific Permian Basin where our land and assets are located. U.S. energy policy developments, including Executive Orders promoting domestic energy production through expedited infrastructure approvals and reduced barriers to resource development, may further support investment and operational activity in the basin. At the same time, federal incentives for alternative and renewable energy technologies may accelerate the broader energy transition. Many of these emerging energy initiatives, similar to traditional oil and gas development, require substantial surface acreage and related infrastructure, positioning companies with significant land and infrastructure assets to benefit from both traditional and renewable energy sources.

How We Generate Revenue

We generate revenue from multiple sources, including the use of our surface acreage, the sale of water and other resources from our land and our water handling infrastructure. The fees, royalty rates, payment structures and other commercial terms under our contracts are negotiated individually, reflecting the specific surface use, type of resource development, anticipated operational intensity and expected production or extraction volumes associated with each agreement. Further, the amount and composition of revenue we receive from a particular customer may vary significantly from period to period based on the nature, timing and scope of that customer’s activities on our land. We are focused on actively growing revenue from the use of our surface acreage and the sale of resources from our land. We believe that our largely fee-based SUAs, as well as our strong base of royalty fees, support cash flow stability through commodity price cycles.

The table below summarizes revenues for our predecessor on a historical and pro forma, as adjusted basis for the periods indicated:


	Predecessor⁽¹⁾				Pro Forma, as Adjusted
	Year Ended December 31,
	2024		2025		2025
	(in thousands)
Resource sales and royalties:
Resource sales	$	14,120	$	55,179	$	65,713
Resource royalties		—		—		—
Surface use royalties and revenues:
Surface use related revenues		3,120		13,667		21,922
Surface use royalties		461		3,327		53,803

Total revenues⁽²⁾	$	17,701	$	72,173	$	141,438

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(1)

2024 and 2025 Resource sales referenced above consists of $10.9 million and $50.3 million reported as “Water sales,” $1.4 million and $0.5 million reported as “Related party water sales” and $1.8 million and $4.3 million of mined caliche resource sales reported as “Surface and other revenues,” respectively, on our predecessor’s Consolidated Statement of Operations. The remaining revenues reported on our predecessor’s Consolidated Statement of Operations have been disaggregated between Surface use royalties and Surface use related revenues above.

(2)	Refer to the Unaudited Pro Forma Condensed Consolidated Financial Statements included elsewhere in this prospectus for additional information on the reclassification of revenues included in the Predecessor’s 2025 financial statements to conform to the line items above.

In the early stages of a customer’s development program, we typically generate usage-based fees and other revenues related to the installation of infrastructure required to support long-term operations. As development progresses, these revenues generally transition toward royalty or lease revenues and resource sales based on the customer’s ongoing use of our land and the extraction of resources to support its oil and gas development activities.

The following table summarizes our revenue streams:


Resource Sales and Royalties

Resource sales		Water sales based on a fee per barrel and caliche sold to customers at a fixed fee per cubic yard

Resource royalties		Royalties generated from third-parties extracting and/or selling resources from our land
Surface Use Royalties and Revenue

Surface use royalties		Royalties from produced water takeaway, transportation and disposal, and transportation and sale of recycled water, based on use of our assets

Surface use related revenues		Surface lease and fees based on fixed fees and rates for a variety of activities

Resource Sales and Royalties

Under our SUAs, we supply water to upstream operators primarily for use in their well completions in exchange for a per barrel fee. These fees are negotiated and vary depending on the delivery point. Our SUAs provide us with the exclusive right to supply water and certain resources to support an operator’s completion activities on certain parts of our acreage at a negotiated fixed fee per barrel. Similarly, our customers are required to purchase caliche from us for the construction of access roads and well pads for which we receive a fixed-fee per cubic yard of caliche extracted from our surface acreage as stipulated in such SUAs.

Surface Use Royalties and Revenue

Under our SUAs, we receive a royalty based on a percentage of gross revenue derived from the use of our land and/or volumetric use of infrastructure installed on our land in exchange for rights of use of our land, one-time or annual payments and additional fees at each renewal period. We typically receive royalties from such operations under our SUAs throughout the lifecycle of our customers’ activities on our land. Surface use royalties include royalties from certain SWDs on and off our ranches

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and lease payments with a base rate from use of our subsurface pore space, third-party sales of recycled water, development and use of drilling sites, new and existing roads, pipeline easements and electric transmission easements.

Under the Hydrosource Recycling Agreement that will be entered into in connection with this offering, we will receive a fee for each barrel of recycled water Hydrosource sells on our land and within certain designated areas outside of our land, and Hydrosource is required to generate minimum annual royalty revenue of $5.0 million from its activities during the initial five years of the agreement. The Company and Hydrosource have access to supplemental off-ranch water (either recycled or brackish water), and the Company’s surface pipeline has the capacity to move approximately 100 MBbls/d, or approximately 36.5 MMBbls per year, of off-ranch water from Texas to its land in New Mexico. Under the Hydrosource Recycling Agreement, we may designate to Hydrosource the rights to manage certain of our customer brackish water demand for which we would expect to receive a royalty payment. Additionally, the Hydrosource Recycled Water Supply Agreement provides Hydrosource with access to up to 3 MMBbls/d of produced water for treatment and recycling within certain designated areas in the Permian Basin.

Additionally, we will receive revenue from our integrated water infrastructure system in the Midland Basin, which is operated by DEF Operating. The operating costs and maintenance expenses of these water infrastructure assets, which include produced water gathering systems, SWDs, water sourcing and delivery pipelines and recycling facilities, will be primarily borne by DEF Operating, with minimal operating costs or capital expenditures borne by us.

Our revenues may fluctuate materially from period to period due to variations in producer activity on and around our land, the introduction of new revenue streams, movements in commodity prices, changes in production volumes and the execution of our acquisition strategy, among other factors. Because our business is closely tied to the operational decisions of our customers, shifts in their development plans directly affect our revenue profile and periods of sustained oil and natural gas price declines have historically led customers to reduce activity levels, which would adversely impact our revenues. We expect to evaluate and pursue opportunities to expand and diversify our revenue base, including potential projects related to solar power generation, energy storage, water treatment and desalination, fueling infrastructure, data centers, telecommunications assets and other complementary uses of our land, although there can be no assurance that these initiatives will be successful or that any resulting revenues will materially diversify our overall revenue mix. In addition, we have grown our revenues, Adjusted EBITDA and cash flow through strategic acquisitions, customer pricing and volume improvements enabled by our ability to consolidate acreage with significant oil and gas development activity, and by working collaboratively with customers on and around our controlled surface acreage to sign new agreements and promote increased use of our land and resources. Our ability to source new commercial opportunities for assets we own or have acquired has contributed to strong financial results, and our business model and significant free cash flow generation continue to be underpinned by low or no capital expenditures with minimal operating costs and employee headcount. In addition, our long-term contracts provide predictable, stable cash flows that are protected from commodity price fluctuations.

Costs of Conducting our Business

Our costs consist primarily of the cost of sales and general and administrative expenses. Our business model and significant free cash flow generation continue to be underpinned by low or no capital expenditures with minimal operating costs and headcount. Our principal costs are as follows:

Cost of Sales. Cost of sales consists primarily of expenses incurred to manage our land, and its resources which include our field personnel’s compensation and related benefits, third-party water purchases, water treatment and handling costs, including cost of repairs and maintenance of ancillary

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water storage facilities and costs associated with compliance with our leased land obligations. These costs generally fluctuate with changes in volumes and activity levels of our customers. Water sourced from our water wells typically has insignificant lifting costs associated with the pumping and logistics of the water resources. In certain instances, we source and purchase supplemental water from other third parties to meet our incremental customer demands. We pass through the costs of our third-party sourced water and handling costs to our customers at costs plus a markup.

General and Administrative Expenses. General and administrative expenses consist primarily of corporate personnel costs, including salaries, bonuses, service fees, payroll taxes and employee-related insurance. These expenses also include professional services such as legal, consulting and accounting fees, as well as information technology and software costs that support our corporate functions. Office-related expenses, such as rent, office equipment rentals, supplies, communications, bank charges and dues and subscriptions, represent an additional component of our administrative cost structure. We also incur various commercial insurance costs, including general liability, directors and officers insurance, umbrella liability, workers’ compensation, auto insurance and property insurance, along with other corporate overhead such as marketing, travel, meals, vehicle lease expenses and miscellaneous administrative expenses. These costs reflect the resources required to manage our business, comply with regulatory and public company requirements and support the organizational infrastructure needed to execute our strategic objectives.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our business.


	Predecessor⁽¹⁾						Pro Forma, as Adjusted
	Year ended December 31,
	2024			2025			2025
	($ in thousands)
Statement of Operations Data:
Revenues
Resource sales	$	14,120		$	55,179		$	65,713
Resource royalties		—			—			—
Surface use related revenues		3,120			13,667			21,922
Surface use royalties		461			3,327			53,803

Total revenues⁽²⁾	$	17,701		$	72,173		$	141,438
Cost of sales (exclusive of depreciation and amortization)	$	4,873		$	20,863		$	19,178
Related party cost of sales		3,438			10,207			—
General and administrative expense		2,600			9,834			65,142
Related party general and administrative expense		198			235			205
Depreciation and amortization expense		3,944			14,984			52,808
Gain on sale of property, plants and equipment, net		(4,954	)		(2,067	)		(3,833	)

Total operating expenses	$	10,099		$	54,056		$	133,500

Operating Income (Loss)	$	7,602		$	18,117		$	7,938

Interest expense		—			—			(385	)
Interest expense—related party		(8,703	)		(21,185	)		—
Interest income		—			—			109
Loss on extinguishment of debt		—			(70,001	)		(5,123	)

Income from operations before taxes	$	(1,101	)	$	(73,069	)	$	2,539

Income tax expense (benefit)		(26	)		2			130

Net income (loss)	$	(1,075	)	$	(73,071	)	$	2,409

Net income (loss) Margin		(6.1	)%		(101.2	)%		1.7	%

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	Predecessor⁽¹⁾						Pro Forma, as Adjusted
	Year ended December 31,
	2024			2025			2025
	($ in thousands)

Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	907		$	14,138
Investing activities	$	(64,556	)	$	(204,963	)
Financing activities	$	64,711		$	199,090
Operating cash flow margin		5.1	%		19.6	%

Supplementary Non-GAAP Financial and Operating Data:
Adjusted EBITDA⁽³⁾	$	7,350		$	35,533		$	118,581
Adjusted EBITDA Margin		41.5	%		49.2	%		83.8	%
Free Cash Flow⁽³⁾	$	5,868		$	30,281
Free Cash Flow Margin		33.2	%		42.0	%
Surface Use Efficiency⁽⁴⁾	$	202.3		$	415.6		$	462.0
Total Water Volumes (MMBbls)⁽⁵⁾		19.2			73.0			237.7

Selected Balance Sheet Data (at end of period):
Cash and cash equivalents	$	1,062		$	9,042		$	16,818
Total assets	$	86,694		$	282,010		$	1,522,239
Non-current liabilities	$	77,521		$	306,594		$	2,537
Total liabilities	$	87,769		$	323,725		$	9,908
Total equity	$	(1,075	)	$	(41,715	)	$	1,512,331

(1)

(2)	Refer to the Unaudited Pro Forma Condensed Consolidated Financial Statements included elsewhere in this prospectus for additional information on the reclassification of revenues included in the Predecessor’s 2025 financial statements to conform to the line items above.

(3)	See “Summary—Non-GAAP Financial Measures” for a reconciliation of these measures to the nearest GAAP measure.

(4)	Surface Use Efficiency is calculated by dividing revenue by weighted average total surface acreage. See “—Surface Use Efficiency” below for more information on the calculation and use of this metric.

(5)	See “Total Water Volumes” below for more information on the use of this metric.

Revenue

Revenue is a key performance indicator for our business. We monitor realized revenue on a monthly, quarterly and annual basis and compare these results to our internal forecasts and budgets. This analysis helps us validate, and when necessary, update, our assumptions regarding the macroeconomic factors influencing our business, the mix of contracts affecting average unit-level revenues, and the level of development activity and commodity pricing associated with our E&P customers, independent of the impact of our operating costs.

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Surface Use Efficiency

We calculate surface use efficiency as total revenues divided by our weighted average total surface acreage. Weighted average total surface acreage represents the total surface acreage owned or controlled by the Company, weighted based on the portion of the period during which the acreage was owned or controlled by the Company. The metric quantifies the effectiveness of our active land management strategy by looking at our ability to optimize revenue on our acreage, evaluate accretive acreage acquisition and compare results period over period. Additionally, we believe this metric serves as a benchmark of our team’s strategy, as well as the relative value of our surface acreage, compared to peers.

Total Water Volumes

Total water volumes sold or handled are an important revenue driver for our business. We generally charge a fixed per-barrel fee for water sales and expect to receive a royalty for water activity under the Hydrosource Recycling Agreement and DE Flow WSMA. Our SUAs provide us with the exclusive right to supply water and certain resources to support an operator’s completion activities on certain parts of our acreage. Revenue increases as total water volumes sold or handled increase, and these volumes are an indicator of activity on our land, which can be driven by our customers’ drilling and completion schedules. We believe this metric is useful because our revenues increase as total water volumes sold or handled increase. In addition, water volumes are an indicator of activity on our land and give visibility into our customers’ drilling and completion schedules, which influence our

financial performance.

Adjusted EBITDA and Adjusted EBITDA Margin

Adjusted EBITDA and Adjusted EBITDA Margin are used by our management and by external users of our financial statements, such as investors, research analysts and others, to assess the financial performance of our assets over the long term to generate sufficient cash to return capital to equity holders or service indebtedness and to evaluate our performance relative to our peers. For more information regarding Adjusted EBITDA and Adjusted EBITDA Margin, including reconciliations to the comparable GAAP measure, please read “Summary—Non-GAAP Financial Measures.”

Free Cash Flow and Free Cash Flow Margin

Free Cash Flow and Free Cash Flow Margin are used by our management and by external users of our financial statements, such as investors, research analysts and others, to assess our ability to repay our indebtedness, return capital to our shareholders, fund potential acquisitions without access to external sources of financing for such purposes and to evaluate our performance relative to our peers. For more information regarding Free Cash Flow and Free Cash Flow Margin, including reconciliations to the comparable GAAP measure, please read “Summary—Non-GAAP Financial Measures.”

Key Factors Affecting our Results of Operations

Dependence on Hydrocarbon Activity and Commodity Prices

Our results of operations are substantially dependent on the level of oil and natural gas exploration, development and production activity on and around our surface acreage in the Permian Basin, including our properties in the Delaware Basin in New Mexico and the Midland Basin in Texas, which activity is significantly influenced by prevailing and expected commodity prices. Although we are not an E&P company and have limited physical operations, we primarily generate revenues from

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surface use fees, easements and rights-of-way, resource sales, such as brackish water and caliche, and royalties associated with third-party development and infrastructure on or adjacent to our lands, rather than by operating drilling or midstream assets. As a result, any sustained reduction in operator activity on or around our lands could materially reduce our revenues, earnings and cash flows. Periods of lower commodity prices may cause operators to curtail drilling and completion programs, defer or renegotiate commercial arrangements or surrender leases, any of which could reduce demand for surface access, water and other resources sourced from our lands and diminish volumetric royalties tied to produced-water handling and disposal, thereby adversely affecting our ability to realize anticipated revenues from our existing asset base. While certain arrangements, such as our Hydrosource Recycling Agreement and DE Flow WSMA, which include minimum annual royalty revenues can partially mitigate volume risk, these features do not eliminate our exposure to reduced activity levels, delays or cancellations driven by commodity price weakness or volatility.

Our ability to grow also depends on continued demand for access to our lands and associated surface rights by E&P operators, midstream providers and other energy and infrastructure users, which demand is closely linked to commodity price expectations, industry capital spending and basin-level capital allocation. If oil and natural gas prices remain depressed or volatile for an extended period, or if operators reallocate capital away from the Delaware or Midland basins where our properties are concentrated, we could experience slower growth in new surface-use arrangements, reduced renewals or expansions of existing agreements and intensified competition for fewer development opportunities. In particular, throughput and related royalties from our Midland Basin produced-water handling network (operated by DEF Operating and currently designed for peak handling capacity of approximately 400 MBbls/d) depend on producer activity levels and the pace of tie-ins, constraints such as pore-space availability, recycling and injection permitting, supply-chain delays or deferrals of drilling and completion schedules can limit volumetric growth and associated payments to us notwithstanding contractual protections. More broadly, because a substantial portion of our revenues are activity-linked, arising from surface use fees, ROWs and easements, water sales, produced-water transportation, recycling and disposal royalties and resource sales (including caliche), industry slowdowns can directly reduce the number, timing and scale of projects undertaken on our land, negatively affecting our results of operations and our ability to execute our growth strategy.

Public Company Costs

Following the completion of this offering, we expect to incur incremental, non-recurring costs associated with our transition to a publicly traded and taxable entity. These transition-related expenses will include offering-related professional fees and other offering costs, as well as the initial design, documentation, implementation and testing of enhanced internal controls over financial reporting under the Sarbanes-Oxley Act. We also anticipate one-time investments in governance structures and policies, board and committee operations, director onboarding and training and upgrades to financial reporting, disclosure and compliance systems necessary to support public company requirements.

In addition to these non-recurring items, we expect to incur significant recurring costs as a public company. These ongoing expenses will include SEC reporting and compliance obligations (including the preparation, review and filing of annual, quarterly and current reports), registrar and transfer agent fees, national securities exchange listing fees, recurring audit and legal fees, investor relations activities and related communications and increased director and officer liability insurance premiums and director compensation. We also expect to incur continuing costs to maintain and periodically test internal controls and disclosure controls and procedures, sustain cybersecurity and data privacy programs appropriate for a public company environment and retain external advisors to support technical accounting, tax compliance and other specialized governance and regulatory matters.

In connection with this offering and our public company readiness efforts, we expect to hire additional employees and engage consultants, including accounting, finance, compliance, internal

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audit, tax and legal personnel, to support the operational, reporting and compliance requirements of being a publicly traded company. The timing and magnitude of these costs will vary based on the pace of our transition activities, evolving regulatory requirements and market practices, and could increase over time as our operations grow or as standards change. While we believe these investments are necessary to support our long-term strategy as a public entity, they will result in higher general and administrative expenses relative to historical periods.

Corporate Reorganization

We were formed solely to serve as the issuer in this offering and, other than activities related to this offering, have not conducted any material business operations to date. As a result, the historical consolidated financial statements and other historical financial information included in this prospectus reflect the results of our accounting predecessor, Lea & Eddy Holdings, LLC, and not our results as the post-reorganization public company. The Corporate Reorganization will be effected immediately prior to, and will be conditioned upon, the consummation of this offering. If the offering is not completed, the Corporate Reorganization will not occur. Accordingly, the historical consolidated financial data may not indicate what our results would have been had the Corporate Reorganization been completed at the beginning of the periods presented, nor what our future results are likely to be. See “Corporate Reorganization” for a detailed description of these steps.

Following the Corporate Reorganization, we will be a holding company and the sole managing member of OpCo, consolidating OpCo for financial reporting purposes while initially reflecting a noncontrolling interest for OpCo Units not owned by us. Our structure is commonly referred to as an “Up C,” in which public investors hold our Class A shares and thereby an indirect interest in OpCo, while our Existing Owners and the TCW Entities initially hold a majority of OpCo Units paired with our Class B shares. Our and OpCo’s capital structures will generally mirror one another to maintain a one-for-one exchange ratio between OpCo Units and our Class A shares. Although organized as a limited liability company, we have elected to be taxed as a corporation for U.S. federal income tax purposes. For additional detail regarding the sequencing of the Corporate Reorganization, our governance rights as OpCo’s sole managing member and our post-offering ownership and control, see “Corporate Reorganization” and “Certain Relationships and Related Party Transactions—OpCo LLC Agreement.”

Because of this structure, investors should carefully consider the basis of presentation used throughout this prospectus. Unless otherwise indicated, historical financial information reflects our predecessor (L&E), whereas certain pro forma and pro forma, as adjusted information gives effect to the Corporate Reorganization, related contributions and exclusions and this offering as described herein. The timing and magnitude of redemptions or exchanges of OpCo Units for our Class A shares over time will change our relative economic interest in OpCo and the amount of noncontrolling interest reflected in our consolidated financial statements, which may affect the comparability of our future results to historical or pro forma periods. For more information, including the illustrative effects of these transactions, see “Basis of Presentation,” “Corporate Reorganization,” and our Unaudited Pro Forma Condensed Consolidated Financial Statements included elsewhere in this prospectus.

Acquisitions

Concurrently with the completion of this offering, we expect to consummate the L&E Contribution, the DE Flow Contribution and the Shallow Valley Contribution, through which we will acquire significant surface acreage and water infrastructure assets that expand our operating footprint and revenue-generating asset base. These transactions will be accounted for in accordance with applicable GAAP, which may result in recognition of identifiable intangible assets and property, plant and equipment of the accounting acquirees at fair value and could include differences in the timing and classification of

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acquisition-related costs depending on the final accounting conclusion. As a result, our post-offering results will reflect a larger asset base and a different mix of revenues and expenses than those presented in our predecessor’s financial statements. See the Unaudited Pro Forma Condensed Consolidated Financial Statements included elsewhere in this prospectus for additional information regarding the DE Flow Contribution and the Shallow Valley Contribution and their pro forma effects.

These acquisitions will impact the comparability of our results of operations across periods. In particular, we expect changes in depreciation and amortization expense associated with the fair value step-up in the carrying value of acquired assets (if applicable), incremental operating and maintenance costs tied to the newly acquired water infrastructure and potential changes in revenue composition and margins as utilization ramps and commercial terms across the combined asset base are harmonized. We may also incur one-time integration and transition-related expenses, including costs to align systems, processes and contracts; rationalize overlapping functions; and implement common safety, environmental and operational standards. Accordingly, results in periods following the consummation of these contributions to us may not be comparable to our historical results. See “Risk Factors,” and “—Results of Operations” for discussion of the expected effects on our operating metrics and margins.

We may pursue additional acquisitions of surface acreage and related infrastructure in the future where we believe opportunities are strategic and appropriately priced. Any such transactions could further affect period-to-period comparability due to changes in scale, asset mix, contract profile, capital structure and purchase accounting effects, and could require incremental integration efforts and costs. The timing, size, structure and financing of any acquisitions will depend on market conditions, availability of suitable targets and our capital allocation priorities. See “Risk Factors—Risks Related to Our Business and Operations” and “—Pro Forma Liquidity and Capital Resources” for additional information about acquisition-related risks and financing consideration.

