As filed with the U.S. Securities and Exchange Commission on July 28, 2026

Registration Statement No. 333-          

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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Form S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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PBT Land and Minerals, Inc.
(Exact name of registrant as specified in its charter)

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400 Pine Street, Suite 1010
Abilene, TX, 79601
(325) 677-6177
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

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Eric L. Oliver
c/o SoftVest Advisors, LLC
400 Pine Street, Suite 1010
Abilene, TX, 79601
(325) 677-6177
(Name, address, including zip code, and telephone number, including area code, of agent for service)

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Copies of all communications, including communications sent to agent for service, should be sent to:

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Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective and all other conditions to the proposed business combination described in the enclosed proxy statement/prospectus have been satisfied or waived.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, 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(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or 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. ☐

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Issuer Tender Offer) ☐

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer) ☐

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

The information in this proxy statement/prospectus is not complete and may be changed. We may not sell the securities offered by this proxy statement/prospectus until the registration statement filed with the Securities and Exchange Commission is effective. This proxy statement/prospectus does not constitute an offer to sell or a solicitation of an offer to buy any securities in any jurisdiction where an offer, solicitation or sale is not permitted.

PRELIMINARY — SUBJECT TO COMPLETION — DATED JULY 28, 2026

SPECIAL MEETING OF HOLDERS OF UNITS OF BENEFICIAL INTEREST
OF
PERMIAN BASIN ROYALTY TRUST

PBT Land and Minerals, Inc., a newly-formed Texas corporation (together with its subsidiaries, unless otherwise indicated or the context otherwise requires, “New PBT,” “we,” “us” or “our”) is furnishing this proxy statement/prospectus and enclosed proxy card (the “Proxy Card”) to holders of units of beneficial interest (the “Trust Units”) of the Permian Basin Royalty Trust (the “Trust,” and such holders, “Unitholders”), in connection with the solicitation of proxies for use at the special meeting of Unitholders scheduled to be held on            , 2026 at            Central Time, at the offices of Argent Trust Company, 4200 South Hulen Street, Suite 217, Fort Worth, Texas 76109 (such meeting, together with any adjournments, continuations or postponements thereof, and any meeting called in lieu thereof, the “Special Meeting”).

New PBT is an affiliate of SoftVest, L.P. (“SoftVest, L.P.”), a Unitholder that beneficially owns in the aggregate approximately 13.3% of the outstanding Trust Units. SoftVest, L.P. created New PBT to facilitate the business combination described below and owns New PBT solely for that purpose.

SoftVest has requested the Special Meeting for Unitholders to consider and vote on an amendment to the Trust’s Royalty Trust Indenture (the “Indenture Amendment”) that would permit consummation of a business combination (the “Business Combination”) whereby New PBT would acquire (i) a majority of the assets and liabilities of the Trust and (ii) approximately 68,000 acres of surface estate and a 15% effective royalty interest associated with certain acreage and certain mineral interests owned directly or indirectly by Blackbeard Holdings, LLC (“Blackbeard Holdings”). Blackbeard Operating, LLC, a subsidiary of Blackbeard Holdings, is the operator of oil and gas interests in the Waddell Ranch, in Crane County, Texas, in which the Trust currently holds a 75% net overriding royalty interest (equivalent to a net profits interest), which represents most of the value of the Trust. A copy of the proposed Indenture Amendment is attached to this proxy statement/prospectus as Annex A.

As a part of the proposed Business Combination, (i) the Trust will terminate and Unitholders will receive one share of Class A common stock, par value $0.0001 per share, of New PBT (“Class A Shares”) for each Trust Unit they own, (ii) the Trust’s 75% net overriding royalty interest in the Waddell Ranch oil and gas interests will effectively be converted into a cost-free 15% effective royalty interest that will be owned by New PBT and that eliminates cost exposure associated with the development and production of oil and gas and is expected to generate more predictable and consistent cash flow for Unitholders going forward as investors in New PBT and (iii) the Trust’s interest in the Waddell Ranch Properties, which currently underlies the net profits interest (“NPI”) structure, will be transferred to Blackbeard Operating through the Unburdened Mineral Interest Lease (as defined herein), resulting in Blackbeard Operating assuming all operating costs and capital obligations associated with the interest while New PBT retains the cost-free royalty interest described above. In addition, New PBT is expected to derive additional revenue from all operations on lands that will be owned by New PBT going forward. This provides meaningful diversification beyond oil and gas royalties alone and contributes significant real assets to the business of New PBT.