EagleRock Credit Facility

We anticipate that we will repay in full, and terminate, the Predecessor Credit Facility promptly following this offering, and enter into the Credit Facility, which will result in a reduction in the amount of our outstanding indebtedness and a change in our borrowing costs relative to those of our predecessor. See “Pro Forma Liquidity and Capital Resources—Pro Forma Debt Instruments—EagleRock Credit Facility” for more information.

Long Term Incentive Plan

In order to incentivize individuals providing services to us or our affiliates, we expect that our board of directors will adopt an LTIP, which will become effective upon the consummation of this offering, for employees and directors. Any individual who is our officer or employee or an officer or employee of any of our affiliates, and any other person who provides services to us or our affiliates, including our directors, may be eligible to receive awards under the LTIP at the discretion of our board of directors or a committee thereof, as applicable. We anticipate that the LTIP will provide for the grant, from time to time, at the discretion of our board of directors, or a committee thereof, of options, share appreciation rights, restricted shares, restricted share units, share awards, dividend equivalents, other share-based awards, cash awards, substitute awards and performance awards intended to align the interests of employees, directors and service providers with those of our shareholders. As such, our historical financial data may not present an accurate indication of what our actual results would have been if we had implemented the LTIP program prior to the periods presented within this prospectus. For more information about our LTIP, see “Executive Compensation—Additional Narrative Disclosure Regarding Executive Compensation Matters.”

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Income Taxes

Prior to this offering, we and our subsidiaries were primarily entities that were treated as partnerships for federal income tax purposes but were subject to certain minimal Texas franchise taxes.

As a result of our predominantly non-taxable structure historically, income taxes on taxable income or losses realized by the predecessor were generally the obligation of the individual members or of our predecessor. Accordingly, the financial data attributable to the predecessor contains no provision for U.S. federal income taxes or income taxes in any state or locality (other than margin tax in the State of Texas). Although we are a limited liability company, we have elected to be taxed as a corporation and will be subject to U.S. federal income taxes. We estimate that we will be subject to U.S. federal income taxes at a blended statutory rate of 26.25% of pre-tax earnings and would have incurred pro forma income tax expense of $0.1 million for the year ended December 31, 2025.

Pro Forma Liquidity and Capital Resources

Overview

We intend to contribute all of the net proceeds from this offering to OpCo in exchange for newly issued OpCo Units. OpCo intends to use the net proceeds from this offering to repay in full, and terminate, the Predecessor Credit Facility and for general corporate purposes. Following the completion of this offering, we expect our liquidity needs to be met primarily through cash flows from operations and borrowings under the Credit Facility. Our key liquidity requirements are expected to include cost of sales and general and administrative expenses. We currently believe that cash on hand following this offering, together with cash flows from operations, will be sufficient to fund such items as well as our capital expenditures, working capital and other capital requirements over both the short and long term. While we expect to rely on these sources to support our operations, we may also utilize borrowings under the Credit Facility (subject to the restrictions set forth therein) to fund certain operating or investing activities.

We aim to preserve financial flexibility and regularly evaluate potential capital sources, including equity and debt financing, to support our liquidity objectives and capital needs over the longer term. Adverse changes in market conditions, such as a material decline in revenues or an increase in operating costs, could reduce our cash flows and liquidity and may require us to pursue additional financing alternatives.

Pro Forma Capital Requirements

We believe that maximizing the efficient utilization and cash flow generation of our assets is critical to create long-term value for our shareholders. Under our long-term commercial agreements, the cost of developing our land and operating the assets we own interests in is primarily borne by our customers and our operating partners, allowing us to deploy little to no capital of our own while benefitting from the increasing use of our land, assets and resources to create Free Cash Flow. Over time, subject to market conditions, board approval and other factors, we intend to prioritize returning capital to shareholders through dividends and/or opportunistic share repurchases while maintaining capacity to pursue high-return growth opportunities. We intend to maintain a prudent financial profile to preserve strategic flexibility. Our asset-light model allows us to support customer activity without large upfront capital requirements. Our strategy will continue to focus on growing our land footprint, a non-depreciable asset, with significant economic cash flow generation for multiple years. We believe maintaining balance sheet discipline positions us to act opportunistically in a basin where surface access, water logistics rights and right-of-way control are increasingly valuable to operators. As a

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landowner, we incur the initial capital investment cost to acquire our acreage, but thereafter we incur modest development capital expenditures and operating expenses as they relate to operations on our land or our sale of our resources, as such expenses are transferred to or borne primarily by our customers and operating partners. As a result, our capital investment strategy will focus on the acquisition of additional surface acreage that is complementary to our business.

The level and allocation of our future acquisition-related capital investments will depend on various factors, including the size and timing of potential acquisition opportunities, cash flows from operating activities and our investing and financing decisions.

While we believe that our cash on hand, together with cash flows from operating activities and borrowings under the Credit Facility, will be sufficient to support the execution of our current strategy, our ability to generate cash is influenced by numerous factors, many of which are outside our control, including commodity prices and broader economic, financial, competitive, legislative and regulatory conditions. If additional capital is needed for acquisitions or other purposes, we may seek to obtain it through other borrowings, the issuance of debt or equity securities or other financing alternatives. Should we be unable to secure financing when required or on acceptable terms, we may be limited in our ability to pursue attractive acquisition opportunities.

If and when our board of directors declares cash dividends to our shareholders, we currently anticipate funding any such dividends with Free Cash Flow. We do not expect to borrow funds or alter our planned capital reinvestment to finance dividends on our shares. The timing, amount and method of financing any dividends will be determined at the discretion of our board of directors following this offering. See “Dividend Policy.”

Pro Forma Debt Instruments

EagleRock Credit Facility

We plan to use a portion of the proceeds from this offering to repay all borrowings outstanding under, and terminate, the Predecessor Credit Facility.

In connection with the closing of this offering we expect that OpCo and certain of our other subsidiaries will enter into the Credit Facility providing a $200.0 million revolving credit facility which will mature in June of 2031. The Credit Facility is administered by JPMorgan Chase Bank, N.A., as administrative agent. The Credit Facility is secured by a first-priority lien on substantially all of the assets of OpCo and the Guarantors, including equity interests in OpCo’s subsidiaries, subject to customary exceptions and exclusions, and is guaranteed by all material existing and future direct and indirect wholly owned domestic subsidiaries of OpCo. The Credit Facility includes an accordion feature providing for up to $100.0 million of additional commitments, a letter of credit sublimit of $10.0 million and customary conditions to borrowing.

Outstanding borrowings under the Credit Facility accrue interest at a rate based on the secured overnight financing rate (“SOFR”), plus an applicable margin. Borrowings under the Credit Facility accrue interest based on a four-tiered pricing grid tied to OpCo’s net total leverage ratio as follows:

•

if the net total leverage ratio is greater than or equal to 3.00x, the applicable margin will be 3.00% and the commitment fee on undrawn amounts will be 0.50%;

•

if the net total leverage ratio is less than 3.00x but greater than or equal to 2.50x, the applicable margin will be 2.75% and the commitment fee on undrawn amounts will be 0.50%;

•

if the net total leverage ratio is less than 2.50x but greater than or equal to 2.00x, the applicable margin will be 2.50% and the commitment fee on undrawn amounts will be 0.375%; and

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•

if the net total leverage ratio is less than 2.00x, the applicable margin will be 2.25% and the commitment fee on undrawn amounts will be 0.375%.

Subject to certain exceptions and materiality qualifiers, the Credit Facility includes certain customary affirmative and negative covenants, which, among other things, restricts the ability of OpCo and its restricted subsidiaries, subject to certain exceptions, to incur debt, grant liens, make restricted payments and investments, issue equity, sell or lease assets, dissolve or merge with another entity, enter into transactions with affiliates or restrictive agreements, change their business, prepay debt and amend their organizational documents and material agreements. It will also include a customary holding company covenant applicable to us.

The Credit Facility allows OpCo and its restricted subsidiaries to make restricted payments, including cash dividends to us that we could pay to our shareholders, so long as (i) no default or event of default exists or would result therefrom, (ii) the pro forma net total leverage ratio is less than 3.00x and (iii) pro forma liquidity (defined as cash plus availability under the Credit Facility) is equal to or greater than $50.0 million.

In addition, OpCo is required to comply with the following financial maintenance covenants: (i) a maximum net total leverage ratio of no greater than 3.50x (with maximum cash netting of up to $25.0 million if any loans are outstanding; if no loans are outstanding, all unrestricted cash and cash equivalents on the balance sheet of OpCo and its restricted subsidiaries and with a step up to 4.00x for a certain period after a material permitted acquisition); and (ii) a minimum interest coverage ratio of at least 2.75x.

The Credit Facility contains customary events of default, including for the failure of OpCo and the other loan parties to comply with the various financial, negative and affirmative covenants under the Credit Facility (subject to the cure provisions set forth therein). During the existence of an event of default (as defined under the Credit Facility), the administrative agent, with the consent of or at the direction of the required lenders thereunder, has a right to, among other available remedies, terminate the commitments and/or declare all outstanding loans and accrued interest and fees under the Credit Facility to be immediately due and payable.

Predecessor Results of Operations

Factors Affecting the Comparability of Our Results of Operations

Acquisitions

In April 2024, we consummated the acquisition of 100% of the equity interests of Desert Ram South Ranch, Inc. (f/k/a NGL South Ranch, Inc.) and Desert Ram North Ranch, LLC (f/k/a NGL North Ranch, LLC) (such acquisition, the “Desert Ram Acquisition”). We acquired approximately 122,000 acres (of which 14,000 acres consist of fee acreage, while the remaining are leased acres from the State of New Mexico and the BLM) in Lea County and Eddy County, New Mexico.

In April 2025, we consummated the Accelerated Acquisition. Through its subsidiaries, Accelerated owns certain parcels of land or surface acreage with an aggregate of approximately 72,000 acres (of which 23,000 acres consist of fee acreage while the remaining are leased acres from the State of New Mexico and the BLM) in Lea County, New Mexico.

Substantially all of the predecessor’s results of operations were generated from its activities in New Mexico.

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


	Predecessor
	For the Year Ended December 31,						Variance
	2024			2025			Amount			Percent
	(in thousands, except for percentages)
Revenues
Water sales	$	12,346		$	55,708		$	43,362			351.2	%
Surface and other revenues		5,355			16,465			11,110			207.5	%

Total revenues	$	17,701		$	72,173		$	54,472			307.7	%
Cost of sales (exclusive of depreciation and amortization)	$	8,311		$	31,070		$	22,759			273.8	%
General and administrative expense		2,798			10,069			7,271			259.9	%
Depreciation and amortization expense		3,944			14,984			11,040			279.9	%
Gain on sale of property, plants and equipment, net		(4,954	)		(2,067	)		2,887			(58.3	)%

Total operating expenses	$	10,099		$	54,056		$	43,957			435.3	%

Operating Income (Loss)	$	7,602		$	18,117		$	10,515			138.3	%

Interest expense—related party		(8,703	)		(21,185	)		(12,482	)		143.4	%
Loss on extinguishment of debt		—			(70,001	)		(70,001	)		nm

Income from operations before taxes	$	(1,101	)	$	(73,069	)	$	(71,968	)		6,536.6	%

Income tax expense (benefit)		(26	)	$	2		$	28			(107.7	)%

Net income (loss)	$	(1,075	)	$	(73,071	)	$	(71,996	)		6,697.3	%

nm - not meaningful

Water Sales. Water sales increased by $43.4 million in the year ended December 31, 2025, as compared to the year ended December 31, 2024, consisting of a $19.9 million increase in recycled water sales, $16.8 million of incremental revenue from the Accelerated Acquisition, a $2.7 million increase in brackish water sales (excluding the impact of the Accelerated Acquisition) and an additional $4.0 million of water transfer and logistics revenue charged to customers for the delivery of water to locations different from the point of sale. The increase in water sales was largely driven by an increase in total water volume sold, incremental revenue associated with the Accelerated Acquisition and a full year of revenue activity related to our Desert Ram Acquisition. Total water sold increased by over 250% to approximately 73 MMBbls for year ended December 31, 2025, as compared to the year ended December 31, 2024, which was driven primarily by the sale of 100% of our commercial water allotment, an over 300% increase in recycled water barrels sold to our customers and additional brackish water volume sourced off-ranch from third-party brackish water suppliers.

Surface and Other Revenues. Surface and other revenues increased by $11.1 million in the year ended December 31, 2025, as compared to the year ended December 31, 2024, largely driven by $6.4 million of incremental revenue from the Accelerated Acquisition, which includes $3.2 million of incremental land use revenue relating to access road and easement use and damages easement from customer activities and $1.8 million of surface use royalties from salt-water disposal wells on the Accelerated ranches. Surface and other revenues increase was also driven by a $1.8 million increase in land use revenue, a $1.8 million increase in caliche sales and a $1.0 million increase in surface use royalties, each excluding the impact of the Accelerated Acquisition. These changes were largely attributable to increased customer activity levels on our land and a full year of revenue from the Desert Ram Acquisition.

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Cost of Sales. Cost of sales (exclusive of depreciation and amortization) increased by $22.8 million in the year ended December 31, 2025, as compared to the year ended December 31, 2024, consisting of a $9.4 million increase in the cost of water purchased and treated driven by higher volumes of recycled water and brackish water sourced from third-party suppliers, a $6.1 million increase attributable to the Accelerated Acquisition, a $2.9 million increase of third-party logistics costs incurred for water transfer and logistics to our customers, and $2.6 million increase in equipment costs and employee labor in connection with water handling and logistics. The increase in cost of sales was primarily due to higher customer activity levels on our land resulting from increased demand for our resources and increased cost levels following the expanded growth in our surface acreage and operations from the Accelerated Acquisition during the year 2025.

General and Administrative Expense. General and administrative expenses increased by $7.3 million in the year ended December 31, 2025, as compared to the year ended December 31, 2024, consisting of a $3.7 million increase in professional fees and a $3.6 million increase in employee-related costs and other general and administrative expenses. The increase in professional and transaction expenses was primarily related to costs incurred in connection with our initial public offering, the Accelerated Acquisition and the Desert Ram Acquisition. The increase in employee-related costs and other general and administrative expenses was related to growth of our company following the Accelerated Acquisition in 2025. Our headcount increased by approximately 12 employees as part of the Accelerated Acquisition.

Depreciation and Amortization Expense. Depreciation and amortization expense increased by $11.0 million in the year ended December 31, 2025, as compared to the year ended December 31, 2024, consisting of a $9.0 million increase attributable to assets acquired in the Accelerated Acquisition, a $2.0 million increase driven by a full year of expense from the Desert Ram Acquisition and additional fixed asset purchases during the period. We incurred additional capital expenditures to expand our water storage facilities to support the maintenance of certain water storage facilities and caliche pits.

Interest Expense. Interest expense increased by $12.5 million in the year ended December 31, 2025, as compared to the year ended December 31, 2024. The increase was primarily attributable to debt activity associated with the Desert Ram Acquisition and the Accelerated Acquisition. In 2024, we funded the Desert Ram Acquisition with a $72.0 million term loan and in 2025, we upsized our debt by $204.0 million to fund the Accelerated Acquisition. See “—Predecessor Liquidity and Capital Resources” for additional information regarding our debt instruments and interest expense.

Loss on Extinguishment of Debt. There was no loss on extinguishment of debt during the year ended December 31, 2024. The loss on extinguishment of debt for the year ended December 31, 2025 relates to the upsize of our Predecessor Credit Facility in connection with the Accelerated Acquisition.

Predecessor Liquidity and Capital Resources

Overview

Historically, our principal sources of liquidity have included borrowings under the Predecessor Credit Facility as well as capital contributions from our various equity owners. Our predecessor was formed on December 7, 2023, and has made two major acquisitions, the Desert Ram Acquisition and the Accelerated Acquisition. Our predecessor funded these acquisitions with borrowings under the Predecessor Credit Facility. See “—Predecessor Credit Facility.” Other than the Desert Ram Acquisition and the Accelerated Acquisition, our predecessor’s business required a minimal amount of capital expenditures and was able to support operations with cash on hand.

As of December 31, 2025, our predecessor’s working capital, calculated as current assets minus current liabilities, was $14.1 million, and we had cash and cash equivalents of $9.0 million.

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Predecessor Cash Flows

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

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


	Predecessor
	For the Year Ended December 31,						Variance
	2024			2025			Amount			Percent
	(in thousands, except for percentages)
Consolidated Statement of Cash Flow Data
Net cash provided by (used in) operating activities	$	907		$	14,138		$	13,231			1,458.8	%
Net cash provided by (used in) investing activities		(64,556	)		(204,963	)		(140,407	)		217.5	%
Net cash provided by (used in) financing activities		64,711			199,090			134,379			207.7	%

Net increase (decrease) in cash and cash equivalents	$	1,062		$	8,265		$	7,203			678.2	%

Net Cash Provided by Operating Activities. Net cash provided by operating activities increased by $13.2 million to $14.1 million for the year ended December 31, 2025, as compared to $0.9 million for the year ended December 31, 2024. The increase was primarily attributable to a net change in accounts receivable of $16.4 million as a result of increased activity levels and growth in our business following the Accelerated Acquisition. This increase was partially offset by a net decrease of $1.1 million in net income, net of non-cash items, and a $1.4 million decrease in cash flows from working capital accounts for the year ended December 31, 2025, compared to the year ended December 31, 2024.

Net Cash Used in Investing Activities. Net cash used in investing activities increased by $140.4 million to $205.0 million for the year ended December 31, 2025, as compared to $64.6 million for the year ended December 31, 2024. Cash used for acquisitions during the year ended December 31, 2024 was approximately $68.4 million, related to the Desert Ram Acquisition, compared to $191.7 million in the year ended December 31, 2025, related to the Accelerated Acquisition and an $8.0 million deposit made in connection with a prospective acquisition of surface acreage, grazing leases and related water rights. Capital expenditure increased from approximately $1.2 million in the year ended December 31, 2024 to $5.3 million in the year ended December 31, 2025. Capital expenditures in the year ended December 31, 2025 included the installation of water storage ponds as well as maintenance of certain assets acquired in the Accelerated Acquisition. The net change in proceeds from the sale of property, plant and equipment is driven by a $5.0 million divestiture of certain parcels of land during the year ended December 31, 2024.

Net Cash Provided by Financing Activities. Net cash provided by financing activities increased by $134.4 million to $199.1 million for the year ended December 31, 2025, as compared to $64.7 million for the year ended December 31, 2024. The increase in net cash from financing activities was driven by increased borrowings under our Predecessor Credit Facility. We borrowed $72.0 million during the year ended December 31, 2024 to fund the Desert Ram Acquisition, and upsized our debt by an additional $204.0 million during the year ended December 31, 2025 to fund the Accelerated Acquisition. Proceeds from the Predecessor Revolver (as defined below) also increased from $3.9 million during the year ended December 31, 2024 to $11.8 million during the year ended December 31, 2025, primarily driven by our working capital needs and deposits for strategic acquisitions. Our cash proceeds from borrowings were partially offset by higher debt issuance costs of approximately $6.6 million during the year ended December 31, 2025, compared to $3.5 million during the year ended December 31, 2024, as well as $23.8 million of debt repayments during the year ended

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December 31, 2025, compared to $7.7 million during the year ended December 31, 2024. Additionally, during the year ended December 31, 2025, our predecessor received approximately $14.0 million in proceeds from the issuance of common units.

Predecessor Capital Requirements

During the years ended December 31, 2024 and 2025, our predecessor invested approximately $68.4 million and $191.7 million, net of cash acquired, in connection with the Desert Ram Acquisition and Accelerated Acquisition, respectively. During the years ended December 31, 2024 and 2025, our predecessor incurred approximately $1.2 million and $5.3 million in capital expenditures for corporate office furniture and equipment as well as for installing and maintaining the modest assets we own on our land.

Predecessor Credit Facility

On April 4, 2024, certain subsidiaries of our predecessor entered into a 5-year financing agreement that included a $72.0 million term loan and a revolving credit facility (as amended, the “Predecessor Revolver”) with a maximum borrowing base of $5.0 million, both of which mature on April 4, 2029 (as amended, the “Predecessor Credit Facility”). Upon entering into the Predecessor Credit Facility, we borrowed $72.0 million under the Predecessor Credit Facility and $3.9 million under the Predecessor Revolver. Net proceeds from these borrowings were used to pay the purchase price in the Desert Ram Acquisition and support our working capital needs. On February 28, 2025, we amended the Predecessor Credit Facility to increase maximum borrowing base by $7.5 million. On April 14, 2025, in order to fund a portion of the purchase price of the Accelerated Acquisition, we further amended the Predecessor Credit Facility, to increase the maximum Term Loan borrowing base by an additional $204.0 million term. The Predecessor Credit Facility is secured by a first priority lien and security interest in all assets of the predecessor.

The Predecessor Credit Facility includes certain affirmative and restrictive covenants common in such agreements. See “Note 6—Long Term Debt—Related Party” within the notes to our predecessor’s consolidated financial statements and included elsewhere in this prospectus for further information with respect to such affirmative and restrictive covenants.

The Predecessor Credit Facility is fully and unconditionally guaranteed by the predecessor. Borrowings under the Predecessor Credit Facility bear interest at the secured overnight financing rate (“SOFR”), plus the applicable margin or certain reference rate, plus the applicable margin, which is set at 8.0%—8.5% depending on the applicable leverage ratio for the most recent four consecutive quarters. Principal amounts borrowed under the Predecessor Revolver may be repaid from time to time without penalty. Any principal amounts outstanding on the maturity date, July 3, 2027, become due and payable on such date. Borrowings under the Predecessor Credit Facility are secured by a first priority lien and security interest in all assets of the predecessor.

As of December 31, 2025, we had $265.6 million of total outstanding borrowings consisting of $7.0 million of revolving credit borrowings and $258.6 million of term loan borrowings and excluding $35.1 million of unamortized premium. The weighted average interest rate on the total amount of borrowings outstanding under the Predecessor Credit Facility as of December 31, 2025 was 12.83% in the case of revolving credit borrowings, and 12.81% in the case of term loan borrowings. We are currently in compliance with all affirmative and negative covenants under the facility.

L&E Warrants

In connection with its entry into the Predecessor Credit Facility, the predecessor issued the L&E Warrants, which are exercisable for equity interests in our predecessor, to the TCW Entities. In connection with the amendment to the Predecessor Credit Facility in April 2025 referenced above, the

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predecessor issued L&E Warrants to a new creditor and modified the terms of the original L&E Warrants. The net effect of the issuance and modification reduced the total number of L&E Warrants outstanding from 1,001 to 900. See “Note 6—Long Term Debt—Related Party” within the notes to our predecessor’s consolidated financial statements and included elsewhere in this prospectus for further information with respect to the warrants. The L&E Warrants are obligations of our predecessor and are not obligations of EagleRock or OpCo. As described in “Corporate Reorganization,” in connection with this offering, each TCW Entity will, pursuant to a Warrant Exercise Agreement, exercise a portion of its L&E Warrants and forfeit the remaining portion, which will be irrevocably cancelled, immediately following which (i) L&E will distribute 14,940,269 OpCo Units and a corresponding number of Class B shares to the TCW Entities in redemption of the L&E units received in respect of the Exercised Warrants, (ii) each Warrant Agreement will terminate and (iii) each of the Rollover TCW Entities will merge with one or more newly formed subsidiaries of EagleRock and receive one Class A share in exchange for each OpCo Unit (and Class B share) it holds, or an aggregate 4,560,785 Class A shares. As a result, the L&E Warrants will no longer be outstanding following this offering, and investors in this offering will not experience dilution from any future exercise of the L&E Warrants.

Quantitative and Qualitative Disclosure about Market Risk

We are exposed to market risks, which include the effects of adverse changes in commodity prices and counter-party and customer credit risks and interest rate 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 commodity prices and counter-party and customer credit and interest rate 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

A significant portion of our market risk is tied to the prices our customers receive for oil and natural gas produced from or serviced on our land. The market for the use of our land and its resources is indirectly affected by fluctuations in commodity prices, to the extent that such fluctuations influence drilling, completion and production activity, and consequently, the operational levels of our customers in the exploration, production and oilfield services sectors. Realized prices are primarily determined by prevailing oil and natural gas prices in the United States. However, we believe that our largely fee-based and surface use contracts, as well as our strong base of royalty fees support cash flow stability through commodity price cycles. Our commercial agreements are usually multi-year agreements that may contain acreage dedications and annual minimum revenue amounts, insulating us against fluctuations in commodity prices. Additionally, many of our SUAs stipulate that customers who have access to our land are required to use our resources, such as water or caliche, for their operations, further insulating us from fluctuations in commodity prices.

As of December 31, 2025, the Henry Hub spot price of natural gas was $3.35 per MMBtu and the WTI posted price was $57.95 per barrel. Declines in commodity prices can reduce our revenues because they may reduce customer activity levels by limiting the volumes of oil and natural gas that our customers can economically produce or service. We expect these markets to remain volatile, and a substantial or prolonged decline in commodity prices could materially adversely affect our results of operations, cash flows and financial condition.

We do not currently hedge our indirect exposure to commodity price risk. In the future, however, we may enter into derivative instruments, such as collars, swaps and basis swaps, to partially mitigate the impact of commodity price volatility. These hedging arrangements could help reduce, but would not eliminate, the potential effects of fluctuations in oil and natural gas prices on our operating cash flows.

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Market Risk

Demand for the use of our land and resources is largely driven by activity levels in the energy industry within the Permian Basin. These activity levels are influenced by numerous factors outside of our control, including the supply of and demand for oil and natural gas; current prices and expectations for future prices; costs associated with exploring, developing, producing and delivering oil and natural gas; rates of decline in existing production; the discovery of new reserves; available pipeline, rail and other transportation capacity; weather conditions; domestic and global economic conditions; political instability both in the U.S. and in oil-producing regions; environmental regulations; technological advances affecting energy consumption; the ongoing transition to a low-carbon economy; the price and availability of alternative fuels; advancements in alternative energy production; the ability of energy companies to secure equity or debt financing; and consolidation, merger and divestiture activity within the energy sector. U.S. energy production, including oil and natural gas development, has historically been volatile.

A prolonged or significant decline in oil and natural gas prices could reduce development and production activity, which in turn may decrease demand for oil and natural gas and the use of our land and resources. Any material reduction in commodity prices or Permian Basin activity could have an adverse impact on our results of operations, cash flows and financial condition.

Counter Party and Customer Credit Risk

We are exposed to the risk of financial loss if our counterparties, including our operating partners or customers, fail to fulfill their contractual obligations. Our primary credit risk arises from receivables generated by the activities of our customers and operating partners on our land. The inability or failure of significant customers or our operating partners to meet their obligations, or their insolvency or liquidation, could adversely impact our financial results.

To manage this risk, we assess the creditworthiness of each counterparty and customer and continuously monitor our exposure through credit analysis and monitoring procedures, including reviewing credit ratings, financial statements and payment history. For the year ended December 31, 2025, three customers accounted for 22%, 15% and 11% of our total revenues, respectively. For the year ended December 31, 2024, four customers represented 28%, 14%, 13% and 12% of total revenues, respectively. No other customer accounted for more than 10% of total revenues. Based on these assessments, we believe the credit risk associated with our counterparties and customers is within an acceptable range.

Interest Rate Risk

Our ability to borrow, as well as the interest rates available to us, may be adversely affected by deterioration in the credit markets or a decline in our credit profile or credit rating. Under the Credit Facility, any outstanding borrowings accrue interest based on the SOFR, plus an applicable margin, which exposes us to interest rate risk on any outstanding borrowings.

As of December 31, 2025, our predecessor had $265.6 million of total outstanding borrowings, consisting of $7.0 million in revolving credit borrowings and $258.6 million in term loan borrowings and excluding $35.1 million of unamortized premium. The weighted average interest rate on these borrowings was 12.83% for the revolving credit borrowings and 12.81% for the term loan borrowings. Assuming no change in the principal amount outstanding, a 1% increase or decrease in the weighted average interest rate would impact interest expense by approximately $2.7 million annually. We do not currently have, and do not plan to enter into, any derivative instruments to hedge against fluctuations in interest rates applicable to our outstanding debt. See “—Predecessor Credit Facility.”

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Critical Accounting Estimates

The preparation of our financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. We consider certain accounting estimates to be critical because they involve significant judgment and have the potential to materially impact our financial results if the underlying assumptions change. For additional information, see “Note 2—Summary of Significant Accounting Policies” within the notes to our predecessor’s consolidated financial statement and included elsewhere in this prospectus for further information with respect to our accounting policies.

Business Combinations

We account for business combinations using the acquisition method of accounting, whereby the identifiable assets and liabilities of the acquired business, including contingent consideration, as well as any non-controlling interest in the acquired business, are recorded at their estimated fair values as of the date that we obtain control of the acquired business. Any purchase consideration in excess of the estimated fair values of the net assets acquired is recorded as goodwill. Significant estimates may be used to determine the fair value of assets acquired and liabilities assumed. Critical estimates in valuing intangible assets include, but are not limited to, expected future cash flows and discount rates. Fair value estimates are based on the assumptions management believes a market participant would use in pricing the asset or liability. Amounts recorded in a business combination may change during the measurement period, which is a period not to exceed one year from the date of acquisitions, as additional information about conditions existing at the acquisition date becomes available.

Warrants

The Company accounts for the warrants as either equity-classified or liability-classified instruments based on an assessment of the warrant’s specific terms and applicable authoritative guidance in ASC 480, Distinguishing Liabilities from Equity (“ASC 480”) and ASC 815. The assessment considers whether the warrants are freestanding financial instruments pursuant to ASC 480, meet the definition of a liability pursuant to ASC 480, and whether the warrants meet all the requirements for equity classification under ASC 815, including whether the warrants are indexed to the Company’s own shares, among other conditions for equity classification. This assessment, which requires the use of professional judgment, is conducted at the time of warrant issuance and as of each subsequent quarterly period end date while the warrants are outstanding. For issued or modified warrants that meet all of the criteria for equity classification, the warrants are required to be recorded as a component of additional paid-in capital at the time of issuance. For issued or modified warrants that do not meet all the criteria for equity classification, the warrants are required to be recorded at their initial fair value on the date of issuance, and each balance sheet date thereafter. The determination of the fair value of the warrants at issuance and each reporting period is performed using a third-party valuation specialist and is subject to a variety of estimates.

Impairment of Long-lived assets

Management evaluates property, plant and equipment and definite-lived intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset group may not be recoverable. Asset groups are identified at the lowest level for which cash flows are largely independent. The recoverability assessment compares the carrying amount of the asset group to the expected undiscounted future cash flows. If the carrying amount is not recoverable, we measure the impairment loss as the excess of the carrying amount over the asset group’s estimated fair value.

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Recently Issued Accounting Pronouncements

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280). This guidance requires a public entity, including entities with a single reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis and provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. This ASU was effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The adoption of this update did not have a material impact on our financial statements.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740). This guidance further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. This ASU is effective for annual periods beginning after December 15, 2024, with early adoption permitted. We have adopted this guidance and the adoption did not have a material impact on its consolidated financial statements or related disclosures.

In November 2024, the FASB issued Accounting Standards Update No. 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses” (“ASU 2024-03”). The guidance in ASU 2024-03 requires public business entities to disclose in the notes to the financial statements, among other things, specific information about certain costs and expenses including purchases of inventory; employee compensation; and depreciation, amortization and depletion expenses for each caption on the income statement where such expenses are included. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted, and the amendments may be applied prospectively to reporting periods after the effective date or retrospectively to all periods presented in the financial statements. We are currently evaluating the potential impact of adopting this new guidance on our consolidated financial statements and related disclosures.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act 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 reporting issuer, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, 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 make our first assessment of the effectiveness of our internal control over financial reporting under Section 404 until our second annual report on Form 10-K after we become a public company.

Further, our independent registered public accounting firm is not required to attest to the effectiveness of our internal controls over financial reporting and will not be required to do so for as long as we are an “emerging growth company” and/or a “smaller reporting company” under applicable federal securities laws. Please see “Summary—Emerging Growth Company and Smaller Reporting Company Status” for more information.

Off Balance Sheet Arrangements

We currently have no material off-balance sheet arrangements.

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BUSINESS

Our Company

Access to land, resources and infrastructure is fundamental for critical industries like energy and technology to thrive. We are a land management company that owns or controls approximately 236,000 acres in the heart of the Delaware and Midland sub-basins within the prolific Permian Basin. In addition, we have an interest in up to approximately 70,000 acres pursuant to an acreage dedication related to our Midland Basin water infrastructure assets. Our acreage is vital to the efficient development of oil and natural gas resources in the Permian Basin and is strategically located to support the growing surface, resource, infrastructure and related commercial development needs of the power and other emerging industries in the Permian Basin.

Our assets are uniquely tailored to meet the needs of our customers in the distinct regulatory and operational environments in each sub-basin of the Permian Basin. Our Delaware Basin acreage sits in productive development corridors in the Permian Basin and supports water supply for drilling activity and produced water offtake, handling and recycling services to support the emerging beneficial reuse markets, generating activity-based revenue streams and royalties tied to recycled water. This position also provides abundant pore space capacity for AGI, helping our customers mitigate the potential impact of local sour gas refining constraints and reducing flaring required by operators. In the Midland Basin, where geologic conditions are more favorable and regulatory conditions are more consistent for subsurface produced water disposal, we have valuable pore space capacity for produced water disposal in areas not affected by seismicity and over-pressurization concerns. Our acreage may also support future CO₂ pipeline development in conjunction with our pore space, which is well suited for large scale CCUS. Our Midland Basin assets also include one of the largest produced water handling and disposal systems in the Permian Basin that, under a long-term agreement with DEF Operating, an affiliate of Double Eagle, one of our operating partners, underpins our ability to monetize produced water handling, disposal, recycling and beneficial reuse activities across our footprint.

We seek to create value for our shareholders by growing and diversifying our revenue streams through a proven strategy of organic growth and accretive land acquisitions that complement our strategy, strengthen our competitive advantages and provide opportunities for our experienced management team to drive incremental organic growth. Our proactive land management strategy has driven organic growth by supporting the full life cycle of oil and gas operations, including drilling, completion, production, offtake, treatment, processing and handling and responsible waste management and disposal activities, to enhance efficient oil and gas development with minimal operating costs or capital expenditures by us. We intend to apply this same proactive approach to attract development by emerging industries on our land. We also seek to grow organically through the expansion of existing infrastructure and operations carried out on our acreage, as well as through the identification and exploitation of new and novel uses of our land to attract new customers and strategic

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partners. In turn, existing and additional development on our land augments our ability to attract further incremental activities and uses, as new customers are able to utilize existing infrastructure.

Our land holdings benefit from a number of strategic contractual arrangements that provide durable revenue streams and consistent demand from our customers. These agreements are characterized by long tenors, minimum payment obligations, minimum use commitments, inflation-linked fee escalators and exclusivity provisions. For example, we are party to SUAs with a number of customers that have operations on our land. Our SUAs typically include 5 to 10-year initial terms, subject to renewal, and provide us with a fee when the SUA is executed, fixed monthly or annual fees that typically escalate annually based on CPI, and often include additional fees at the beginning of each renewal period. Our SUAs also typically include pre-defined terms for additional fees that we will receive for our customers’ development and use of drilling sites, new and existing roads, pipeline easements and electric transmission easements. Many of our SUAs require our customers to use ROWs and easements on our land as well as the resources from our land, such as water and caliche, for their operations on our land, for which we receive additional fees. Production of oil and natural gas from the reservoirs underlying our land is expected to continue for many decades and, as a result, we expect these contracts to be renewed for an extended period of time. Furthermore, our SUAs typically include provisions that require our customers to remove their assets from and remediate our land if such agreements are not renewed, providing an incentive for our customers to continue to renew their existing agreements with us.

In addition, our Midland Basin assets include the DE Flow System from which we will generate royalty revenues from the activities of our operating partner, DEF Operating, under the DE Flow WSMA, which we will enter into in connection with this offering. The DE Flow WSMA will have an initial 10-year term, include a minimum annual royalty commitment, and will be supported by the DE Acreage Dedication. Our produced water infrastructure is capable of handling up to approximately 400 MBbls/d of produced water under long-term contracts, and includes produced water gathering systems, SWDs, water sourcing and delivery pipelines and recycling facilities.

In connection with this offering, we will also enter into the Hydrosource Recycling Agreement with Hydrosource, our other operating partner, pursuant to which we will receive a royalty for, among other things, each barrel of produced water Hydrosource treats and recycles for oil and gas customers on our land and within certain designated areas outside of our land. Under the Hydrosource Recycling Agreement, Hydrosource will provide treated, blended and recycled water to customers across certain parts of our acreage. The Hydrosource Recycling Agreement will have a 10-year term with a five-year minimum royalty commitment. The Company and Hydrosource have access to supplemental off-ranch water, and the Company’s surface pipeline has the capacity to move approximately 100 MBbls/d, or approximately 36.5 MMBbls per year, of off-ranch water from Texas to its land in New Mexico. Additionally, Hydrosource is party to the Hydrosource Recycled Water Supply Agreement, as well as other water infrastructure on our land.

•

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obtained from commercial water wells or recycling of produced water, as well as caliche for the construction of drilling pads, roads and production batteries. Under many of our SUAs, our customers are required to purchase from us or our operating partners the resources used in their operations at negotiated fees. We source water to fulfill our customers’ needs from commercial water wells on our fee lands, our operating partners and other third-party sources. Our commercial water wells in New Mexico, water infrastructure in Texas and off-ranch water from third party sources allow us to produce and sell in excess of 200 MMBbls of water per year. We sell caliche from 29 caliche mines on our land.

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EagleRock Land Revenue

LOGO


	Predecessor						Pro Forma, As Adjusted
	Year Ended December 31,						Year Ended December 31,
	2024			2025			2025
	($ in thousands)
Total revenues	$	17,701		$	72,173		$	141,438
Net (loss) income	$	(1,075	)	$	(73,071	)	$	2,409
Adjusted EBITDA⁽¹⁾	$	7,350		$	35,533		$	118,581
Cash flows from operating activities	$	907		$	14,138
Capital expenditures⁽²⁾	$	(1,482	)	$	(5,252	)
Free Cash Flow⁽¹⁾	$	5,868		$	30,281
Acreage at end of period		122,132			193,875			306,136

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(1)

Adjusted EBITDA and Free Cash Flow are non-GAAP financial measures. See “Summary—Summary Consolidated Financial and Other Data” and “Summary—Non-GAAP Financial Measures” for more information regarding these non-GAAP measures and reconciliations to the most comparable measures calculated and presented in accordance with GAAP.

(2)	Capital expenditures include costs incurred, inclusive of changes in accounts payable related to capital expenditures, for corporate office furniture and office equipment and costs incurred to install and maintain modest ancillary assets, such as ponds and pits, we own on our land.

Our Proactive Management Strategy

Surface Access to Land and its Resources is Critical to Efficiently Develop Energy Assets

Our land is situated in the prolific Permian Basin, which includes both the Delaware and Midland Basins and is regarded as the premier region for oil and gas development, primarily due to its vast

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remaining hydrocarbon resources and low break-even costs. Our land sits atop some of the most productive areas in the Delaware and Midland Basins presenting significant oil and natural gas development potential and many decades of remaining inventory for our customers. We believe the location of our land will contribute to durable revenue streams and consistent demand from our customers. The chart below depicts the estimated remaining oil resource and basin resource life of the Delaware Basin, the Midland Basin and other notable basins, according to the U.S. Geological Survey.

Basin Resource Life Comparison

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increasingly outpaced available handling and disposal capacity, creating logistical constraints that can impact drilling and completion schedules, operating costs and development efficiency. The chart below illustrates historical and forecasted Permian Basin produced water volumes relative to basin-wide operational handling capacity, underscoring the importance of surface access, infrastructure siting and proximity to disposal and recycling solutions in supporting continued development across the Permian Basin.

Permian Basin Water Volumes by Handling Method vs. Operational Produced Water Handling Capacity

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Delaware Basin Subsurface Diagram Midland Basin Subsurface Diagram

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Source: Enverus | Note: WOR = Water to Oil Ratio. This ratio compares the amount of produced water relative to the amount of produced oil.

In addition to the large quantities of water needed during drilling and completion of a well, the production phase, which spans multiple years, requires significant produced water handling and disposal infrastructure to safely and reliably separate, transport and dispose produced water in order to maintain production continuity. The oil produced in and around our Midland Basin acreage is accompanied by significant volumes of produced water, averaging approximately 4 barrels of water per barrel of oil, or approximately 80% of total liquids produced from a typical well, according to the NMOCD. This water must be reliably handled in order for these wells to be brought online and remain in production, driving ongoing demand for water handling on acreage in close proximity to the operations of producers. We believe that our land resources and produced water infrastructure are well-situated to handle these large volumes of produced water.

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regulated at the state level and is required to meet guidelines imposed by the relevant state agencies. Because the Delaware Basin is situated across the Texas–New Mexico state border, the planning, permitting and building of produced water infrastructure is dependent upon the laws and regulations of either Texas or New Mexico. Inconsistent regulations governing produced water reinjection between Texas and New Mexico have resulted in the transmission of significant quantities of produced water from New Mexico to reinjection locations in Texas, which has led to pore space constraints and geologic issues, such as seismicity and over-pressurization, in certain areas of the Texas Delaware Basin. Meanwhile, the Midland Basin’s location entirely in Texas provides a consistent regulatory environment in addition to advantaged geologic characteristics, which results in a more evenly distributed system for reinjecting produced water across the Midland Basin. Our Midland Basin acreage is located in areas with abundant pore space, low seismicity and reduced over-pressurization concerns, and we believe that the combination of favorable geological characteristics and a consistent regulatory environment complements our existing, permitted and future produced water disposal assets.

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Our Assets

The map below shows our controlled acreage and selected assets in the Delaware Basin and Midland Basin.

EagleRock Assets

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Source: Enverus, US Department of Transportation

The table below contains information regarding our acreage and assets in each of the Delaware Basin and Midland Basin as of December 31, 2025.


	Combined Acres Owned/ Controlled			Commercial Water Rights and Supply Capacity (Bbls/y)			Current Above Ground Storage Capacity (Bbls)		Mining Sites		SWDs			Produced Water Handling Capacity (MBbls/d)
Delaware Basin		193,875			44,337,513			11,375,000		26		—			—
Midland Basin		112,261	⁽¹⁾		167,802,272	⁽²⁾		16,930,739		3		21	⁽³⁾		400

(1)	Includes up to approximately 70,000 acres in which we will have an interest pursuant to an acreage dedication related to our Midland Basin water infrastructure assets.

(2)	Consists of commercial on-ranch water supply of approximately 101,802,272 Bbls and sourced off-ranch water supply of 66,000,000 Bbls annually.

(3)	Total SWDs consist of 3 in-service off-ranch, 4 permitted off-ranch, 13 royalty-only on-ranch, and 1 permitted royalty-only on-ranch.

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We own or control approximately 236,000 total surface acres across the Permian Basin, the most active oil and natural gas development and production region in the United States. In addition, we have an interest in up to approximately 70,000 acres pursuant to an acreage dedication related to our Midland Basin water infrastructure assets. We do not own the mineral interests that underlie our surface acreage. Our surface acreage is concentrated in two sub-basins of the Permian Basin, the Delaware Basin in New Mexico and the Midland Basin in Texas. Our critical acreage mass in these prolific sub-basins affords us with broader diversification and optionality to access unique trends in each region while also providing multiple avenues to further grow our platform. Through our land position and integrated infrastructure assets, we generate revenue and royalties from completion and production-based activities, including surface damages, ROWs, easements, commercial water supply and produced water recycling, handling and disposal and other surface and subsurface related activities by leading operators on our owned and controlled acres. As of January 2026, many of the most active operators in the Delaware and Midland Basins were actively drilling or have permits to drill on our surface acreage, including Chevron Corporation, ConocoPhillips Company, Devon Energy Corporation, Diamondback Energy, Inc., Double Eagle, EOG Resources, Inc., ExxonMobil Corporation, Matador Resources Company, Occidental Petroleum Corporation and Permian Resources Corporation. We believe these and other operators have significant remaining inventory of drilling locations to drill on our surface acreage based on information from Enverus.

The table below represents current sources of revenue for our assets in the Delaware and Midland Basins.