Following the Business Combination, New PBT will be organized in a structure that is commonly referred to as an “Up-C” structure. New PBT will be a holding company, the sole material assets of which will consist of units of its subsidiary PBT Land and Minerals OpCo, LLC (“OpCo” and such units, “OpCo units”). OpCo LLC in turn will directly or indirectly own the operating subsidiaries through which New PBT will conduct its business. New PBT 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 the financial results of OpCo and its subsidiaries.

Class A Shares, which Unitholders will receive, are expected to be listed for trading on the New York Stock Exchange (the “NYSE”) and NYSE Texas under the symbol “PBT”. If the Business Combination is completed, the Trust will terminate, and the Trust Units will no longer be listed on the NYSE and will be deregistered under the Exchange Act. The OpCo units and corresponding shares of Class B common stock, par value $0.0001 per share, of New PBT (“Class B Shares” and, together with the Class A Shares, the “New PBT Common Stock”) will not be traded on an exchange.

As part of the Business Combination and the Blackbeard and Greybeard Subscription (as defined below), Blackbeard Security Holdings, LLC, a subsidiary of Blackbeard Holdings (“Blackbeard Security”), and Greybeard Energy LLC, an affiliate of Blackbeard Holdings (“Greybeard Energy”), will receive a combination of (i) Class A Shares, and (ii) OpCo units and a corresponding number of Class B Shares.

ADDITIONAL INFORMATION

The Trust files annual, quarterly and current reports and other business and financial information with the Securities and Exchange Commission (the “SEC”), and the SEC maintains a website located at http://www.sec.gov containing this information. You can also obtain these documents, free of charge from the Trust, at http://www.pbt-permian.com. The information contained on, or that may be accessed through, the Trust’s website is not incorporated by reference into, and is not a part of, this proxy statement/prospectus.

This proxy statement/prospectus incorporates important business and financial information about the Trust from documents that are not attached to this proxy statement/prospectus. This information is available to you without charge upon your request. You can obtain the documents incorporated by reference into this proxy statement/prospectus free of charge by requesting them in writing or by telephone from New PBT’s proxy solicitor at the following address and telephone number:

D.F. King & Co., Inc.

28 Liberty Street, 53rd Floor

New York, NY 10005

Holders may call toll-free: (877) 283-0318
Banks and brokers call: (212) 784-6885

If you would like to request any documents, please do so by            , 2026, which is five business days prior to the date of the Special Meeting, in order to receive them before the Special Meeting.

For a more detailed description of the information incorporated by reference into this proxy statement/prospectus and how you may obtain it, please see the section entitled “Where You Can Find More Information.”

Notwithstanding the incorporation by reference of Trust filings and business and financial information hereby, neither the Trust nor the Trustee are making a solicitation in this proxy statement/prospectus, nor are they offering any securities in this proxy statement/prospectus.

ABOUT THIS DOCUMENT

This document, which forms part of a registration statement on Form S-4 (Registration No. 333-            ) filed with the SEC by New PBT, constitutes the prospectus of New PBT under the Securities Act of 1933, as amended, with respect to the Class A Shares to be issued to the Trust and distributed pro rata to the Unitholders pursuant to the Combination Agreement. This document also constitutes a proxy statement under the Securities Exchange Act of 1934, as amended, with respect to the Special Meeting of Unitholders.

You should rely only on the information contained in or incorporated by reference into this proxy statement/prospectus. No one has been authorized to provide you with information that is different from that contained in, or incorporated by reference into, this proxy statement/prospectus. This proxy statement/prospectus is dated            , 2026. The information contained in this proxy statement/prospectus is accurate only as of that date or, in the case of information in a document incorporated by reference, as of the date of such document, unless the information specifically indicates that another date applies. Neither the mailing of this proxy statement/prospectus to Unitholders nor the issuance by New PBT of Class A Shares and Class B Shares and the issuance by OpCo of OpCo units pursuant to the Combination Agreement will create any implication to the contrary.

This proxy statement/prospectus does not constitute an offer to sell, or a solicitation of an offer to buy, any securities, or the solicitation of a proxy, in any jurisdiction in which or from any person to whom it is unlawful to make any such offer or solicitation in such jurisdiction.

The information concerning the Trust contained in this proxy statement/prospectus or incorporated by reference has been provided by the Trust, and the information concerning Blackbeard and its affiliates contained in this proxy statement/prospectus has been provided by Blackbeard. Notwithstanding the inclusion of information regarding the Trust hereby, neither the Trust nor the Trustee are making a solicitation in this proxy statement/prospectus, nor are they offering any securities in this proxy statement/prospectus.