Activity	Region	Fee / Royalty Type
Oil & Gas Drilling and Production
Produced and recycled water handling and storage*	All regions	Fixed fee, volume-based royalty
Water sales*	All regions, Off-Ranch	Per barrel fee / royalty
Salt water disposal wells	All regions	Volume-based royalty / surface fee
Sour gas treating	Delaware	Volume-based royalty / surface fee
Roads, pads and access easements	All regions	One-time + recurring fee
Caliche	All regions	Cubic yard-based royalty

Other Land Uses
Agricultural grazing leases	All regions	Lease, fixed fee, royalty
Commercial real estate leases	All regions	Lease

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The table below represents selected potential future sources of revenue for our assets in the Delaware and Midland Basins.


Potential Future Activities*	Region	Fee / Royalty Type
Oil & Gas Drilling and Production
Sand mining	All regions	Per unit royalty
Solid waste disposal	All regions	Royalty

Other Land Uses
Behind the meter power generation	All regions	Lease, royalty
Wind farm leases	All regions	Lease, royalty
Solar farm leases	All regions	Lease, royalty
Battery storage & microgrids	All regions	Lease, royalty
Data centers	All regions	Lease
Transmission lines	All regions	One-time + recurring fee
Beneficial reuse	All regions	Lease, royalty
CO₂ sequestration	All regions	Lease, royalty
Cryptocurrency mining	All regions	Lease, royalty

Delaware Basin Assets

Delaware Basin Land

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Our Delaware Basin acreage is shown below, together with EUR/ft of producing wells, according to Enverus, as of January 2026. EUR is the total amount of oil and natural gas expected to be recovered over the life of active wells. For comparability purposes, we show EUR/ft because lateral lengths vary, and wells with longer lateral lengths tend to have higher EUR/ft.

Estimated Ultimate Recovery (EUR)

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Source: Enverus

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EagleRock Share of Rigs in Lea & Eddy Counties

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Source: Enverus, EIA

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at our discretion. Under New Mexico law, the holder of an easement or right-of-way is required to compensate the lessee for the reasonable value of any measurable damage incurred upon improvements or other property belonging to the lessee. As the agricultural lessee, we have leased possession and use of the grazing interest. When the surface is excavated or occupied by a surface use implemented by a third party, we receive payments to compensate us for the impairment of value and costs to repair the physical damage. Additionally, our leasehold interests in federal lands with the BLM are generally grazing leases that grant us rights with respect to the surface for a period of approximately 10 years from inception. As part of our land management strategy, we leverage our total acreage footprint in driving our resource sales through our SUAs to our customers. Where our SUAs grant exclusive rights for commercial resources over land we control, the terms of those SUAs extend to leased land, and our customers are obligated to purchase resources such as water and caliche from us.

Delaware Basin Infrastructure

EagleRock Delaware Basin Assets

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Source: Enverus

The Delaware Basin is characterized by high water production and high WORs across formations, which results in significantly more produced water as a byproduct of production activities. Produced water originating in New Mexico generally must be transported to reinjection locations in Texas for disposal or recycled for use in drilling and completion activities. Our Hydrosource Recycling Agreement will position us to meet our customers’ demand for treated, blended and recycled water

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through Hydrosource’s water recycling infrastructure. Under the Hydrosource Recycling Agreement, we will earn a royalty for each barrel of produced water Hydrosource treats and recycles for oil and gas customers on our land. Our Delaware Basin water infrastructure assets are proximate to areas of high WORs, as depicted in the map below.

Water to Oil Ratios in the Delaware Basin

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Source: Enverus

In addition to oil and gas activity, we believe our Delaware Basin land has significant potential for future electricity transmission development, which we believe will attract new customers to our land as access to electricity increases. For instance, Oncor is in the process of developing a 765kV transmission line that is expected to traverse portions of our Delaware Basin acreage, which we anticipate will result in fees for the related easement across our land. In addition, we believe the availability of reliable power connectivity will further expand the uses of our land and allow us to attract new customers. Oncor anticipates the transmission line, if approved by regulators, will be energized by December 2028.

Additionally, the United States Department of Energy is considering designating land that crosses our acreage as the Transmission Corridor. The map below shows the Transmission Corridor’s extent in Lea and Eddy County with proximity to our Delaware Basin land. We believe any future development of the Transmission Corridor could significantly increase the value and alternative uses of our surface.

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EagleRock Delaware Basin Acreage and Transmission Corridor

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Midland Basin Assets

Midland Basin Land

Our Midland Basin land also hosts wind lease options with a potential combined 379 MW build-out, which would be supported by a base lease rate and royalty structure, with minimum projected lease revenue terms of 36 years. Additional income sources from our Midland Basin land include resource sales to customers operating within a certain mile-radius from our land and incremental royalty revenues from our infrastructure in and adjacent to our Midland Basin land that are operated by our operating partner, DEF Operating.

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Midland Basin Infrastructure

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The map below illustrates our acreage and material assets in the Midland Basin.

EagleRock Midland Basin Assets

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Source: Enverus

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Water to Oil Ratios in the Midland Basin

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Source: Enverus

The Midland Basin is also distinguished by its consistent well productivity. EUR/ft benchmarking highlights Upton and Reagan Counties as among the highest-performing areas in the Permian Basin, with well results that support extended-reach laterals, dense development spacing and multi-zone economic viability across the Spraberry and Wolfcamp formations. Our Midland Basin land is concentrated within these high-quality geologic corridors, positioning us to benefit from continued development activity and long-term inventory depth in one of the most attractive oil-weighted regions in

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North America. The graphic below depicts the EUR/ft of lateral length from oil and natural gas wells on and near our land position, according to Enverus, as of January 2026.

Estimated Ultimate Recovery (EUR)

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Source: Enverus

Our Business Model

We focus on royalty-based opportunities with minimal capital expenditure exposure, high margins and minimal operating costs and risks that generate substantial Free Cash Flow, with limited exposure to commodity price changes. Our land management strategy is to actively increase the amount of revenue-generating activities on our land through resource sales, surface and pore space leases and royalties and alternative land uses beyond oil and gas development, underpinned by SUAs with a diversified group of large, well-capitalized producers and customers. We believe our predominantly fee-based SUAs, along with long-term royalty agreements with minimum annual revenue commitments, will facilitate stable cash flows through a variety of commodity price cycles.

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Our Relationship with Our Operating Partners

Double Eagle

Double Eagle is an independent oil and natural gas company focused on development and production throughout the Permian Basin. The company is backed by equity capital commitments from EnCap, Double Eagle Management and other strategic investors. Double Eagle continues to pursue acquisitions and ambitious development programs in the Permian Basin, supported by its strategic partnership with EnCap, strong cash flows through operations, as well as available debt facilities. Additionally, Double Eagle has historically maintained consistent drilling activity through a variety of commodity price cycles, supported by its private ownership structure and flexible capital base.

Hydrosource

Our Competitive Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and achieve our business objectives.

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Balanced portfolio with strategically located assets in both the Delaware and Midland sub-basins.

Diverse revenue streams underpinned by a large percentage of fee-based royalties and surface use agreements.

Our business model is built on recurring, contracted, long-term, fee-based revenue streams with a diverse group of large, well-capitalized producers and other customers tied to surface use of our land. We generate revenue from granting ROWs, easements and rights to conduct surface use activities, sourcing and delivering water for completions, handling, transporting, recycling and disposing of produced water, AGI pore space leases and providing access to mining sites for the sale of caliche and topsoil to customers. Many of our SUAs allow us to be the exclusive provider of our resources to upstream operators on our fee land, as well as select lands we control. We will also generate revenue under our Hydrosource Recycling Agreement and DE Flow WSMA when our customers utilize our and our operating partners’ water infrastructure assets, which, in the Midland Basin, will be supported by

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long-term acreage dedications. These activities support multiple sources of revenue, which are not directly impacted by commodity price volatility and require minimal ongoing operating or maintenance expenditures from us.

Multiple potential uses of land, including power and technology, to create long-term revenue streams.

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We have an entrepreneurial management team with a track record of building businesses and creating value.

Our management team has several decades of combined experience in the energy industry, with a proven history of value creation specifically in the Permian Basin.

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consolidated fragmented SUAs with various customers while renegotiating key commercial terms that increased revenue activities on our land;

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achieved the above strategies while maintaining a strong balance sheet.

Our Business Strategies

Increase cash flow per share and generate differentiated returns for our shareholders.

Promote efficient development of our assets through both existing and novel approaches to utilize our land and resources.

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our resources both across the combined footprint and among our operating partners. We also believe revenue generation opportunities exist from ancillary surface use activities, such as sand mining, solid waste disposal and pore space leases. We believe that our ability to offer a single commercial interface for land access, water sourcing and produced water logistics is a competitive advantage that reduces downtime and cost for operators, making our acreage the preferred platform for multi-year development programs for operators. Additionally, the water recycling services offered by our operating partners on our land provide our operators with access to a commercial solution to assist them with managing increasing produced-water volumes, as well as the ability to meet their individual sustainability goals. We will also seek to further develop and grow our non-oil and gas revenue streams, which we believe include traditional and renewable power generation, transmission and storage and data center infrastructure. Our goal is to efficiently increase revenue by maximizing fee-generating activities on the same land while minimizing permitting friction for our customers.

Pursue accretive acquisitions to enhance our asset base.

Maintain a prudent balance sheet with capital flexibility.

Capitalize on our relationship with Hydrosource and DEF Operating to increase revenue.

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desalination facilities, which could potentially provide incremental surface use revenues and water sales royalties to us.

Properties

As of December 31, 2025, we owned or controlled (through OpCo and its restricted subsidiaries) approximately 236,000 surface acres across Texas and New Mexico. In addition, we have an interest in up to approximately 70,000 acres pursuant to an acreage dedication related to our Midland Basin water infrastructure assets. Substantially all of the acreage and other assets of OpCo and its restricted subsidiaries will be encumbered by first-priority mortgages (deeds of trust) and related security interests to secure the Credit Facility. Other than such mortgages and our SUA easements, there are no material liens or encumbrances on our title to the surface estate on our acreage as of December 31, 2025. Acreage figures are approximate, reflect our current mapping and records, and may be subject to adjustment based on surveys, acquisitions or dispositions. We do not own the mineral interests that underlie our surface acreage.

The following table shows by sub-basin of the Permian Basin the surface acreage in which we have an interest as of December 31, 2025:


Location	Number of Surface Acres
Delaware Basin		193,875
Midland Basin
Owned Midland Basin		42,156
Dedicated Midland Basin⁽¹⁾		70,105

Total Acres		306,136

(1)	Consists of up to 70,105 acres in which we will have an interest pursuant to an acreage dedication related to our Midland Basin water infrastructure assets.

Customers; Material Contracts and Marketing

Material Contracts and Marketing

We enter into various agreements with our customers in the ordinary course relating to the use of our land and resources, the fees, royalty rates, payment structure and other related terms under which are negotiated on a case-by-case basis, taking into account the surface use of our land, the type of resources extracted and the amount of use expected to be made of our land and the amount of resources to be produced and/or extracted, among other things. These agreements generally include defined fee schedules for specified surface activities and resource uses, and may provide exclusivity

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for certain resources within defined areas. We are also party to SUAs with a number of customers that have operations on our land. See “Certain Relationships and Related Party Transactions.” For a discussion regarding general market rates for similar uses of land and resources in our industry and geographic area, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Generate Revenue.” Our commercial terms frequently incorporate inflation escalators, audit and measurement rights and customary default and cure regimes. In select arrangements, we also receive royalties tied to volumetric throughput or gross revenues, including for produced water handling, recycling and disposal conducted on or adjacent to our acreage.

Although our agreements typically do not include minimum commitment provisions for activities on or around our land (for example, water purchase volumes), we may, in certain cases and based on a customer’s proposed use, negotiate minimum-use or minimum-volume commitments, acreage dedications, or take-or-pay constructs. Under our contracts, our customers generally bear liability for environmental, health and safety risks, through indemnification of us, mandated insurance coverage and covenants and representations regarding environmental, health and safety compliance for all such risks, in each case, related to their operations on our land. These agreements often include financial assurance or bonding requirements and require customers to name us as an additional insured, with waivers of subrogation where appropriate. Further, our contracts include inspection rights such that we may enter and oversee certain activities on our properties to monitor our customers’ compliance with environmental, health and safety requirements, and, following completion of the term of our agreements, our customers typically must remediate our land as close as is reasonably practicable to its state prior to such customers’ activities on the land.

Assignments, transfers and change-of-control transactions by customers are commonly subject to our consent, and our agreements may include step-in or suspension rights in the event of uncured breaches or imminent safety or environmental risk. For a description of our SUAs, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Generate Revenue—Surface Use Royalties and Revenue—Surface Use Royalties.”

In addition, we are party to the following agreements with our operating partners. The DE Flow WSMA and Hydrosource Recycling Agreement described below are new agreements that will be entered into in connection with this offering. While the businesses we are acquiring (including DE Flow and Shallow Valley Ranch) have historically generated revenues from water-related activities, the royalty revenue structure described in this prospectus reflects the terms of these new agreements, which will supersede any prior arrangements and govern our relationship with DEF Operating and Hydrosource on a go-forward basis.

Produced Water Recycling Rights Agreement with Hydrosource

In connection with this offering, we will enter into the Hydrosource Recycling Agreement with Hydrosource, under which Hydrosource has the sole and exclusive right during the term to utilize our acreage to treat, process and recycle water on our land, including the right to construct, own and operate related water recycling infrastructure. The agreement will have an initial term of 10 years with automatic three-year renewals, unless terminated by a party prior to the renewal, and will have a five-year minimum royalty commitment. We will receive a royalty for each barrel of recycled water stored, treated, processed, recycled, disposed, purchased or sold on our land, and a percentage of the gross selling price for each barrel of recycled water sold off of our land, subject to the agreement. The agreement will also grant Hydrosource the exclusive, two-year option to lease a portion of our land and install and operate a solid waste facility. If the option is exercised, Hydrosource must purchase from us, at prevailing rates, all water and other resources needed for the construction and operation of the solid waste facility and will pay us for easements and surface damages associated therewith, as well as a royalty on the facility’s gross revenues. The agreement will provide for automatic annual increases in

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the flat rate royalties that are tied to the lesser of CPI and a fixed percentage, and mutual termination rights in the event of payment or performance defaults, and contains standard confidentiality, indemnification, insurance and change of control provisions.

Water System Management Agreement with DEF Operating

In connection with this offering, we will enter into the DE Flow WSMA with DEF Operating, pursuant to which DEF Operating is obligated to operate, maintain, repair, expand and optimize our integrated water infrastructure system. The agreement will have an initial term of 10 years with automatic three-year renewals, unless terminated by a party prior to the renewal, and will have a 10-year minimum royalty commitment. Under the agreement, DEF Operating will operate, maintain, repair, expand and optimize the water infrastructure system, and will utilize it to store, transport, treat, process, dispose of, purchase and sell produced water, fresh water, blended water, treated water and recycled water. We will receive monthly royalties on the net proceeds realized by DEF Operating. The agreement will also provide for automatic annual increases in royalties that are tied to the lesser of CPI and a fixed percentage, and mutual termination rights in the event of payment or performance defaults and contains standard confidentiality, indemnification, insurance and change of control provisions.

Pursuant to a put option agreement between Double Eagle and Hydrosource, Double Eagle has the right to sell, and Hydrosource has the obligation to purchase, DEF Operating if Double Eagle undergoes certain change of control events or at any time following five years from the date of this offering. If Double Eagle exercises such put right, Hydrosource would become the owner of DEF Operating, which is the party to the DE Flow WSMA and the minimum royalty obligation thereunder.

Infrastructure

In order to use our surface acreage to, among other things, support all stages of energy development and production to supply growing global demand, we have entered into various SUAs and other agreements through which our customers or operating partners have built and own or are developing infrastructure on our land, including oil, natural gas and produced water gathering pipelines, recycled water pipelines, produced water handling facilities and water recycling ponds, as of December 31, 2025. These agreements typically grant ROWs, easements and defined surface sites and include specified fee schedules for construction, operation and renewal. We also own water wells and ponds on our land. Where applicable, our SUAs provide resource exclusivity on defined tracts and include audit and measurement rights.

Additionally, our Midland Basin assets from which we generate royalty revenue, consist of an integrated produced-water handling and disposal infrastructure system with peak handling capacity of approximately 400 MBbls/d of produced water. This system is supported by long-term contracts, including acreage dedications and, in certain cases, minimum-volume commitments with multiple investment-grade operators, enhancing throughput visibility. Our produced water handling and disposal system is operated by our partner, DEF Operating, and includes pipelines, SWD wells and water storage tanks that enable water management for multiple investment grade operators across the Midland Basin. The system provides reliable, large-scale water handling, recycling and delivery infrastructure that is essential to supporting upstream development activity. Our royalty revenue from our Midland Basin infrastructure, under the DE Flow WSMA, will be underpinned with a long-term contract with a minimum guaranteed royalty commitment for a term of ten years.

In addition to the above infrastructure, improvements with respect to permanent electrical infrastructure, including telecommunication lines, drilling pad sites and roads, among other things, have been constructed on our land that improve reliability and lower operating costs for our customers.

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Although infrastructure with the ability to increase revenue-generating activities is already present on our surface acreage, we believe that our land presents a multitude of additional opportunities for further commercialization and optimization, including coordinating with potential customers to construct infrastructure relating to traditional and renewable power generation, transmission and storage and data center infrastructure.

Cyclical Nature of Oil and Natural Gas Industry

The oil and natural gas industry is a highly cyclical industry. Demand for the use of our land and its resources depends substantially on activity levels by producers on and around our land. Prevailing commodity prices and future demand for, and price of, oil and natural gas and volatility in oil or natural gas prices (or the perception that oil or natural gas prices will decrease) affect such producers’ capital expenditures and willingness to pursue development activities. As such, the willingness of our producers to engage in drilling activities on and around our land is substantially influenced by the market prices of oil and natural gas. Producers tend to increase capital expenditures in response to increases in oil and natural gas prices, which would generally be expected to result in greater revenues for us. Increased capital expenditures can also lead to greater production, which historically has resulted in increased supplies of oil and natural gas that can, in turn, reduce prices, thereby leading to a reduction in activity levels. For these reasons, the results of our operations may be cyclical and may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort comparisons of results across periods.

Seasonality

While our business is not necessarily seasonal in nature, revenue from the use of our land and its resources may fluctuate over certain reporting periods due to fluctuations in the prices of oil and natural gas. Generally, but not always, the demand for natural gas, as well as associated production, decreases during the summer months and increases during the winter months, thereby affecting the amount we receive in association with natural gas production and related activities on our land. Seasonal anomalies, such as mild winters or hotter than normal summers, may lessen this fluctuation. Demand for oil has generally not been seasonal. Our other revenue streams, including sales of water, payments from SUAs and other surface-related revenue and sales of resources, may also vary from period to period due to seasonal changes in supply and demand, and a variety of additional seasonal factors that are beyond our control and the control of producers on or around our land.

Our results and business are significantly dependent on our customers and their activities on our land, which are beyond our control. Weather conditions in the Permian Basin generally result in higher drilling activity in the spring, summer and fall months, although summer and fall drilling activity can be restricted due to severe weather conditions. In the fourth quarter, due to inclement weather and the exhaustion of annual drilling and completion capital expenditure budgets, drilling activity typically declines in the Permian Basin. As a result, our results of operations, cash flows and financial position may vary year over year, with particular periods of results not necessarily indicative of our future results.

Human Capital Resources

Employees and Human Capital Resources

As of December 31, 2025, L&E had 28 full-time employees. Following the L&E Contribution, we expect to have 21 full time employees. None of L&E’s employees are represented by a labor union or party to a collective bargaining agreement.

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Our human capital resources objectives include, as applicable, identifying, recruiting, retaining, incentivizing, and integrating our existing and new employees, advisors, and consultants. We believe our success depends on our ability to attract, retain, develop, and motivate diverse, highly skilled personnel. In particular, we depend upon the personal efforts and abilities of the principal members of our senior management to partner effectively as a team and to provide strategic direction, develop our business, manage our operations, and maintain a cohesive and stable work environment.

We offer employees a 401(k) plan, and encourage participation as well as financial wellness education. We also offer health benefits, including services focused on emotional and mental health, as well as certain preventative health services related to the early detection of concerns, including breast cancer, diabetes and cardiovascular disease.

Personnel Health and Safety

Safety is important to us and begins with the protection and safety of our personnel and the communities in which we operate. We value people above all else and remain committed to making safety and health our top priority. We strive to comply with all applicable health and safety laws and regulations and continually seek to maintain and deepen our safety culture by providing a safe working environment that encourages active personnel engagement, including implementing safety programs and continuing education policies to achieve improvements in our safety culture. We intend to continue to develop and administer policies to promote our organizational goals and improve and maintain the safety of our workspace.

Competition

The market in which we operate is competitive due to the location of our land in the Permian Basin in Texas and New Mexico, the concentration of large, well-capitalized operators in our areas, and the services that we offer our customers. Given our geographic concentration in the Permian Basin, we compete with existing landowners in the area to provide an attractive development site for the limited number of potential customers that seek to develop and/or construct infrastructure in Texas and New Mexico to support their various business activities. We also encounter competition from landowners or controlling parties with critical ROWs and easements needed for aggregation corridors, grid interconnects and produced-water handling. We also compete with such landowners over the limited supply of, and demand for, resources, including water, in the area. Furthermore, to the extent any new property owner purchases land located in areas comparable to our surface acreage, such property owner could be a potential competitor. In addition, consolidation among upstream operators can shift development pacing and preferred surface access, intensifying competition for projects on specific corridors. As we continue to grow our business and enter into new business lines, we will experience increasing levels of competition. Competition in our current market is based primarily on the geographic location of land, business reputation, pricing arrangements for the use of the land and its resources and legal and regulatory restrictions, among other factors. Although some of our competitors may have a broader geographic scope, longer operating history and greater financial and other resources than we have, we believe that we are competitively well-positioned due to the premier location of our land, which also provides a multitude of resources and uses and our customer relationships.