HELPFUL INFORMATION

As used herein and unless otherwise specifically indicated, the following terms have the meanings set forth below:

Bbl.    One stock tank barrel, of 42 U.S. gallons liquid volume, used in this proxy statement/prospectus in reference to crude oil or other liquid hydrocarbons.

Blackbeard.    Blackbeard Holdings and its subsidiaries, but excluding USLG Legacy.

Blackbeard Holdings.    Blackbeard Holdings, LLC, a Delaware limited liability company indirectly owned by NGP and members of Blackbeard Holdings’ management.

Blackbeard Operating.    Blackbeard Operating, LLC, a Delaware limited liability company and subsidiary of Blackbeard Holdings, which is a large privately held and vertically integrated energy producer in the Permian Basin in West Texas.

Blackbeard Parties.    Blackbeard Holdings, Blackbeard Security and Greybeard Energy, collectively.

Blackbeard Security.    Blackbeard Security Holdings, LLC, a Texas limited liability company and affiliate of Blackbeard Holdings.

Blackbeard Transferred Entities.    MineralCo, USLG ExCo, USLG Legacy, and their respective Subsidiaries (if any).

Boe.    Barrel of oil equivalent.

Btu.    British thermal unit, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit.

CBP.    Central Basin Platform.

Class A Shares.    Shares of Class A common stock, par value $0.0001 per share, of New PBT.

Class B Shares.    Shares of Class B common stock, par value $0.0001 per share, of New PBT.

Closing.    The Blackbeard Contribution Closing (as defined in the Combination Agreement included as Annex B hereto).

Closings.    The PBT Contribution Closing and the Blackbeard Contribution Closing (as defined in the Combination Agreement included as Annex B hereto), together.

Closing Date.    The date on which Closing occurs.

Code.    The Internal Revenue Code of 1986, as amended.

Combination Agreement.    The Combination Agreement, dated as of July 28, 2026, by and among New PBT, New PBT Sub, OpCo, Blackbeard Holdings, Blackbeard Security, and Greybeard Energy.

Credit Facilities.    The (a) Credit Agreement dated as of August 29, 2019, by and among Blackbeard Operating, as borrower, the lenders from time to time party thereto and JPMorgan Chase Bank, N.A., as administrative agent, as amended, modified or supplemented from time to time (the “BBO Credit Facility”), (b) Credit Agreement dated as of March 31, 2025, by and among Greybeard Holdings, as borrower, the lenders from time to time party thereto and BOKF, NA dba Bank of Texas, as administrative agent, as amended, modified or supplemented from time to time (the “Greybeard Credit Facility”) and (c) Credit Agreement dated as of June 1, 2026, by and among USLG Legacy, as borrower, the lenders from time to time party thereto and JPMorgan Chase Bank, N.A., as administrative agent, as amended, modified or supplemented from time to time, as the context may require (the “JPM Credit Facility”).

Credit Facility Consents.    Collectively, any consents and/or amendments required under the Credit Facilities with respect to the transactions contemplated under the Combination Agreement.

Cutlass Sands Ranch.    Approximately 14,300 surface acres in Crane County, Texas owned by USLG.

DUCs.    Drilled-but-uncompleted production wells.

E&P.    Exploration & Production segment of the oil and gas industry.

Exchange Act.    Securities Exchange Act of 1934, as amended.

Greybeard Assets.    Hydrocarbon mineral interests, fee mineral interests, royalty interests, leases, servitudes, and related contracts held by Greybeard Energy that will be transferred to New PBT in connection with Closing, including 2,300 NRAs located in the Permian Basin in West Texas.

Greybeard Energy.    Greybeard Energy, LLC, a Delaware limited liability company.

Greybeard Holdings.    Greybeard Holdings, LLC, a Delaware limited liability company.

Greybeard-OpCo Contribution.    The contribution to OpCo by, and OpCo unit issuance to, Greybeard Energy described in the Combination Agreement.

Hilcorp.    Hilcorp Permian CT TXNM, LLC, a Delaware limited liability company.

Hilcorp Acquisition.    The acquisition by Blackbeard Operating and USLG Legacy of certain assets held by Hilcorp, which closed on May 30, 2025.

Hilcorp Assets.    40,400 NRAs and 14,300 surface acres located in the Permian Basin primarily in Crane County, Texas that were acquired as part of the Hilcorp Acquisition.

Horizon Kinetics.    Horizon Kinetics Asset Management LLC.