Insurance

We maintain insurance coverage at levels that we believe are reasonable and prudent for a Permian Basin-focused land management company; however, as is customary in our industry, we do not fully insure against all risks associated with our business, either because such insurance is not

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available or because premium costs are considered prohibitive. Our policies are subject to deductibles, self-insured retentions, exclusions, sublimits (including for pollution, cyber, named storms and seismic events) and other limitations, and certain risks may be uninsurable or uneconomic to insure at desired limits. We may not be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable and our actual coverage may not insure against many types of interruptions or events that might occur. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if a loss event were to occur. The occurrence of such an event, the consequences of which are either not covered by insurance or not fully insured, or a significant delay in, or denial of, the payment of a major insurance claim, could have a material and adverse effect on our results of operations, cash flows and financial position. Our arrangements with our customers operating on our land require the maintenance of certain levels of insurance and such customers’ indemnification of us to protect for such events occurring with respect to their operations, including requirements to name us as an additional insured on specified liability policies on a primary and non-contributory basis, provide waivers of subrogation, furnish certificates and endorsements, and maintain financial assurance where appropriate. However, indemnities may be subject to carve-outs (such as for our gross negligence or willful misconduct) and counterparty credit risk, and customer insurance programs (often written on a claims-made basis) may not respond to all losses; we cannot guarantee continuous compliance by counterparties notwithstanding our contractual audit and inspection rights.

Near Term Business Plan and Capital Needs

We generate multiple revenue streams from the use of our surface acreage and the sale of resources from our land. During 2026, we intend to continue our active land management strategy of optimizing the current uses of our land and its resources, while also identifying and developing, or supporting the development of, new uses of and revenues from our land. We do not currently anticipate any significant capital requirements during 2026 associated with research and development or otherwise, although we may pursue any compelling acquisition opportunity that is presented to us.

Under most of our agreements with our customers, our customers bear substantially all of the operating and capital expenditures related to their operations on our land, which minimizes our capital requirements for both current and future commercial opportunities. We intend to contribute all of the net proceeds from this offering to OpCo in exchange for newly issued OpCo Units. OpCo intends to use the net proceeds from this offering to repay in full, and terminate, the Predecessor Credit Facility and for general corporate purposes.

Should we seek to grow our land position through acquisitions of additional acreage and additional capital were required in excess of our cash resources, we expect that we would seek to raise such capital through borrowings under the Credit Facility, offerings of debt and equity securities or other similar means.

Regulation of Environmental and Occupational Safety and Health Matters

Our customers’ business operations are subject to numerous environmental and occupational health and safety laws and regulations that may be imposed at the federal, regional, state and local levels. The activities that our customers conduct in the course of oil and natural gas exploration and production, produced water handling, sand mining, and other activities are subject to or may become subject to stringent environmental regulation. Our customers are responsible for compliance with various environmental laws and regulations in the course of their operations. Although we generally have the right to inspect our properties and the activities thereon, we typically do not have any control with respect to such activities. For land which we own and lease to a customer, we may be subject to

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strict, joint and several liability for any spills or contamination on those properties, even though we generally have no control over operations on those properties. For further information, see “Risk Factors—Risks Related to Environmental and Regulatory Matters—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause certain of our customers to incur increased costs, additional operating restrictions or delays and a reduction in potential drilling locations. Any such impacts could, in turn, reduce activity levels and related payments on or around our surface acreage.” To mitigate the risk of potential environmental liabilities that may arise in the course of operations on our properties that we do not control, we generally seek to partner with reputable customers and seek indemnification from our customers for liabilities arising from their operations on our land, and we maintain what we believe is customary and reasonable insurance to protect our business against these potential losses. We also typically include covenants relating to compliance with environmental, health and safety regulations and remediation provisions in our contracts. Additionally, we may be able to rely on state-funded programs (such as the TRRC’s Orphan Well Program) for coverage of certain plugging and abandonment liabilities upon declaration of bankruptcy by any of our customers. However, such actions may not be adequate to cover our liabilities, and we are not fully protected or insured against all risks. There can be no assurance that environmental compliance costs will not be material in the future or that such future compliance will not have a material adverse effect on our results of operations, cash flows and financial position, or on those of our customers.

The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. legal standards, as amended from time to time:

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the CAA, which restricts the emission of air pollutants from many sources and imposes various pre-construction, operational, monitoring and reporting requirements, and which the EPA has historically relied upon as authority for adopting climate change regulatory initiatives relating to GHG emissions;

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the Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), which regulates discharges of pollutants into state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;

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the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

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the Resource Conservation and Recovery Act (“RCRA”), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;

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the Oil Pollution Act of 1990, which subjects owners and operators of onshore facilities, pipelines and other facilities, as well as lessees or permittees of areas in which offshore facilities are located, that are the site of an oil spill in waters of the United States, to liability for removal costs and damages;

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the SDWA, which ensures the quality of the United States’ public drinking water through the adoption of drinking water standards and control of the injection of waste fluids into below-ground formations that may adversely affect drinking water sources;

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the ESA, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;

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the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the

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preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment; and

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the Occupational Safety and Health Act (“OSHA”), which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.

Texas and New Mexico have similar laws and regulations in many respects. These environmental and occupational health and safety laws and regulations generally restrict the level of substances generated as a result of operations that may be emitted to ambient air, discharged to surface water, and disposed or released to surface and below-ground soils and groundwater. Additionally, there exist state and local jurisdictions in the United States where we operate that also have, or are developing or considering developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. Any failure by us, or our customers, to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal fines or penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all activities in a particular area. Certain environmental laws also provide for citizen suits, which allow environmental organizations to act in place of the government and sue customers for alleged violations of environmental law. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable, as existing standards are subject to change and new standards continue to evolve.

Some of our land has been or is now operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons is not under our control. Under environmental laws such as CERCLA and RCRA, we could incur strict, joint and several liability for remediating hydrocarbons, hazardous substances or wastes disposed of or released by us or prior owners or operators. We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal or to which we sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at or from such third-party sites.

Waste Disposal. RCRA and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and nonhazardous wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water, and most of the other wastes associated with the exploration, development, and production of oil or gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA, and instead are regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as nonhazardous could be classified as hazardous wastes in the future. Any loss of the RCRA exclusion for drilling fluids, produced water and related wastes could result in an increase in our and our oil and natural gas producing operators’ costs to manage and dispose of generated wastes, which could have a material adverse effect on our and our customers’ results of operations, cash flows and financial position. Texas and New Mexico have received authority from the EPA to administer the RCRA program in their respective jurisdictions, in addition to their own state regulations.

Wastes containing naturally occurring radioactive materials (“NORM”) may also be generated in connection with our customers’ operations. Certain processes used to produce oil and natural gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. NORM is subject primarily

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to individual state radiation control regulations. For example, the TRRC and NMOCD generally regulate the management and disposal of NORM from oil and natural gas operations in their own respective jurisdictions. 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.

The CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into state waters and waters of the U.S. 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 CWA and analogous state laws also require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities.

Water Regulation. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. There continues to be uncertainty regarding the federal government’s applicable jurisdictional reach under the CWA over waters of the U.S., including wetlands, as the EPA and the U.S. Army Corps of Engineers (“Corps”) under the Obama, Trump and Biden Administrations have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach. In January 2023, the EPA and the Corps issued a final rule founded upon the pre-2015 regulations and incorporated updates based on existing Supreme Court decisions, including considerations based on regional and geographic differences. Additionally, the Supreme Court recently decided Sackett v. EPA, a case relating to the legal tests used to determine whether wetlands should be considered “waters of the United States.” A revised waters of the U.S. rule was issued in September 2023, amending the January 2023 rule based on the Sackett decision; however, that rule was challenged in multiple courts. Due to the rule’s injunction in certain states, the implementation of the September 2023 rule varies by state. In November 2025, however, the EPA and the Corps proposed another rule to further update and narrow the September 2023 definition. To the extent any judicial ruling, administrative rulemaking or other action changes the scope of the CWA’s jurisdiction, we, our operating partners and our producers and other customers could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of crude oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. To the extent that any new final rule or rules issued by the EPA and Corps under the Biden Administration expands the scope of the CWA’s jurisdiction in areas where we or our customers conduct operations, such developments could increase compliance expenditures or mitigation costs, contribute to delays, restrictions, or cessation of the development of projects, and also reduce the rate of production of oil and natural gas from producers with whom we have a business relationship and, in turn, have a material adverse effect on our results of operations, cash flows and financial position. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Air Emissions. The CAA and comparable state laws restrict the emission of air pollutants from many sources through air emissions standards, construction and operating permit programs and the imposition of other compliance standards. These laws and regulations may require us, or our customers, to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay our projects as well as our customers’ development of various types of projects. Over the next several years, our customers may incur certain

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capital expenditures for air pollution control equipment or other air emissions related issues, which could lead to an increase in our customers’ operating costs or a decrease in our or our customers’ revenues and limit future development activity by our customers, including our operating partners, thereby reducing their demand for the use of our land and resources. For example, in 2015, the EPA issued a final rule under the CAA, making the National Ambient Air Quality Standard (“NAAQS”) for ground level ozone more stringent. Since that time, the EPA has issued attainment/nonattainment designations with respect to ground-level ozone, and in December 2020, the EPA under the first Trump Administration published a final action that, upon conducting a periodic review of the ozone standard in accord with CAA requirements, elected to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups filed litigation over this December 2020 decision, and in October 2021, the Biden Administration announced plans to reconsider the final action in favor of a more stringent ground-level ozone NAAQS. The 2015 NAAQS continue to be implemented at this time. State implementation of the revised NAAQS could also result in the imposition of more stringent requirements through permits issued by the New Mexico Environmental Department or the Texas Commission on Environmental Quality if projects on our land have air emissions above certain thresholds set under applicable laws and regulations. Compliance with the NAAQS requirements or other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas and other projects and increase our or our customers’ costs of development and production, which costs could reduce demand for our services and have a material adverse impact on our results of operations, cash flows and financial position. In addition, the IRA amends the CAA to impose a fee on the emission of excess 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. In May 2024, the EPA issued a final rule to implement the IRA’s methane fee, although in February 2025, Congress repealed the rule under the Congressional Review Act. Additionally, in the OBBB Act, Congress delayed the implementation of the methane emission charge until 2034. We cannot predict if the Trump Administration and/or Congress may take action to repeal or revise this requirement of the IRA; 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 customers’ cost of development, which costs could be significant, and, indirectly, adversely affect our results of operations, cash flows and financial position.

Produced Water Handling Facilities. Water handling via underground injection is regulated pursuant to the UIC program established under the SDWA and analogous state and local laws and regulations. The UIC program includes requirements for permitting, testing, monitoring, recordkeeping and reporting of produced water handling activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate produced water handling facilities. Authority over underground injection and disposal wells has been delegated by the EPA to the TRRC and the NMOCD, respectively. Although our customers monitor the injection process of their facilities, any leakage from the subsurface portions of the produced water handling facilities could cause degradation of groundwater resources, potentially resulting in suspension of our customers’ UIC permits, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties claiming damages for alternative water supplies, property and personal injuries. A change in water handling regulations or the inability to obtain permits for new produced water handling permits in the future may affect our customers’ ability to handle produced water and other substances on our land, which could adversely affect our business, results of operations, cash flows and financial position.

Furthermore, in response to seismic events in the past several years near produced water handling facilities used for disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such facilities have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such

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produced water handling facilities in certain areas prone to increased seismic activity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by region and that only a very small fraction of the tens of thousands of produced water handling facilities have been suspected to be, or have been, the likely cause of induced seismicity. In 2016, the U.S. Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico and Arkansas. As a result of these concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water handling facilities or otherwise to assess any relationship between seismicity and the use of such wells. For example, the TRRC has issued rules for water handling facilities that imposed certain permitting and operating restrictions and reporting requirements on produced water handling facilities in proximity to faults. New Mexico has, in some parts of the state, issued monitoring and reporting guidelines with respect to seismic activity and requires significant spacing between produced water handling facilities.

States also may issue orders to temporarily shut down or to curtail the injection depth of existing facilities in the vicinity of seismic events. In Texas, the TRRC has pursued several regulatory initiatives since the latter half of 2021 as a result of recent seismic activity in an area of the Midland Basin including: (i) directing operators to pursue voluntary reductions in produced water handling from scores of produced water handling facilities in response to earthquakes; (ii) suspending certain deep produced water handling permits within SRAs: and (iii) suspending all produced water handling permits to inject oil and natural gas waste into deep strata within the boundaries of SRAs. In November 2021, New Mexico implemented protocols requiring operators to take various actions within a specified proximity of certain seismic activity, including a requirement to limit injection rates if a seismic event is of a certain magnitude. Further, in July 2024, New Mexico announced the administrative cancellation of 75 pending permit applications for UIC Class II wells within the 10-mile County Line SRA, due to the potential for increased seismicity within the area. An additional consequence of this seismic activity is lawsuits alleging that produced water handling operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. The adoption and implementation of any new laws, regulations or directives that restrict our customers’, including our operating partners’, ability to dispose of wastewater on our land by limiting volumes, disposal rates, produced water handling facility locations or otherwise, or requiring our customers to shut down produced water handling facilities, could reduce the demand for use of our land and resources and limit the fees and royalties we receive from the transportation and the handling of produced water on our land, which would have a material adverse effect on our results of operations, cash flows and financial position.

Hydraulic Fracturing. Hydraulic fracturing involves the injection of water, sand or other proppants and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is an important and common practice that is typically regulated by state oil and natural gas commissions or similar agencies. However, the practice continues to be controversial in certain parts of the country, resulting in increased scrutiny and regulation of the hydraulic fracturing process, including by federal agencies that have asserted regulatory authority or pursued investigations over certain aspects of the hydraulic fracturing process.

Moreover, some state and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations, including states where our customers operate. For example, Texas, New Mexico and other states have adopted regulations that impose stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. The TRRC in 2014, for instance, issued a “well integrity rule” which updated the requirements for drilling, completing and cementing wells. States could also elect to place certain prohibitions on hydraulic fracturing. For example, in recent years, in New Mexico, there have been continued efforts to pause hydraulic fracturing and cease state issuance of permits for a four-year time period, although none of the bills introduced on this topic have yet passed the New Mexico Legislature.

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In the event that new federal, state or local restrictions or bans on the hydraulic fracturing process are adopted in areas where our land is located, our customers may incur additional costs or permitting requirements to comply with such requirements that may be significant in nature and our customers could experience added restrictions, delays or cancellations in their exploration, development, or production activities, which would in turn reduce the demand for use of our land and resources and have a material adverse effect on our results of operations, cash flows and financial position.

Climate Change. The threat of climate change continues to attract considerable attention from the public and policymakers in the U.S. and around the world. As a result, numerous proposals have been made, and more are likely forthcoming at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our customers are subject to a series of regulatory, political, litigation, and financial risks associated with our and their operations, including those related to the production and processing of fossil fuels and emission of GHGs.

Endangered Species. The ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are afforded under the MBTA, which prohibits the taking of protected migratory bird species without prior authorization by the FWS. To the degree that species listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our customers operate, our and our customers’ abilities to conduct or expand operations and construct facilities could be limited or we and our customers could be forced to incur material additional costs. Moreover, our customers’ drilling activities may be delayed, restricted, or cancelled in protected habitat areas or during certain seasons, such as breeding and nesting seasons. Some of our land and the operations of our customers are located in areas that are designated as habitats for protected species. In addition, the FWS may make determinations on the listing of unlisted species as endangered or threatened under the ESA. The dunes sagebrush lizard and the lesser prairie chicken are examples of species that, if listed as endangered or threatened under the ESA in the future, could impact our or our customers’ operations. For example, in November 2022, the FWS listed the northern district population segment of the lesser prairie chicken (encompassing southwest Colorado, southcentral to western Kansas, western Oklahoma and the northeast Texas Panhandle) as threatened under the ESA, and the southern district population segment (covering eastern New Mexico and the southwest Texas Panhandle) as endangered. However, in March 2025, the U.S. District Court for the Western District of Texas vacated the rule for the northern district population segment. The FWS also listed the dunes sagebrush lizard as an endangered species under the ESA in a final rule effective June 20, 2024. However, this rule is also subject to challenge. Critical habitat for the species has not yet been designated, but is expected to occur after a separate rulemaking in the future. The designation of previously unidentified endangered or threatened species could indirectly cause us or our customers to incur additional costs, cause our or our customers’ operations to become subject to operating restrictions or bans and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of, or access to, federal, state, and private lands, including our land. Over time, the trend in environmental and occupational health and safety regulation is to typically place more restrictions and limitations on activities that may adversely affect the environment or expose workers to injury and thus, any changes in environmental or occupational health and safety laws and regulations or reinterpretation of enforcement policies that may arise in the future and result in more stringent or costly waste management or disposal, pollution control, remediation or occupational health and safety-related requirements could have a material adverse effect on our business, results of operations, cash flows and financial position. We may not have insurance or be fully covered by insurance against all environmental and occupational health and safety risks, and we may be unable to pass on increased compliance costs arising out of such risks to our customers. We review regulatory and environmental issues as they pertain to us and we consider regulatory and environmental issues as part of our

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general risk management approach. For more information on environmental and occupational health and safety matters, see “Risk Factors—Risks Related to Environmental and Regulatory Matters—Legislation or regulatory initiatives intended to address seismic activity, over-pressurization or subsidence could restrict drilling, completion and production activities, as well as our operating partners’ ability to handle produced water gathered from its customers, which could have a material adverse effect on our results of operations, cash flows and financial position,” “Risk Factors—Risks Related to Environmental and Regulatory Matters—The results of operations of our customers, as well as producers on or around our land, may be materially impacted by efforts to transition to a lower-carbon economy, which could have a material adverse effect on our business, results of operation, cash flows and financial position.” “Risk Factors—Risks Related to Our Business and Operations—We and our customers may be subject to claims for personal injury and property damage, catastrophic events, and those related to contamination resulting from our customers’ operations, which could have a material and adverse effect on our results of operations, cash flows and financial position,” “Risk Factors—Risks Related to Our Business and Operations—We or our customers may be unable to obtain and renew permits necessary for operations, which could materially and adversely affect our results of operations, cash flows and financial position” and “Risks Related to Our Business and Operations.”

Legal Proceedings

We are periodically party to proceedings and claims incidental to our business. While many of these other matters may not be predicted with certainty, we believe that the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on our financial position or on our liquidity, capital resources, future results of operations or cash flows. We will continue to evaluate proceedings and claims involving us on a regular basis and will establish and adjust any estimated reserves as appropriate to reflect our assessment of the then-current status of the matters.

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MANAGEMENT

Set forth below are the names, ages and titles of our executive officers and director nominees:


Name	Age		Position with EagleRock Land, LLC
Greg Pipkin Jr.		36	Chief Executive Officer and Sole Director
Neal H. Shah		55	President and Chief Financial Officer
Robert W. Hunt Jr.		45	General Counsel
Richard H. Coats		66	Chairman
Raj Kumar		53	Director Nominee
Jeff S. Lott		64	Director Nominee
James C. Nelson		62	Director Nominee
Stephanie Reed		43	Director Nominee
Michael W. Wallace		63	Director Nominee

Executive Officers and Director Nominees

The following is a biographical summary of the business experience of these executive officers and director nominees:

Greg Pipkin Jr.—Chief Executive Officer and Sole Director. Mr. Pipkin has served as our Chief Executive Officer since November 2025 and will continue to serve in such role upon the listing of our Class A shares. Prior to this offering, he also served as our sole director. Prior to joining EagleRock, Mr. Pipkin served as Senior Vice President, Corporate Development and Strategy of Infinity Natural Resources (“Infinity”) from March 2024 to November 2025. Prior to joining Infinity, he served as Senior Vice President, Permian Asset Team & Finance at Spur Energy Partners (“Spur”) from September 2021 to March 2024. While at Spur, Mr. Pipkin had previously held the position of Vice President, Finance & Corporate Development from June 2019 to September 2021. Previously, Mr. Pipkin held engineering roles at Wildhorse Resources Management Company, LLC, Memorial Resource Development Corp. and Halcon Resources Corporation. Mr. Pipkin holds a Bachelor of Science in Petroleum Engineering and a Master of Business Administration from the University of Texas at Austin.

Neal H. Shah—President and Chief Financial Officer. Mr. Shah has served as our President and Chief Financial Officer since December 2025 and will continue to serve in such role upon the listing of our Class A shares. Prior to joining EagleRock, Mr. Shah was elected as Executive Vice President and Chief Financial Officer of Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”), where he held the role of Chief Financial Officer from January 2021 through June 2024. Under his tenure as Chief Financial Officer, Pioneer’s stock price increased from approximately $113 to approximately $270 per share and culminated in Pioneer’s $65 billion acquisition by Exxon Mobil Corporation. Mr. Shah joined Pioneer in June 2017 as Vice President, Investor Relations.

Prior to Pioneer, Mr. Shah served as a Senior Equity Research Analyst at Thrivent Asset Management from June 2016 to June 2017 and as a Vice President at Nuveen LLC from March 2006 to June 2016. His deep operational experience is complemented with additional financial roles at Piper Jaffray & Company, RBC Capital Markets, and Goldman Sachs & Co. Mr. Shah holds a Bachelor of Science in Electrical Engineering from Louisiana State University and a Master of Business Administration from The University of Chicago Booth School of Business, where he was named a Siebel Scholar and received the Irwin J. Biederman Leadership Award.

Robert W. Hunt Jr.—General Counsel. Mr. Hunt has served as our General Counsel since January 2026 and will continue to serve in such role upon the listing of our Class A shares. Prior to joining EagleRock, Mr. Hunt served as Chief Legal Officer and Corporate Secretary of Aris Water Solutions, Inc. (“Aris”) from February 2024 until Aris’ merger with Western Midstream Partners, LP in

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October 2025. Prior to joining Aris, he served as Executive Vice President & General Counsel of Earthstone Energy, Inc. (“Earthstone”) from April 2022 until Earthstone’s merger with Permian Resources Corporation in November 2023. Prior to joining Earthstone, he served as Senior Vice President, General Counsel and Secretary of Indigo Natural Resources LLC (“Indigo”) from August 2016 until Indigo’s merger with Southwestern Energy Company in September 2021. From May 2010 until July 2016, Mr. Hunt worked for Cobalt International Energy, Inc., serving most recently as Associate General Counsel focusing primarily on capital markets and major transactions. Mr. Hunt began his career with Vinson & Elkins LLP, practicing corporate and securities law. Mr. Hunt holds a Bachelor of Science in Business Administration and Politics from Washington and Lee University and a Juris Doctor from the University of Texas School of Law.