Intended Tax Treatment.    With respect to, (i) the PBT-NewCo Contribution, the Blackbeard Security-NewCo Contribution and the Greybeard-NewCo Contribution, taken together and with any cash purchases of Class A Shares by Unitholders pursuant to exercises of Subscription Rights (including pursuant to the Backstop Agreement), a transaction described in Section 351(a) of the Code, (ii) the NewCo-NewCo Sub Contribution a transaction described in Section 351(a) of the Code, (iii) the Section 1031 Exchange as a like-kind exchange under Section 1031 of the Code, and (iv) each of the NewCo-OpCo Contribution, the NewCo Sub-OpCo Contribution, the Blackbeard Security-OpCo Contribution, and the Greybeard-OpCo Contribution as a contribution of property described in Section 721(a) of the Code, subject to Section 707(a)(2)(B) of the Code and its implementing Treasury Regulations (provided that any transfers (or deemed transfers) of cash shall be treated to the maximum extent permitted as a reimbursement of preformation capital expenditures within the meaning of Treasury Regulation Section 1.707-4(d)).

Mcf.    One thousand cubic feet.

MineralCo.    Pirate Fee MineralCo, LLC, a Texas limited liability company to be formed by Blackbeard Operating.

MMBtu.    One million Btus.

NewCo Parties.    New PBT, New PBT Sub and OpCo, collectively.

New PBT.    PBT Land and Minerals, Inc., a Texas corporation, and, unless otherwise indicated or the context otherwise requires, each of its subsidiaries, including OpCo.

New PBT Board.    The board of directors of New PBT immediately after Closing.

New PBT Bylaws.    The A&R Bylaws of New PBT, substantially in the form attached as Annex D to this proxy statement/prospectus.

New PBT Charter.    The A&R Certificate of Formation of New PBT, substantially in the form attached as Annex C to this proxy statement/prospectus.

New PBT Common Stock.    The Class A Shares and Class B Shares.

New PBT Predecessor.    The oil and natural gas mineral interests, land operations, and other assets and liabilities held by Blackbeard Holdings that will be transferred to New PBT in connection with Closing, presented as PBT Land and Minerals, Inc. Predecessor and also US Land Guild Corp. Predecessor in the financial statements included elsewhere in this proxy statement/prospectus.

New PBT Preferred Stock.    The preferred stock, par value $0.0001 per share, of New PBT.

New PBT Sub.    PBT Sub, Inc., a Texas corporation and wholly owned subsidiary of New PBT.

NGLs.    Natural gas liquids.

NGP.    A family of private equity funds managed by NGP Energy Capital Management, L.L.C., including NGP Natural Resources X, L.P., NGP Natural Resources XI, L.P. and NGP Natural Resources XII, L.P.

Nile Midstream.    Nile Midstream, LLC, a Delaware limited liability company and a leading provider of midstream services to oil and natural gas operators in the Permian Basin that operates on USLG’s surface acreage.

NPI-Burdened Mineral Interests.    All of Blackbeard Operating’s (and after the consummation of the Blackbeard Pre-Closing Restructuring, MineralCo’s) right, title and interest in and to all hydrocarbon and mineral interests in the Waddell Ranch that are burdened by the Trust’s Waddell Ranch Interest, together with all rights (including rights of set-off, recoupment, and recovery), claims, counterclaims and causes of action (including any audit rights and any indemnity, bond, insurance or condemnation awards) arising from acts, omissions or events or damage to or destruction of property, unpaid awards, other rights against third parties and claims for adjustments and refunds, in each case to the extent attributable to any such hydrocarbon and mineral interests, as further described in the Combination Agreement.

NRAs.    A Net Royalty Acre, amounting to a 12.5% (or one-eighth) mineral and royalty ownership interest.

OpCo.    PBT Land and Minerals OpCo, LLC, a Texas limited liability company and a subsidiary of New PBT.

OpCo LLC Agreement.    The A&R Limited Liability Company Agreement of OpCo that will be entered into as of Closing.

PBT Competing Proposal.    Any proposal, offer (including tender or exchange offers) or indication of interest, other than the Transactions, (a) with respect to a merger, consolidation, business combination, recapitalization, binding share exchange, scheme of arrangement or other similar transaction with respect to assets that, taken together, constitute more than 20% of the consolidated assets of the Trust, (b) to acquire in any manner, directly or indirectly, in one or more transactions, more than 20% of the issued and outstanding equity securities of the Trust representing more than 20% of the voting power of the Trust, or (c) to acquire in any manner, directly or indirectly, in one or more transactions, assets or businesses of the Trust, representing more than 20% of the consolidated assets of the Trust.

PBT Contribution Closing Date.    The date on which the PBT Contribution Closing (as defined in the Combination Agreement included as Annex B hereto) occurs.