Richard H. Coats—Chairman. Mr. Coats began his career in the oil and gas business in 1984. Since 2006, Mr. Coats has served as the Co-Founder of OGX Resources, LLC, Santa Elena Minerals, LLC, OGX Minerals, LP and OGX Minerals II, LP, entities focused on acquisition and development of oil and natural gas resources in the Permian Basin. Beginning in 2011, Mr. Coats began acquiring surface rights and, as of January 2026, owned approximately 83,000 acres, with 60,000 acres located in the Permian Basin and 23,000 acres located in Utah. Approximately 40,000 of such acreage in the Permian Basin is located in the Midland Basin, where substantial water infrastructure and SWD systems were developed from the ground up.

Prior to 2006, Mr. Coats founded Cactus Energy, Inc., which currently owns non-operated working interests in over 750 wells located primarily in the Permian Basin. Mr. Coats began his oil and gas career at Texas Oil & Gas Corp. after employment as an oil and gas lender at Republic Bank Dallas. Mr. Coats holds a Bachelor’s Degree from the University of Texas at Austin.

Raj Kumar—Director Nominee. Mr. Kumar has served as Executive Vice President and Chief Financial Officer of Kirby Corporation (NYSE: KEX) (“Kirby”) since November 2021. Prior to joining Kirby, Mr. Kumar served as Vice President and Chief Financial Officer of Dril-Quip, Inc. (NYSE: DRQ) (“Dril-Quip”) from 2020 to 2021, Vice President and Chief Accounting Officer from 2019 to 2020, and Vice President and Treasurer from 2017 to 2019. Prior to joining Dril-Quip, he served as Vice President Finance at Frank’s International (NYSE: FI) from 2015 to 2017. Prior to that, he served as a segment controller at LyondellBasell (NYSE: LYB) and in Division CFO, treasury, strategic planning and corporate development positions at FMC (NYSE: FMC) and Dell Inc. (NYSE: DELL). Mr. Kumar is a member of CPA Australia and holds a Master of Business Administration degree from Columbia University in New York City and a Bachelor of Business in Accounting degree from Deakin University in Australia.

Jeff S. Lott—Director Nominee. Mr. Lott has served as Managing Trustee and co-owner of Lott Mineral Trust for over 29 years. The Lott Mineral Trust comprises approximately 88,000 contiguous net mineral acres in West Texas. In this role, Mr. Lott oversees oil and gas royalties, leasing operations, water resource revenues—including fresh water sales and disposal—and easement and surface use royalties. In addition to his work with Lott Mineral Trust, Mr. Lott has been involved in numerous ventures in the oil and gas industry over the past three decades. From 2011 to 2014, he was Founder and Chief Executive Officer of Permian Basin Sand Haulers, which operated a fleet of over 140 trucks throughout the Permian Basin prior to its sale to Francis Drilling Fluids. From 2009 to 2011, he was co-founder and owner of Tech Management, an oilfield chemical company servicing more than 6,000 wells across West Texas and Eastern New Mexico, until its acquisition by Globe Energy Services. From 2007 to 2011, Mr. Lott served as Founder and Chief Executive Officer of Surpacifico, LLC, which owned and operated oil tankers and drilling assist barges off the coast of Northern Peru. Earlier in his career, beginning in 1986, he owned and operated several companies across Texas providing services in oilfield chemicals, conventional drilling and gas compression. Mr. Lott holds a Bachelor of Business Administration in Management from Texas Tech University.

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James C. Nelson—Director Nominee. Mr. Nelson serves as President, Chief Executive Officer and Chairman of Warren Equipment Company (“WEC”) and as Dealer Principal and President of Warren CAT. Prior to joining WEC, Mr. Nelson spent seven years in the investment industry as a Financial Consultant with Dean Witter Reynolds and Smith Barney, Harris Upham in Dallas, Texas. Mr. Nelson serves as Chairman of The Scharbauer Foundation in Midland, Texas and as a board member of HiVolt Energy. He previously served as Chairman of The Cooperative Association of Tractor Dealers, Inc., and as Chairman and member of the Advisory Council of the Moody College of Communication at The University of Texas. Mr. Nelson holds a bachelor’s degree in Finance from Michigan State University.

Stephanie Reed—Director Nominee. Ms. Reed has served as Partner of Formentera Partners, where she oversees business development, land, geosciences, and marketing and midstream functions, and supports asset management and operations since April 2022. Prior to joining Formentera, Ms. Reed served as Vice President of Oil & Gas Marketing & Midstream at Pioneer. Prior to Pioneer, she spent more than a decade at Parsley Energy, where she most recently served as Senior Vice President of Business Development, Land, Marketing & Midstream. During her tenure, she led business development and integration efforts representing over $20 billion in asset value. Ms. Reed has over 15 years of experience in the oil and gas industry. She holds a Master of Business Administration and a Bachelor of Applied Science from Texas Tech University. In 2019, she was named to Oil and Gas Investor magazine’s “Forty Under 40” list.

Michael W. Wallace—Director Nominee. Mr. Wallace has served as Partner and Manager of Wallace Family Partnership, LP (“Wallace LP”), which holds non-operated working interests in oil and gas leases, midstream assets and other investments since 2010. He previously served on the Board of Directors of RSP Permian, Inc. (NYSE: RSPP), a public oil and gas company, from 2014 to 2018 when it was acquired by Concho Resources (NYSE: CXO) for $9.5 billion. Mr. Wallace served as President, Director and Manager of High Sky Partners LLC, a Midland, Texas-based oil and gas company with operations in the Spraberry Trend of the Permian Basin. Additionally, Mr. Wallace served as Executive Vice President of Production at Patriot Resource Partners LLC from 2007 to 2011. In 2004, he founded Flying W Resources, L.L.C., an independent oil and gas production company. Previously, Mr. Wallace held various technical and managerial roles at Conoco Inc. and ConocoPhillips Company from 2001 to 2004, and earlier in his career, he held roles at Burlington Resources Inc. Mr. Wallace holds a Bachelor of Science in Petroleum Engineering from Texas Tech University and is a member of the Society of Petroleum Engineers.

Status as a Controlled Company

Upon completion of this offering, our Existing Owners will initially own approximately 94,785,096 Class B shares, representing approximately 72.8% of our combined voting power. Pursuant to the terms of the Voting Agreements, each Existing Owner will agree with us that it and certain of its transferees will vote its respective Class A shares and Class B shares in favor of each of the director nominees recommended for election by our board of directors. See “Certain Relationships and Related Party Transactions—Voting Agreements.” As a result, we expect to be a controlled company as of the completion of this offering under the Sarbanes-Oxley Act and the NYSE and NYSE Texas rules. A controlled company is not required to have a majority of independent directors or to form an independent compensation or nominating and corporate governance committee. As a controlled company, we will remain subject to the Sarbanes-Oxley Act and the rules of the NYSE and NYSE Texas that require us, subject to certain phase-in periods, to have an audit committee composed entirely of independent directors. Under these rules, we must have an audit committee that has one member who is independent by the listing date, a majority of members that are independent within 90 days of the effective date and all members that are independent within one year of the effective date. We expect to have five independent directors upon the closing of this offering.

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If at any time we cease to be a controlled company, we intend to take all action necessary to comply with the Sarbanes-Oxley Act and the NYSE and NYSE Texas rules, including by appointing a majority of independent directors to our board of directors and establishing a compensation committee and a nominating and corporate governance committee, each composed entirely of independent directors, subject to a permitted “phase-in” period.

Composition of Our Board of Directors

Upon consummation of this offering, our LLC Agreement will provide that our board of directors shall consist of such number of directors as shall be determined from time to time by our board of directors, but shall not consist of less than seven directors. At the closing of this offering, we will have a single class of directors, and directors will be subject to re-election on an annual basis at each annual meeting of shareholders. In connection with this offering, we will enter into a Shareholder’s Agreement with each of the Existing Owners, which will provide the Existing Owners with the right to designate a certain number of nominees to our board of directors so long as the Existing Owners, and their affiliates and certain transferees, collectively beneficially own a specified amount of the outstanding Class A and Class B shares. See “Certain Relationships and Related Party Transactions—Shareholder’s Agreements.” After the Trigger Event, our board of directors will be divided into three classes that are as nearly equal in number as is reasonably possible and each director will be assigned to one of the three classes. If at the time of the Trigger Event, any of the directors are designees of Double Eagle, such designees shall, at Double Eagle’s election, be classified as members of the third class of directors. After the Trigger Event, at each annual meeting of shareholders, a class of directors will be elected for a three-year term to succeed the directors of the same class whose terms are then expiring. The initial terms of the Class I, Class II and Class III directors will expire at the first, second and third, respectively, annual meeting following the Trigger Event. Upon the date that our Class A shares are first traded on the NYSE and NYSE Texas, we expect to have seven members on our board of directors.

Our LLC Agreement will not provide for cumulative voting in the election of directors, which means that the holders of a majority of our issued and outstanding common shares can elect all of the directors standing for election, and the holders of the remaining common shares will not be able to elect any directors. Our Existing Owners’ beneficial ownership of greater than 50% of our voting common shares immediately following this offering means our Existing Owners will be able to control matters requiring shareholder approval, which includes the election of directors.

Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.

Director Independence

Our board of directors intends to review the independence of our directors using the independence standards of each of the NYSE, NYSE Texas and the SEC. Currently, we anticipate that our board of directors will determine that each of Mr. Kumar, Mr. Nelson and Ms. Reed are independent within the meaning of the NYSE and NYSE Texas rules currently in effect and will be independent within the meaning of Rule 10A-3 of the Exchange Act.

Director Compensation

For a discussion of our director compensation arrangements, see “Executive Compensation—Director Compensation.”

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Committees of the Board of Directors

Following the completion of this offering, we intend to have an audit committee of our board of directors. In addition, our board of directors may establish such other committees as it determines necessary or advisable from time to time. We anticipate that each of the standing committees of the board of directors will have the composition and responsibilities described below. We will rely on the exemptions and phase-in provisions of Rule 10A-3 of the Exchange Act and the NYSE and NYSE Texas transition rules applicable to companies completing an initial listing.

Audit Committee

We are required to have an audit committee of at least three members, and all of its members are required to meet the independence and experience standards established by each of the Exchange Act and the NYSE and NYSE Texas rules, subject to certain transitional relief described below. We will establish an audit committee compliant with each of the SEC and the NYSE and NYSE Texas rules prior to the completion of this offering. We anticipate that following completion of this offering, our audit committee will consist of Mr. Kumar, Mr. Nelson and Ms. Reed, who are independent under the applicable rules of each of the SEC and the NYSE and NYSE Texas. We expect that our board of directors will determine that Mr. Kumar is an audit committee financial expert as defined by the SEC. We will rely on the phase-in rules of each of the SEC and the NYSE and NYSE Texas with respect to the independence of our audit committee.

The audit committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs relating to legal and regulatory requirements and company policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management. We expect to adopt an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of each of the SEC and the NYSE and NYSE Texas standards.

Conflicts Committee

In accordance with the terms of our LLC Agreement, our board of directors may from time to time refer specific matters that may involve conflicts of interest to a conflicts committee. The members of any such conflicts committee cannot be officers or employees of our Existing Owners or their respective affiliates, and must meet the independence and experience standards established by each of the SEC and the NYSE and NYSE Texas to serve on an audit committee of a board of directors. In addition, the members of any such conflicts committee cannot own any interest in our Existing Owners or their respective affiliates, or any interest in us or our subsidiaries other than shares or awards, if any, awarded under the LTIP.

Compensation Committee

Because we will be a “controlled company” within the meaning of the NYSE and NYSE Texas rules, we will not be required to, and do not currently expect to, have a compensation committee in the present or foreseeable future.

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If and when we are no longer a “controlled company” within the meaning of each of the NYSE and NYSE Texas rules, we will be required to establish a compensation committee compliant with each of the SEC and NYSE and NYSE Texas rules. We anticipate that such a compensation committee would consist of three directors who will be “independent” under the applicable rules of each of the SEC and the NYSE and NYSE Texas. This committee would establish salaries, incentives and other forms of compensation for officers and other employees. Any compensation committee would also administer our incentive compensation and benefit plans. Upon formation of any compensation committee, we would expect to adopt a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of each of the SEC and the NYSE and NYSE Texas.

Nominating and Corporate Governance Committee

Because we will be a “controlled company” within the meaning of the NYSE and NYSE Texas rules, we will not be required to, and do not currently expect to, have a nominating and corporate governance committee in the present or foreseeable future.

If and when we are no longer a “controlled company” within the meaning of the NYSE and NYSE Texas rules, we will be required to establish a nominating and corporate governance committee compliant with SEC and NYSE and NYSE Texas rules. We anticipate that such a nominating and corporate governance committee would consist of three directors who will be “independent” under the applicable rules of the SEC and the NYSE and NYSE Texas. This committee would identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes and maintain a management succession plan. Upon formation of any nominating and corporate governance committee, we would expect to adopt a nominating and corporate governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and the NYSE and NYSE Texas.

Guidelines for Selecting Director Nominees

In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance our board of directors’ ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of a committee of the board to fulfill its duties. In particular, we will assess candidates who:

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have demonstrated notable or significant achievements in business, education or public service;

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possess the requisite intelligence, education and experience to make a significant contribution to the board of directors and bring a range of skills, diverse perspectives and backgrounds to its deliberations; and

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have the highest ethical standards, a strong sense of professionalism and intense dedication to serving the interests of our shareholders.

We will consider a number of additional qualifications in evaluating a person’s candidacy for membership on the board of directors. We may require certain skills or attributes, such as financial or accounting experience, to meet specific board needs that arise from time to time, and we will also consider the overall experience and makeup of the board’s members to obtain a broad and diverse mix of board members.

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Corporate Code of Business Conduct and Ethics

Prior to the completion of this offering, our board of directors will adopt a code of business conduct and ethics applicable, at a minimum, to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE and NYSE Texas. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE and NYSE Texas.

Corporate Governance Guidelines

Prior to the completion of this offering, our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE and NYSE Texas.

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EXECUTIVE COMPENSATION

We are currently considered an “emerging growth company” within the meaning of the Securities Act and the Exchange Act, for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures regarding executive compensation for our last completed fiscal year. Further, our reporting obligations generally extend only to each individual who, during the last completed fiscal year, served in the role of our principal executive officer, and to our two most highly compensated executive officers (such individuals are referred to herein as “Named Executive Officers”).

With respect to the year ended December 31, 2025, our Named Executive Officers were as follows:


Name		Principal Position
Gregory Pipkin Jr.		Chief Executive Officer
Neal H. Shah		President and Chief Financial Officer

2025 Summary Compensation Table

The following table represents information regarding the total compensation awarded to, earned by or paid to our Named Executive Officers during the fiscal year ended December 31, 2025:


Name and Principal Position	Year		Salary ($)(1)		Bonus ($)(2)		Total ($)
Gregory Pipkin Jr. (Chief Executive Officer)		2025	$	40,011	$	250,000	$	290,011
Neal H. Shah (President and Chief Financial Officer)		2025	$	19,178	$	250,000	$	269,178

(1)	Base salary values reflect amounts paid during the Named Executive Officer’s service following his respective hire date.

(2)	The 2025 bonus amount reflected for Mr. Pipkin was paid in February 2026. The 2025 bonus amount reflected for Mr. Shah was paid in January 2026.

Outstanding Equity Awards at Fiscal Year End

Neither of the Named Executive Officers held any equity awards at 2025 fiscal year-end.

Additional Narrative Disclosure Regarding Executive Compensation Matters

Employment Agreements and Compensation Arrangements with our Named Executive Officers

The narrative set forth below reflects compensation awarded to or earned by our named executive officers for the fiscal year ended December 31, 2025. In connection with the Company’s preparation for this offering, the employment agreements of Mr. Shah and Mr. Pipkin were amended during 2026 to provide for the assignment of such agreements to the Company automatically upon the completion of this offering, and to clarify the terms of certain incentive awards that may become earned upon the completion of this offering. These amendments did not affect compensation earned by Mr. Shah or Mr. Pipkin for fiscal year 2025.

Each of the following employment agreements was entered into with Hydrosource during 2025. In connection with this offering, the employment agreements will be assigned to the Company. The Named Executive Officers did not receive any compensation from the Company prior to entering into these employment agreements.

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Employment Agreement with Mr. Gregory Pipkin Jr.

Mr. Pipkin’s employment agreement provides for an initial two-year term ending November 17, 2027, unless earlier terminated. The employment agreement provides for Mr. Pipkin to serve as our Chief Executive Officer. Under the agreement, the Company may terminate Mr. Pipkin’s employment at any time with or without Cause (defined below), and Mr. Pipkin may resign for Good Reason (defined below) or for convenience. Under the terms of his employment agreement, Mr. Pipkin’s initial base salary is $500,000, subject to review and adjustment by the Company from time to time. Mr. Pipkin is also eligible for an annual discretionary bonus, as determined by the board of directors, and a one-time initial public offering bonus of $10,000,000 payable in cash or fully vested equity upon the successful completion of this offering, subject to his continued employment through that date, and a potential initial public offering bonus based on valuation multiples. If no initial public offering occurs but the Company or substantially all of its assets are sold, he is eligible for a discretionary one-time cash bonus. The agreement also provides severance benefits of $2,500,000 in the event of a qualifying termination without Cause or resignation for Good Reason (subject to timing limitations and execution of a release).

Employment Agreement with Mr. Neal H. Shah

Mr. Shah’s employment agreement provides for a fixed term ending December 31, 2027, unless earlier terminated. The employment agreement provides for Mr. Shah to serve as President and Chief Financial Officer of the Company. Under the agreement, the Company may terminate his employment at any time with or without Cause, and Mr. Shah may resign for Good Reason or for convenience. Under the terms of his employment agreement, Mr. Shah’s initial base salary is $500,000, subject to review and adjustment by the Company from time to time. Mr. Shah is also eligible to receive an initial $250,000 signing bonus, an annual discretionary bonus and, upon the completion of this offering, a one-time initial public offering bonus of $10,000,000 and a potential initial public offering additional bonus based on valuation multiples. If a Company sale or asset sale occurs before an initial public offering, he will receive a cash bonus equal to 1% of the sale proceeds (net of specified deductions). The agreement also provides severance benefits of up to $15,000,000 in combined cash and equity in the event of a qualifying termination without Cause or resignation for Good Reason, subject to timing limitations and execution of a release.

Severance or Change in Control Agreements

The employment agreements provide for potential severance benefits in the event of a termination of employment for “Cause” or “Good Reason.” The employment agreements generally provide that “Cause” means the person’s (i) willful failure to substantially perform duties or comply with a lawful directive from the board of directors, (ii) conviction, plea of nolo contendere or imposition of unadjudicated probation for any felony or any crime involving moral turpitude, (iii) unlawful use or possession of illegal drugs on Company premises or while performing duties, (iv) fraud, embezzlement, misappropriation, material misconduct or breach of fiduciary duty with respect to the Company or (v) a material breach of the employment agreement or any other written agreement with the company including a material breach of any representation, warranty or covenant, subject in certain cases to a 30-day cure right, if curable.

The employment agreements generally provide that “Good Reason” means (i) a material reduction in base salary or target bonus opportunity, (ii) a material reduction in title, authority, duties or responsibilities or (iii) relocation of the executive’s principal work location by more than 50 miles. For each executive, resignation for “Good Reason” requires written notice within 60 days of the triggering event, a 30-day opportunity for the Company to cure the condition, and, if not cured, resignation within 30 days after the cure period.

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Gregory Pipkin Jr.

Pursuant to the terms of Mr. Pipkin’s employment agreement, if his employment is terminated by the Company without Cause, or if he resigns for Good Reason under the conditions described in the agreement, he is entitled to receive a lump-sum severance payment of $2,500,000, subject to his execution of a release and continued compliance with standard restrictive covenants over a one-year period following his employment. If his employment is terminated for Cause, due to death or disability or if he resigns without Good Reason, he is entitled only to accrued but unpaid compensation and benefits.

Neal H. Shah

Pursuant to the terms of Mr. Shah’s employment agreement, if his employment is terminated by the Company without Cause, if he resigns for Good Reason, or upon the expiration of the contract term, he is entitled to receive a severance payment consisting of $5,000,000 in cash and $10,000,000 in fully vested equity (subject to a cap), contingent upon his execution of a release and continued compliance with restrictive covenants over a one-year period following his employment. If his employment is terminated for Cause, due to death or disability or if he resigns without Good Reason, he is entitled only to accrued but unpaid compensation and benefits. In the event he receives an initial public offering bonus (and any applicable additional listing bonus), he is not entitled to severance.

Anti-Hedging Policies

We expect to adopt a policy that will prohibit our employees, including all executive officers, and members of our board of directors from engaging in transactions that are considered to hedge or offset the financial impact of holding our Class A shares.

Clawback Policy

We intend to timely adopt an incentive compensation clawback policy that complies with the listing standards of the NYSE and NYSE Texas.

Director Compensation

We did not pay any compensation or grant any equity awards to any non-employee director during the 2025 calendar year. We expect to adopt a director compensation program for non-employee directors on a go-forward basis that will include a significant element of share-based compensation awards from the LTIP described above, in order to align the interests of our directors and our shareholders. However, we are currently in discussions regarding the design of the director compensation program that will become effective upon completion of this offering and have not made any final decisions regarding the details of such a program.

Compensation Arrangements to be Adopted in Connection with this Offering

Long Term Incentive Plan (the “LTIP”)

In order to incentivize management members following the completion of this offering, we anticipate that our board of directors will adopt an LTIP for employees, consultants and directors. Our Named Executive Officers will be eligible to participate in this plan, which will become effective upon the consummation of this offering. We anticipate that the LTIP will provide for the grant of options, share appreciation rights, restricted shares, restricted share units, share awards, dividend equivalents, other share-based awards, cash awards, substitute awards and performance awards intended to align the interests of service providers (including the Named Executive Officers) with those of our

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shareholders. The description of the LTIP set forth below is a summary of the material anticipated features of the LTIP. This summary does not purport to be a complete description of all of the anticipated provisions of the LTIP and is qualified in its entirety by reference to the LTIP, the form of which will be filed as an exhibit to this registration statement.

LTIP Share Limits

Subject to adjustment in the event of certain transactions or changes of capitalization in accordance with the LTIP, a total of 13,012,499 of our Class A shares will initially be reserved for issuance pursuant to awards under the LTIP. The total number of shares reserved for issuance under the LTIP may be issued pursuant to incentive stock options (which generally are stock options that meet the requirements of Section 422 of the Code). Class A shares subject to an award that expires or is cancelled, forfeited, exchanged, settled in cash or otherwise terminated without delivery of shares will again be available for delivery pursuant to other awards under the LTIP; however, shares withheld to pay the exercise price of, or to satisfy the withholding obligations with respect to an award, will not be available for delivery pursuant to other awards under the LTIP. Substitute awards granted in accordance with applicable stock exchange requirements and in substitution or exchange for awards previously granted by a company acquired by us or any of our subsidiaries or with which we or any of our subsidiaries combines will not reduce the number of Class A shares authorized for issuance under the LTIP, nor will Class A shares subject to substitute awards be added to the Class A shares available for issuance under the LTIP.

Additionally, the LTIP limits the value of awards (based on their grant-date fair value) granted to a non-employee director in respect of his or her service as a non-employee director to a maximum of $750,000 during each calendar year during which the LTIP is in effect, except that, for any calendar year in which a non-employee director first commences service on our board of directors or serves as lead director or chairman of our board of directors, additional awards may be granted under the LTIP in excess of such limit.

Administration

The LTIP will be administered by a committee of two or more directors designated by our board of directors to administer the LTIP, such as our compensation committee, unless our board of directors elects to administer the LTIP (as applicable, the “administrator”). The administrator will have broad discretion to administer the LTIP, including the power to determine the eligible individuals to whom awards will be granted, the number and type of awards to be granted and the terms and conditions of awards. The administrator may also accelerate the vesting or exercise of any award and make all other determinations and to take all other actions necessary or advisable for the administration of the LTIP.

Eligibility

Any individual who is our officer or employee or an officer or employee of any of our affiliates, and any other person who provides services to us or our affiliates, including members of our board of directors, is eligible to receive awards under the LTIP at the discretion of the administrator.

Stock Options

The administrator may grant incentive stock options and options that do not qualify as incentive stock options, except that incentive stock options may only be granted to persons who are our employees or employees of one of our subsidiaries, in accordance with Section 422 of the Code. The exercise price of a stock option generally cannot be less than 100% of the fair market value of our Class A shares on the date on which the option is granted and the option must not be exercisable for longer than 10 years following the date of grant. In the case of an incentive stock option granted to an

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individual who owns (or is deemed to own) at least 10% of the total combined voting power of all classes of our shares, the exercise price of the stock option must be at least 110% of the fair market value of a share of our Class A shares on the date of grant and the option must not be exercisable more than five years from the date of grant.

Share Appreciation Rights (“SARs”)

A SAR is the right to receive an amount equal to the excess of the fair market value of our Class A shares on the date of exercise over the grant price of the SAR. The grant price of a SAR generally cannot be less than 100% of the fair market value of our Class A shares on the date on which the SAR is granted. The term of a SAR may not exceed 10 years. SARs may be granted in connection with, or independent of, a stock option. SARs may be paid in cash, Class A shares or a combination of cash and Class A shares, as determined by the administrator.

Restricted Shares

Restricted shares are a grant of our Class A shares subject to the restrictions on transferability and risk of forfeiture imposed by the administrator. In the discretion of the administrator, dividends distributed prior to vesting may be subject to the same restrictions and risk of forfeiture as the restricted share with respect to which the distribution was made.

Restricted Share Units

A restricted share unit is a right to receive cash, our Class A shares or a combination of cash and our Class A shares at the end of a specified period equal to the fair market value of our Class A shares on the date of vesting. Restricted share units may be subject to the restrictions, including a risk of forfeiture, imposed by the administrator.

Share Awards

A share award is a transfer of unrestricted Class A shares on terms and conditions determined by the administrator.

Dividend Equivalents

Dividend equivalents entitle an individual to receive cash, our Class A shares, other awards or other property equal in value to dividends or other distributions paid with respect to a specified number of our Class A shares. Dividend equivalents may be awarded on a free-standing basis or in connection with another award.

Other Share-Based Awards

Subject to limitations under applicable law and the terms of the LTIP, the administrator may grant other awards related to our Class A shares. Such awards may include, without limitation, awards that are convertible or exchangeable debt securities, other rights convertible or exchangeable into our Class A shares, purchase rights for our Class A shares, awards with value and payment contingent upon our performance or any other factors designated by the administrator and awards valued by reference to the book value of our Class A shares or the value of securities of, or the performance of, our affiliates.

Cash Awards

The LTIP will permit the grant of awards denominated in and settled in cash as an element of or supplement to, or independent of, any award under the LTIP.

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Substitute Awards

Awards may be granted in substitution or exchange for any other award granted under the LTIP or any other right of an eligible person to receive payment from us. Awards may also be granted under the LTIP in substitution for similar awards held by individuals who become eligible persons as a result of a merger, consolidation or acquisition of another entity or the assets of another entity by or with us or one of our affiliates.

Performance Awards

Performance awards represent awards with respect to which a participant’s right to receive cash, our Class A shares, or a combination of both, is contingent upon the attainment of one or more specified performance measures during a specified period. The administrator will determine the applicable performance period, the performance goals and such other conditions that apply to each performance award. The administrator may use any business criteria and other measures of performance it deems appropriate in establishing the performance goals applicable to a performance award.

Recapitalization

In the event of any change in our capital structure or business or other corporate transaction or event that would be considered an equity restructuring, the administrator shall or may (as required by applicable accounting rules) equitably adjust the (i) aggregate number or kind of shares that may be delivered under the LTIP, (ii) the number or kind of shares or amount of cash subject to an award, (iii) the terms and conditions of awards, including the purchase price or exercise price of awards and performance goals and (iv) the applicable share-based limitations with respect to awards provided in the LTIP, in each case to equitably reflect such event.

Change in Control

In the event of a change in control or other changes to us or our Class A shares, all outstanding awards shall immediately vest in full and, to the extent applicable, become exercisable and nonforfeitable, without the consent or approval of any holder and without any action by the administrator, unless otherwise expressly provided in an award agreement. In addition to the foregoing, the administrator, acting in its sole discretion without the consent or approval of any holder, may make any other adjustments to awards that the administrator deems appropriate to reflect the applicable transaction or event.

No Repricing

Except in connection with (i) the issuance of substitute awards granted to new service providers in connection with a transaction or (ii) in connection with adjustments to awards granted under the LTIP as a result of a transaction or recapitalization involving us, without the approval of our shareholders, the terms of outstanding option or SAR may not be amended to reduce the exercise price or grant price or to take any similar action that would have the same economic result.

Clawback

All awards granted under the LTIP are subject to reduction, cancelation or recoupment under any written clawback policy that we may adopt and that we determine must, to the extent required by applicable law, or should apply to awards under the LTIP.

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Amendment and Termination

The LTIP will automatically expire on the tenth anniversary of its effective date. The administrator may amend or terminate the LTIP at any time, subject to shareholder approval if required by applicable law, rule or regulation, including the rules of the stock exchange on which our Class A shares are listed. The administrator may amend the terms of any outstanding award granted under the LTIP at any time so long as the amendment would not materially and adversely affect the rights of a participant under a previously granted award without the participant’s consent.

Change in Control Severance Plan (the “CIC Severance Plan”)

Purpose

We intend to adopt the EagleRock Land, LLC CIC Severance Plan in connection with this offering to provide certain members of our management team with severance protection in connection with a change in control of the Company. The purpose of the CIC Severance Plan is to attract and retain talent and to assure the continuity, objectivity, and dedication of management in the event of any change in control, in order to maximize the value of the Company.

Eligible Participants

Members of the management team designated by the Administrator (which is the board or another person or committee appointed by the board) are eligible to participate in the CIC Severance Plan. The Administrator may designate additional participants from time to time. Each participant will receive a participation agreement specifying the participant’s individual severance multiplier and COBRA multiplier, which are used to calculate the participant’s severance benefits under the CIC Severance Plan.

Change in Control Protection Period

The CIC Severance Plan provides severance protections during the “Change in Control Protection Period,” which begins 180 days prior to the consummation of a change in control (the “Closing”) and ends on the date that is 18 months following the Closing. The definition of “Change in Control” under the CIC Severance Plan has the same meaning as that term in the Company’s LTIP.

Qualifying Termination

A “Qualifying Termination” under the CIC Severance Plan means a termination of the participant’s employment by the Company without “Cause” or by the participant for “Good Reason,” in each case during the Change in Control Protection Period. A termination due to death or disability does not constitute a Qualifying Termination.

“Cause” generally means, in the absence of a definition in the participant’s individual employment or severance agreement: (a) willful failure to substantially perform duties (subject to a cure period); (b) willful failure to comply with a lawful directive of the Board; (c) conviction of, or plea of guilty or nolo contendere to, a felony or crime involving moral turpitude; (d) unlawful use or possession of illegal drugs on Company premises; (e) fraud, embezzlement, or breach of fiduciary duty; or (f) material breach of any agreement with or policy of the Company (subject to a cure period, if curable).

“Good Reason” generally means, in the absence of a definition in the participant’s individual employment or severance agreement and without the participant’s consent: (a) a material reduction in base salary or target annual bonus opportunity; (b) a material diminution of the participant’s title, authority, duties, or responsibilities; or (c) a requirement that the participant relocate more than 50 miles from the participant’s then-current principal work location. Good Reason is subject to a notice

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and cure process requiring written notice within 60 days of the initial occurrence of the condition, a 30-day cure period, and resignation within 30 days following expiration of the cure period.

Severance Benefits

Upon a Qualifying Termination, and subject to the participant’s execution and non-revocation of a general release of claims, the CIC Severance Plan provides the following benefits:

•

Base Salary Severance. A lump sum cash payment equal to the participant’s Severance Multiplier multiplied by the participant’s annual base salary amount in effect on the Termination Date (or, if the participant separates from service prior to the change in control, the base salary at the time of separation).

•

Prior Year Bonus. Payment of the participant’s earned but unpaid annual bonus, if any, for the fiscal year preceding the fiscal year in which the Termination Date occurs, payable on the date when bonuses for such fiscal year are otherwise paid to the Company’s executives, but in all events within the fiscal year that includes the Termination Date.

•

Bonus Severance. A lump sum cash payment equal to the participant’s Severance Multiplier multiplied by the greater of (x) the participant’s target annual cash bonus for the fiscal year in which the Termination Date occurs and (y) the participant’s “Lookback Bonus Amount” (which is the highest actual bonus paid to or earned by the participant with respect to any of the three fiscal years immediately preceding the fiscal year in which the Qualifying Termination or change in control occurs, with any pro-rated bonuses annualized).

•

Pro-Rata Bonus. A lump sum cash payment equal to a pro-rata portion of the greater of (x) the participant’s target annual cash bonus for the fiscal year in which the Termination Date occurs and (y) the participant’s Lookback Bonus Amount, pro-rated based on the number of days employed during the fiscal year of termination.

•

COBRA Benefits. If the participant elects COBRA continuation coverage, a lump sum cash payment equal to the participant’s COBRA Multiplier multiplied by the monthly COBRA premiums for the participant and covered dependents (less the applicable active employee contribution), determined as of the Termination Date.

All cash severance payments are generally payable in a lump sum as soon as practicable following the expiration of the release revocation period, but in no event later than ten (10) days following the end of such revocation period.

Equity Award Acceleration

The CIC Severance Plan provides for automatic acceleration of all outstanding and unvested equity incentive awards held by a participant, effective upon the change in control (regardless of whether the participant’s employment is terminated). Performance-based awards will be deemed achieved at the maximum possible payout level.

If a participant’s employment is terminated without Cause or for Good Reason prior to the consummation of a change in control and such termination results in the forfeiture of unvested equity awards, and a change in control is consummated within 180 days thereafter, the participant will be entitled to receive an additional lump sum payment equal to the value of the forfeited equity awards as if such awards had remained outstanding and vested upon the change in control at the maximum payout level.

Except as modified by the CIC Severance Plan, upon a termination of employment for any reason, all outstanding equity incentive awards will be governed by the terms of the LTIP and the applicable award agreements.

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Conditions to Benefits

A participant’s entitlement to severance benefits under the CIC Severance Plan is conditioned on (a) the participant executing and delivering the participation agreement, and (b) the participant executing, and not revoking, a general release of claims in a form acceptable to the Company within the applicable time period.

Interaction with Other Severance Arrangements

Any severance payable under the CIC Severance Plan is in lieu of, and not in addition to, any severance benefits the participant would otherwise be entitled to under any other severance policy, plan, or agreement maintained by the Company (unless such policy, plan, or agreement expressly provides otherwise). Severance under the CIC Severance Plan will be reduced by any severance benefits received under an alternative severance arrangement or by operation of statute.

Administration, Amendment and Termination

The CIC Severance Plan is administered by the Administrator, which has exclusive authority to interpret the CIC Severance Plan and make all determinations regarding eligibility, benefits, and plan administration. The Company reserves the right to amend or terminate the CIC Severance Plan at any time upon at least 90 days’ advance written notice to each participant; provided that, notwithstanding anything in the CIC Severance Plan, no amendment or termination that reduces or diminishes a participant’s rights will be effective without the written consent of such participant.

Employee Share Purchase Plan (the “ESPP”)

Purpose of the ESPP

We intend to adopt the EagleRock Land, LLC ESPP in connection with this offering to provide eligible employees of the Company with an opportunity to purchase Class A shares at a reduced price through payroll deductions, thereby strengthening their commitment to the Company, motivating them, and attracting and retaining competent and dedicated persons.

Summary Features of the ESPP

The ESPP is intended to qualify as an “employee share purchase plan” under Code Section 423. During regularly scheduled offering periods under the ESPP, participants will be able to authorize payroll deductions which will be applied to purchase Class A shares at a discount to the market price and in an amount determined in accordance with the ESPP’s terms.

Term

The ESPP may be terminated by the board at any time and for any reason, subject to the terms of the ESPP. The ESPP shall automatically terminate upon the purchase by participants of all Class A shares committed to the ESPP, unless the number of shares committed to the ESPP is increased by the board and approved by the shareholders of the Company.

Eligible Participants

The ESPP provides that each employee of the Company who meets the eligibility requirements under the ESPP and are selected for participation by the Administrator (defined below), be eligible to participate with respect to an offering period if they are employed by the Company on the Grant Date (the first day of each of the offering period). Employees hired during an offering period will be eligible to participate in the next offering.

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The Administrator may exclude certain categories of employees from participating in any offering to the extent permitted by Code Section 423, including employees who have been employed less than two years, employees whose customary employment is 20 hours or less per week, employees whose customary employment is for not more than five months in any calendar year, highly compensated employees, and citizens or residents of a foreign jurisdiction where participation is prohibited under the laws of such jurisdiction or where compliance would cause the ESPP to violate the requirements of Code Section 423. In accordance with Code Section 423, no employee may be granted an option under the ESPP if immediately after the grant such employee would own shares possessing more than 5% of the total combined voting power or value of all classes of shares of the Company or any subsidiary.

Securities Offered and Terms of Participation

The maximum number of Class A shares which may be purchased by all employees under the ESPP is 5% of the outstanding Class A shares, subject to adjustments as provided in the ESPP. Any shares relating to options which are granted but which subsequently lapse, are cancelled or are otherwise not exercised by the final date for exercise, shall be available for future grants of options. As of the date hereof, no rights to purchase Class A shares have been granted under the ESPP.

Eligible employees who elect to participate in the ESPP must authorize deductions from their base compensation prior to the beginning of the applicable offering period in accordance with procedures established by the Administrator. The ESPP is implemented through a series of offering periods, with the duration and frequency of offering periods determined by the Administrator. In no event shall an offering period exceed 27 months. The option price for each offering period will be 85% of the lesser of (i) the fair market value of a Class A share on the Grant Date or (ii) the fair market value of a Class A share on the Exercise Date (the last trading day of the offering period); provided that the Administrator may establish a higher option price for a given offering. Under the ESPP, each participant will be granted, on the Grant Date, an option to purchase on the Exercise Date, at the option price, the maximum number of whole Class A shares that his or her accumulated payroll deductions on the Exercise Date will pay for at such price. The option will automatically be deemed to be exercised if the employee is still a participant on the Exercise Date.

A participating employee may authorize a payroll deduction of up to 10% of his or her base compensation received during each offering period. A participant may not change the percentage of payroll deduction during an offering period, and a participant may not make additional payments to his or her account. Further, no employee will be granted an option which permits the employee’s right to purchase Class A shares under all qualified employee share purchase plans of the Company to accrue at a rate that exceeds $25,000 in fair market value of the Class A shares (determined at the time the option is granted) for each calendar year in which such option is outstanding at any time.

A participant may, at any time on or before 15 days prior to the applicable Exercise Date (or such other date as may be selected by the Administrator), withdraw from participation in an offering by electing to withdraw all funds credited to the participant’s account. Upon such withdrawal, the participant’s option for that offering period will terminate, no further payroll deductions may be made for that offering period, and the withdrawn funds will be refunded to the participant without interest.

Administration and Amendment

The ESPP will be administered by the Administrator, which shall be our board of directors or committee consisting of not less than two directors appointed by the board. Subject to the terms of the ESPP, the Administrator will have full and absolute discretion to interpret the ESPP and all options granted under the plan, make such rules as it deems necessary for the proper administration of the

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ESPP, and to make all other determinations necessary or advisable for the administration of the ESPP. The Administrator may delegate some or all of its authority to one or more employees to the extent permitted by applicable law.

The ESPP may be amended by the board at any time and to any extent deemed advisable, including any amendment deemed necessary to ensure compliance with Section 423 of the Code. The board may also suspend the operation of the ESPP for any period. However, no amendment or suspension shall reduce any amounts previously allocated to a participant’s account, reduce a participant’s rights with respect to Class A shares previously purchased, or adversely affect a participant’s outstanding option without the participant’s agreement. Any amendment changing the aggregate number of Class A shares committed to the ESPP and any other change for which shareholder approval is required under applicable Treasury regulations must be approved by the shareholders of the Company.

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CORPORATE REORGANIZATION

•

OpCo will be formed by EagleRock;

•

Each of the Existing Owners will contribute cash to EagleRock in exchange for 109,725,365 Class B shares;

•

Each of the Shallow Valley Owners and Double Eagle will contribute certain of their subsidiaries to OpCo in exchange for 21,134,393 OpCo Units and 45,874,065 OpCo Units, respectively;

•

Each of EagleRock’s and OpCo’s operating agreements will be amended and restated to facilitate this offering;

•

Pursuant to the Warrant Exercise Agreement, each TCW Entity will exercise a portion of its L&E Warrants and forfeit the remaining portion, which will be irrevocably cancelled, immediately following which (i) L&E will distribute 14,940,269 OpCo Units and a corresponding number of Class B shares to the TCW Entities in redemption of the L&E units received in respect of the Exercised Warrants, (ii) each Warrant Agreement will terminate and (iii) each of the Rollover TCW Entities will merge with one or more newly formed subsidiaries of EagleRock and receive one Class A share in exchange for each OpCo Unit (and Class B share) it holds, or an aggregate 4,560,785 Class A shares;

•

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number of OpCo Units equal to the number of Class A shares issued pursuant to the underwriters’ option. OpCo intends to use such proceeds as described in “Use of Proceeds.”

After giving effect to the Corporate Reorganization, this offering and assuming the underwriters’ option to purchase additional Class A shares is not exercised:

•

our Existing Owners and the TCW Entities will own all 105,164,580 of our Class B shares (with 27,776,638 Class B shares held by L&E, 45,874,065 Class B shares held by Double Eagle, 21,134,393 Class B shares held by the Shallow Valley Owners and 10,379,484 Class B shares held by the TCW Entities), and the Rollover TCW Entities will own 4,560,785 of our Class A shares, collectively representing 84.3% of our common shares (with 21.3% held by L&E, 35.3% held by Double Eagle, 16.2% held by the Shallow Valley Owners and 11.5 % held by the TCW Entities);

•

investors in this offering will own 17,300,000 of our Class A shares, representing 13.3% of our common shares;

•

EagleRock will own an approximate 19.2% interest in OpCo; and

•

The diagrams under “Summary—Organizational Structure” below depict a simplified version of our organization and ownership structure immediately before and after giving effect to this offering and the Corporate Reorganization.

For further details on our agreements with OpCo and its affiliates, please see “Certain Relationships and Related Party Transactions.”

Holding Company Structure

For additional information, please see “Summary—Organizational Structure” and “Certain Relationships and Related Party Transactions—OpCo LLC Agreement.”

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our common shares that will be issued and outstanding upon the consummation of this offering, the Corporate Reorganization and the related transactions and held by:

•

each person or group known to us to be beneficial owners of more than 5% of any class of our outstanding common shares;

•

each director, director nominee and named executive officer; and

•

all of our directors and executive officers as a group.

All information with respect to beneficial ownership has been furnished by the respective more than 5% shareholders, directors, director nominees and named executive officers, as the case may be. Unless otherwise noted, the mailing address of each listed beneficial owner is c/o 9655 Katy Freeway, Suite 375, Houston, Texas 77024. The following table does not reflect any of the Class A shares that more than 5% shareholders, directors and named executive officers may purchase in this offering through the directed share program described in “Underwriting—Directed Share Program.”

To the extent that the underwriters sell more than 17,300,000 Class A shares, the underwriters have the option to purchase up to an additional 2,595,000 Class A shares from us. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional Class A shares. The table below does not reflect any shares to be issued pursuant to the LTIP.

The amounts and percentages of common shares beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power, which includes the power to vote or direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest. Except as otherwise indicated in these footnotes, each of the persons or entities listed below has, to our knowledge, sole voting and investment power with respect to all common shares beneficially owned by them, except to the extent this power may be shared with a spouse.


Name of Beneficial Owner	Shares Beneficially Owned Before this Offering					Shares Beneficially Owned After this Offering (No Exercise)															Shares Beneficially Owned After this Offering (Full Exercise)
	Shares Beneficially Owned Before this Offering					Class A Shares					Class B Shares⁽¹⁾					Combined Voting Power⁽²⁾					Class A Shares					Class B Shares⁽¹⁾					Combined Voting Power⁽²⁾
	Number		%			Number		%			Number		%			Number		%			Number		%			Number		%			Number		%
5% Shareholders:
Lea & Eddy Holdings, LLC⁽³⁾		N/A		100	%		—		—			27,776,638		26.4	%		27,776,638		21.3	%		—		—			27,776,638		26.4	%		27,776,638		20.9	%
Double Eagle IV Midco, LLC⁽⁴⁾		—		—			—		—			45,874,065		43.6	%		45,874,065		35.3	%		—		—			45,874,065		43.6	%		45,874,065		34.6	%
Charles R. Wiggins⁽⁵⁾		—		—			—		—			8,430,923		8.0	%		8,430,923		6.5	%		—		—			8,430,923		8.0	%		8,430,923		6.4	%
TCW Entities⁽⁶⁾		—		—			4,560,785		18.3	%		10,379,484		9.9	%		14,940,269		11.5	%		4,560,785		16.6	%		10,379,484		9.9	%		14,940,269		11.3	%

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Name of Beneficial Owner	Shares Beneficially Owned Before this Offering				Shares Beneficially Owned After this Offering (No Exercise)															Shares Beneficially Owned After this Offering (Full Exercise)
	Shares Beneficially Owned Before this Offering				Class A Shares					Class B Shares⁽¹⁾					Combined Voting Power⁽²⁾					Class A Shares					Class B Shares⁽¹⁾					Combined Voting Power⁽²⁾
	Number		%		Number		%			Number		%			Number		%			Number		%			Number		%			Number		%
Directors, Director Nominees and Named Executive Officers:
Greg Pipkin Jr.		—		—		1,283,097		5.1	%		—		—			1,283,097		*			1,283,097		4.7	%		—		—			1,283,097		*
Neal H. Shah		—		—		1,283,097		5.1	%		—		—			1,283,097		*			1,283,097		4.7	%		—		—			1,283,097		*
Robert W. Hunt Jr.		—		—		533,440		2.1	%		—		—			533,440		*			533,440		1.9	%		—		—			533,440		*
Richard H. Coats⁽⁷⁾		—		—		—		—			9,514,047		9.0	%		9,514,047		7.3	%		—		—			9,514,047		9.0	%		9,514,047		7.2	%
Raj Kumar		—		—		—		—			—		—			—		—			—		—			—		—			—		—
Jeff S. Lott		—		—		—		—			—		—			—		—			—		—			—		—			—		—
James C. Nelson		—		—		—		—			—		—			—		—			—		—			—		—			—		—
Stephanie Reed		—		—		—		—			—		—			—		—			—		—			—		—			—		—
Michael W. Wallace		—		—		—		—			—		—			—		—			—		—			—		—			—		—
Directors, Director Nominees and Executive Officers as a Group (9 Persons)		—		—		3,099,634		12.4	%		9,514,047		9.0	%		12,613,681		9.7	%		3,099,634		11.2	%		9,514,047		9.0	%		12,613,681		9.5	%

*	Less than 1%.

(1)

Subject to the terms of the OpCo LLC Agreement, OpCo Unitholders (other than us) will have the right to redeem all or a portion of their OpCo Units for Class A shares (or cash, at OpCo’s election) at a redemption ratio of one Class A share for each OpCo Unit redeemed. In connection with any such redemption of OpCo Units, a corresponding number of Class B shares will be cancelled. Please see “Certain Relationships and Related Party Transactions—OpCo LLC Agreement.” Beneficial ownership of OpCo Units is not reflected as beneficial ownership of our Class A shares for which such OpCo Units may be redeemed.

(2)

Represents percentage of voting power of our Class A shares and Class B shares voting together as a single class. OpCo Unitholders will hold one Class B share for each OpCo Unit that they own. Each Class B share has no economic rights, but entitles the holder thereof to one vote for each OpCo Unit held by such holder. Accordingly, OpCo Unitholders collectively have a number of votes in us equal to the number of OpCo Units that they hold.

(3)

Lea & Eddy Holdings, LLC is managed by a board of managers consisting of Dale Redman, Gregory Mabee, Elo Peter Omavuezi, Jason Andreotes and Josh Brandt. No single manager has unilateral voting or dispositive authority over the shares held by Lea & Eddy Holdings, LLC, and all material decisions, including decisions regarding voting and disposition of the Class A shares, require approval by a majority of the board of managers. The address of Lea & Eddy Holdings, LLC is 413 Veterans Airpark Lane, Suite 200, Midland, Texas 79705.

(4)

Double Eagle IV Midco, LLC is controlled by its sole member Double Eagle IV Pledgeco, LLC, a Delaware limited liability company, which is controlled by its sole member, Double Eagle Energy Holdings IV, LLC, a Delaware limited liability company, which is in turn controlled by EnCap Energy Capital Fund XI, L.P., a Texas limited partnership (“EnCap Fund XI”). EnCap Fund XI is controlled by its general partner, EnCap Equity Fund XI GP, L.P., a Texas limited partnership (“EnCap Fund XI GP LP”), which is controlled by its general partner, EnCap Equity Fund XI GP, LLC, a Delaware limited liability company (“EnCap Fund XI GP LLC”), which is controlled by its sole member, EnCap Investments L.P., a Delaware limited partnership (“EnCap Investments LP”), which is controlled by its general partner, EnCap Investments GP, L.L.C., a Delaware limited liability company (“EnCap Investments GP”), which is controlled by its sole member, EnCap Investments Holdings, LLC, a Delaware limited liability company (“EnCap Investments Holdings”), which is controlled by its managing member, EnCap Partners, LP, a Delaware limited partnership (“EnCap Partners LP”), which is controlled by its general partner, EnCap Partners GP, LLC, a Delaware limited liability company (“EnCap Partners GP,” together with EnCap Partners LP, EnCap Investments Holdings, EnCap Investments GP, EnCap Investments LP, EnCap Fund XI GP LLC, and EnCap Fund XI GP LP, the “EnCap Entities”). EnCap Partners GP is managed by its managing members, David B. Miller, Gary R. Petersen, D. Martin Phillips, Robert L. Zorich, Jason M. DeLorenzo and Douglas E. Swanson, Jr., each of which may be deemed to beneficially own the listed securities. The address for the EnCap Entities is 9651 Katy Freeway, Suite 600, Houston, Texas 77024. The address of Double Eagle IV Midco, LLC is 3724 Hulen Street, Fort Worth, Texas 76107.

(5)	The address of Charles R. Wiggins is 500 W. Illinois Avenue, Suite 620, Midland, Texas 79701.

(6)

The funds and accounts managed by TCW include TCW DL HDR LLC, TCW Direct Lending Structured Solutions 2022 LLC, TCW Direct Lending Structured Solutions 2019 LLC, TCW Brazos Fund LLC, TCW Skyline Lending LP, TCW DL HDR-S LLC, TCW WV Financing LLC, TCW Direct Lending Private Fund VIII LP, Safety National Casualty Corporation, Reliance Standard Life Insurance Company, Philadelphia Indemnity Insurance Company and TCW Marina SL LLC. Voting and dispositive control of the securities held by each of the TCW Entities is exercised by the investment committee for the Private Credit Group (the “PCG IC”) of TCW. The PCG IC is comprised of Richard Miller, David Wang, Ryan Carroll, Mark Gertzof, Suzanne Grosso, James Synborski and Jim Bold. The PCG IC acts by majority consent and thus, in accordance with the “rule of three,” none of the members of the PCG IC is deemed to be a beneficial owner of the securities held by each of the TCW Entities. TCW disclaims beneficial ownership of the securities held by the TCW Entities except to the extent of any pecuniary interest it may have therein. The address of TCW Asset Management Company LLC is 200 Clarendon Street, 51^st Floor, Boston, Massachusetts 02116.

(7)	Includes (i) 8,770,300 Class B shares held directly by Richard H. Coats and (ii) 743,747 Class B shares held by Cactus Energy, Inc., of which Mr. Coats is the president and sole director. The address of Mr. Coats is 400 N. Marienfeld Street, Midland, Texas 79701.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

OpCo LLC Agreement

The OpCo LLC Agreement is filed as an exhibit to the registration statement of which this prospectus forms a part, and the following description of the OpCo LLC Agreement is qualified in its entirety by reference thereto.

Following this offering, under the OpCo LLC Agreement, each holder of an OpCo Unit (other than EagleRock) will, subject to certain limitations, have the Redemption Right to cause OpCo to acquire all or a portion of its OpCo Units (along with the cancellation of a corresponding number of our Class B shares) for, at OpCo’s election, (i) Class A shares at a redemption ratio of one Class A share for each OpCo Unit redeemed, subject to applicable conversion rate adjustments, or (ii) cash in an amount equal to the Cash Election Amount of such Class A shares. Each redemption must involve at least 150,000 OpCo Units (or all OpCo Units then held by the redeeming holder, if less than 150,000), and redemptions may generally be exercised no more frequently than once per calendar quarter. More frequent redemptions are permitted in connection with a registered offering pursuant to the Registration Rights Agreement or a Rule 10b5-1 trading plan that has been approved by the Managing Member. Redemptions will also be subject to the conditions, timing, notice and other procedural requirements set forth in the OpCo LLC Agreement and applicable law, which may include blackout periods or other restrictions to ensure compliance with securities and other regulatory requirements. OpCo will determine whether to issue Class A shares or pay cash in an amount equal to the Cash Election Amount in lieu of the issuance of Class A shares based on facts in existence at the time of the decision, which we expect would include the relative value of the Class A shares (including the trading price for the Class A shares at the time), the cash purchase price, the availability of other sources of liquidity (such as an issuance of additional common shares) to acquire the OpCo Units and alternative uses for such cash. Alternatively, upon the exercise of the Redemption Right, we (instead of OpCo) will have the Call Right to, for administrative convenience, acquire each tendered OpCo Unit directly from an OpCo Unitholder for, at our election, (x) one Class A share, subject to applicable conversion rate adjustments, or (y) cash in an amount equal to the Cash Election Amount of such Class A shares. We may exercise the Call Right only if an OpCo Unitholder first exercises its Redemption Right, and an OpCo Unitholder may exercise its Redemption Right beginning immediately following the consummation of this offering, subject to certain limitations in the OpCo LLC Agreement and the expiration of lock-up restrictions. As the sole managing member of OpCo, our decision to pay the Cash Election Amount upon an exercise of the Redemption Right or Call Right may be made by a conflicts committee consisting solely of independent directors. In connection with any redemption of OpCo Units pursuant to the Redemption Right or acquisition of OpCo Units pursuant to the Call Right, a corresponding number of Class B shares held by the redeeming OpCo Unitholder will be automatically cancelled. Redemptions and exchanges will reduce the number of OpCo Units held by persons other than us, increase our direct ownership in OpCo and, to the extent settled in Class A shares, increase the number of publicly traded Class A shares outstanding and, upon the resale of such shares by Existing Owners, the public float.

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or amount of related deductions, and we may not prevail in any such challenge. Any realization of tax benefits may also be affected by future changes in tax law.

As the OpCo Unitholders cause their OpCo Units to be redeemed, holding other assumptions constant, our membership interest in OpCo will be correspondingly increased, the number of Class A shares outstanding will be increased, and the number of Class B shares will be decreased.

“Cash Election Amount” means, with respect to the Class A shares to be delivered to the redeeming OpCo Unitholder by OpCo pursuant to the Redemption Right or the Call Right, as applicable, (i) the amount of cash that would be received if the number of Class A shares to which the redeeming OpCo Unitholder would otherwise be entitled were sold at a per share price equal to the trailing 10-day volume weighted average price of a Class A share on such redemption date, net of actual or deemed offering expenses or (ii) if the Class A shares no longer trade on a securities exchange or automated or electronic quotation system, an amount equal to the Fair Market Value (as defined in the OpCo LLC Agreement) of one Class A share that would be obtained in an arm’s-length transaction for cash between an informed and willing buyer and an informed and willing seller, neither of whom is under any compulsion to buy or sell and without regard to the particular circumstances of the buyer or seller.

Under the OpCo LLC Agreement, subject to the obligation of OpCo to make tax distributions and to reimburse us for our corporate and other overhead expenses, we will have the right to determine when dividends will be paid to the OpCo Unitholders and the amount of any such dividends.

Following this offering, if we authorize dividends, such dividends will be paid to the OpCo Unitholders generally on a pro rata basis in accordance with their respective percentage ownership of OpCo Units.

The OpCo Unitholders, including us, will be allocated their proportionate share of any taxable income or loss of OpCo pursuant to the OpCo LLC Agreement and will generally incur U.S. federal, state and local income taxes on their proportionate share of any net taxable income of OpCo. Net profits and net losses of OpCo generally will be allocated to OpCo Unitholders on a pro rata basis in accordance with their respective percentage ownership of OpCo Units, except that certain non-pro rata adjustments will be required to be made to reflect built-in gains and losses and tax depletion, depreciation and amortization with respect to such built-in gains and losses. The OpCo LLC Agreement will provide, to the extent cash is available and subject to the terms of any current or future debt or other arrangements, for pro rata tax distributions to the OpCo Unitholders in an amount generally intended to allow such holders to satisfy their respective income tax liabilities with respect to their allocable share of the income of OpCo, based on certain assumptions and conventions, provided that the distribution will be sufficient to allow us to satisfy our actual tax liabilities.

The OpCo LLC Agreement will provide that, except as otherwise determined by us or in connection with the exercise of the Call Right, at any time we issue a Class A share or any other equity

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security, the net proceeds received by us with respect to such issuance, if any, shall be concurrently invested in OpCo, and OpCo shall issue to us one OpCo Unit or other economically equivalent equity interest. Conversely, if at any time any Class A shares are redeemed, repurchased or otherwise acquired, OpCo shall redeem, repurchase or otherwise acquire an equal number of OpCo Units held by us, upon the same terms and for the same price, as the Class A shares are redeemed, repurchased or otherwise acquired.

Under the OpCo LLC Agreement, the members have agreed that our Existing Owners and their affiliates will be permitted to engage in business activities or invest in or acquire businesses that may compete with our business or do business with any client of ours.

Registration Rights Agreement

In connection with the closing of this offering, we will enter into a registration rights agreement with our Existing Owners and the TCW Entities (the “Registration Rights Agreement”) pursuant to which we will agree to register under the federal securities laws the offer and resale of all Class A shares owned by or underlying the Class B shares and OpCo Units owned by our Existing Owners or the TCW Entities or certain of their affiliates or permitted transferees. The Registration Rights Agreement will provide that, after the expiration of the lock-up period, any Holder (as defined in the Registration Rights Agreement) may request a demand registration or underwritten offering, provided that the Registrable Securities (as defined in the Registration Rights Agreement) to be included in such registration or offering have an aggregate value of at least $50 million (based on the volume weighted average price for the five trading days immediately preceding the date of the request). Additionally, certain of the Existing Owners and the TCW Entities will be subject to an additional lock-up period (the “Special Lock-Up”) expiring on the earliest to occur of (i) the date on which Double Eagle and the Shallow Valley Owners have collectively sold securities for aggregate gross proceeds of $300 million, (ii) 18 months following the date of the Registration Rights Agreement and (iii) the date on which Double Eagle terminates the Special Lock-Up in its sole discretion. Subject to certain exceptions, if at any time we propose to register an offering of Class A shares or conduct an underwritten offering, regardless of whether for our own account, then we must notify the Holders of such proposal, to allow them to include a specified number of their Class A shares in that registration statement or underwritten offering, as applicable, including Class A shares issuable upon the exchange of the OpCo Units and the cancellation of a corresponding number of our Class B shares.

We may suspend offers and sales under a shelf registration statement for up to 60 days per occurrence if our board of directors determines that a postponement is in our best interest due to a pending transaction, compliance with applicable securities laws, or to preserve material confidential information, provided that no such suspension periods may continue for more than 90 days in the aggregate during any consecutive 12-month period.

We will bear all registration expenses (excluding selling expenses such as underwriting discounts, selling commissions and stock transfer taxes), including fees and expenses of all persons retained by us, and the fees and expenses of one law firm of national standing selected by the Holders owning the majority of the Registrable Securities to be included in any such registration or offering. Any sales in the public market of our Class A shares registrable pursuant to the Registration Rights Agreement could adversely affect prevailing market prices of our Class A shares. See “Risk Factors—Risks Related to this Offering, Our Corporate Structure and Our Class A Shares—The market price of our Class A shares could be adversely affected by sales of substantial amounts of our Class A shares in the public or private markets or the perception in the public markets that these sales may occur, including sales by the Existing Owners after the exercise of the Redemption Right.”

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Contribution Agreement

General

In connection with the consummation of this offering, our Existing Owners and certain of their affiliates (the “Contributors”) will enter into a contribution and assignment agreement (the “Contribution Agreement”) that will govern the consummation of the Corporate Reorganization, including (i) the contribution by L&E of all of its subsidiaries (other than Hydrosource) to OpCo in exchange for OpCo Units and OpCo’s assumption of the Predecessor Credit Facility, (ii) the contribution by the Shallow Valley Owners and Double Eagle of certain of their subsidiaries to OpCo in exchange for OpCo Units and (iii) the amendment and restatement of EagleRock’s and OpCo’s operating agreements, as described in more detail in “Corporate Reorganization.”

The Contribution Agreement will be entered into by and among EagleRock, OpCo and the Existing Owners and certain of their affiliates, and will govern a series of transactions to combine the Contributors’ respective businesses into OpCo in connection with this offering. Pursuant to the Contribution Agreement, each Contributor will form or designate a holding company subsidiary, effect multi-survivor mergers to consolidate specified assets into those holding companies and then contribute all of the equity interests in such holding companies to OpCo in exchange for OpCo Units and Class B Shares. As part of the transactions contemplated by the Contribution Agreement, L&E will distribute Hydrosource to Hydrosource Midstream, LLC, which is not owned or controlled by us, and following which we will not control, be controlled by or be under common control with Hydrosouce. The Contribution Agreement includes customary representations and warranties by each Contributor, on a several and not joint basis, regarding organization, authority, title to assets, compliance with laws, taxes, environmental matters, material contracts and financial statements, among others. It also contains interim operating covenants restricting the Contributors’ conduct of business prior to closing, mutual obligations regarding Hart-Scott-Rodino Antitrust Improvements Act of 1976 compliance and provisions appointing a designated committee to oversee and make all decisions in connection with this offering. The Contribution Agreement may be terminated by mutual consent, for material breach, if the closing of this offering has not occurred by September 30, 2026, or upon termination by the designated person prior to this offering, and is governed by the laws of the State of Texas.

The Contribution Agreement provides that each Contributor, severally and not jointly, will indemnify us, OpCo and our respective subsidiaries against losses based on, arising out of or resulting from:

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a breach or inaccuracy of such Contributor’s representations and warranties set forth in the Contribution Agreement;

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(i) any affidavits (including non-imputation affidavits), certificates, information (including financial data), lien waivers and instruments of indemnification (including a so-called “gap” indemnification), and other documentation executed and delivered by such Contributor or such Contributor’s contributed entities as shall be required by the designated title company to induce such title company to issue policies of title insurance on our acreage or (ii) the inability of such title company to issue a title policy with respect to such Contributor’s contributed real property interests; and

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any of such Contributor’s tax obligations related to the transactions contemplated by the Contribution Agreement.

Shareholder’s Agreements

In connection with the closing of this offering, we and each of our Existing Owners will enter into a Shareholder’s Agreement.

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The Shareholder’s Agreements will provide that, subject to compliance with applicable law and NYSE and NYSE Texas rules, for so long as an Existing Owner, and its affiliates and certain transferees, beneficially owns at least 30%, 20% and 10% of our outstanding common shares, such Existing Owner shall be entitled to designate three directors, two directors and one director, respectively, for nomination to our board of directors. The board of directors is expected to initially consist of seven directors. If the size of the board of directors is increased or decreased to other than seven directors, each Existing Owner’s nomination rights will be proportionately increased or decreased, respectively, rounded to the nearest whole number; provided that such adjustment will not reduce the number of directors an Existing Owner is entitled to nominate to fewer than the number set forth above, as long as such Existing Owner, and such affiliates and transferees, maintain the required beneficial ownership thresholds.

Of the directors designated by each of L&E and Double Eagle, at least two of each such Existing Owner’s director designees (or if such Existing Owner is designating only one director, such Existing Owner’s sole designee) must qualify as “independent” for the purposes of serving on the Audit Committee pursuant to the rules of the New York Stock Exchange and the Securities and Exchange Commission, as determined by the board of directors.

So long as an Existing Owner is entitled to designate one or more nominees to the board and notifies the board of directors of its desire to remove, with or without cause, any director previously designated by it to the board, we are required to take all necessary action to cause such removal.

The Shareholder’s Agreements will prohibit each Existing Owner from granting any proxy or entering into or agreeing to be bound by any voting trust, agreement or arrangement with respect to its common shares if and to the extent the terms thereof conflict with the provisions of the Shareholder’s Agreements.

Each Shareholder’s Agreement with an Existing Owner will terminate when the applicable Existing Owner no longer holds board designation rights.

Voting Agreements

In connection with this offering, we and each Existing Owner will enter into a Voting Agreement pursuant to which each Existing Owner, and certain of its transferees, will agree with us to vote all of the common shares that it owns in favor of all director nominees recommended for election by our board of directors. In the event an Existing Owner fails to vote as required by its Voting Agreement, the agreement grants an irrevocable proxy to our President and Chief Financial Officer and General Counsel to vote such Existing Owner’s common shares in accordance with the Voting Agreement. The Voting Agreement does not restrict an Existing Owner’s ability to sell, transfer or pledge its common shares. Each Voting Agreement with an Existing Owner will terminate upon the earliest to occur of: (a) the date on which such Existing Owner no longer beneficially owns any common shares subject to the Voting Agreement; (b) the mutual written consent of the parties; and (c) the date on which no Existing Owner has designation rights pursuant to a Shareholder’s Agreement.

Produced Water Recycling Rights Agreement with Hydrosource

In connection with this offering, we will enter into the Hydrosource Recycling Agreement with Hydrosource, a wholly owned subsidiary of an entity that shares common ownership with L&E, one of our Existing Owners. Prior to this offering, there were no transactions pursuant to such agreement. The Hydrosource Recycling Agreement will be entered into concurrently with the closing of this offering and will govern our royalty revenue relationships with Hydrosource on a go-forward basis. This new agreement was negotiated in connection with this offering and is not an amendment or continuation of

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a historical arrangement. We do not own or control Hydrosource and following the Corporate Reorganization, we will not control, be controlled by or be under common control with Hydrosource. For more information, see “Business—Customers; Material Contracts and Marketing—Material Contracts and Marketing—Produced Water Recycling Rights

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EagleRock Land, LLC S-1/A