PBT Excluded Assets.    Means (i) an amount in cash equal to the lesser of (a) the cash on-hand of the Trust as of the Closing Date or, and (b) $1.75 million, which amount is to be retained by the Trustee as a reserve for contingent liabilities pursuant to Section 9.03 of the PBT Trust Indenture, (ii) other than the amount in cash contemplated by clause (i) of this definition, any other cash, cash equivalents, marketable securities and bank deposits (including checks and wire transfers, ACH transactions and drafts deposited or available for deposit for the account of the Trust) held by or on behalf of the Trust, including any amounts paid to the Trust pursuant to the terms and conditions of the Settlement Agreement on or prior to the Closing (which disposition will remain at the discretion of the Trustee pursuant to the terms and conditions of the PBT Trust Indenture, as amended), (iii) PBT and its Affiliates’ right, title and interest in and to any amounts payable under the Texas Royalty Conveyance on or prior to the Closing (which disposition will remain at the discretion of the Trustee pursuant to the terms and conditions of the PBT Trust Indenture, as amended, and (iv) the NewCo Legacy Securities (as defined in the Combination Agreement).

Pirate Ranch.    Approximately 7,800 surface acres in Crane County, Texas held by USLG.

Port Royal Ranch or East Ranch.    Approximately 14,000 surface acres in Crane County, Texas held by USLG.

PUDs.    Proved undeveloped reserves.

SEC.    The U.S. Securities and Exchange Commission.

Securities Act.    The Securities Act of 1933, as amended.

Settlement Agreement.    That certain Settlement Agreement and Release, dated as of August 19, 2025, by and between the Trustee and Blackbeard Operating, as amended.

Smugglers Cove Ranch.    Approximately 8,300 surface acres in Crane County, Texas.

SoftVest Advisors.    SoftVest Advisors, LLC, a registered investment adviser and the investment adviser to SoftVest, L.P.

SoftVest GP.    SoftVest GP I, LLC, the general partner of SoftVest, L.P.

SoftVest, L.P.    SoftVest, L.P., the sole owner of New PBT prior to its transfer to the Trust.

Termination Date.    11:59 p.m. (New York City time) on December 31, 2026, as such date may be extended.

TBOC.    The Texas Business Organizations Code.

Texas Royalty Interests.    The net overriding royalty interest conveyed to The First National Bank of Fort Worth (previously Simmons Bank, now Argent Trust Company), as Trustee, for the benefit of the Trust, pursuant to the Net Overriding Royalty Conveyance (Permian Basin Royalty Trust) dated effective as of November 1, 1980 from Southland Royalty Company (now Burlington Resources Oil & Gas Company LP) to The First National Bank of Fort Worth (previously Simmons Bank, now Argent Trust Company), as Trustee, for the benefit of the Trust, and filed of record in Crane County.

Tortuga Ranch.    Approximately 4,700 surface acres in Crane County, Texas.

Transactions.    The transactions contemplated by the Combination Agreement and the Exchange Agreement.

Trust.    Permian Basin Royalty Trust, an express trust created under the laws of the State of Texas.

Trust Interests.    All of the Trust’s right, title and interest in and to the (i) Waddell Ranch Interest, (ii) the Texas Royalty Interests, (iii) the Settlement Agreement and (iv) any and all other rights, properties, and assets of the Trust, of every kind and nature, character and description, whether real personal or mixed, tangible or intangible, accrued or contingent, wherever located and whether or not reflected in on the books and records of the Trust (other than the PBT Excluded Assets).

USLG.    The oil and natural gas mineral interests and land operations owned by Blackbeard Holdings and Greybeard Energy that will be contributed directly or indirectly to New PBT in connection with Closing.

USLG Business.    The ownership and operation of the Blackbeard Transferred Entities, the NPI-Burdened Mineral Interests, and USLG Legacy and USLG ExCo, and other activities conducted in connection with such ownership and operation or that are incidental thereto.

USLG ExCo.    USLG ExchangeCo, LLC, a Texas limited liability company to be formed by USLG Legacy.

USLG Legacy.    US Land Guild, LLC, a Delaware limited liability company and wholly owned subsidiary of Blackbeard Holdings.

Waddell Ranch Interest.    The net overriding royalty interest conveyed to The First National Bank of Fort Worth (previously Simmons Bank, now Argent Trust Company), as Trustee, for the benefit of the Trust, pursuant to the Net Overriding Royalty Conveyance (Permian Basin Royalty Trust — Waddell Ranch) dated effective as of November 1, 1980 from Southland Royalty Company (now Burlington Resources Oil & Gas Company LP) to The First National Bank of Fort Worth (previously Simmons Bank, now Argent Trust Company), as Trustee, for the benefit of the Trust, and filed of record in the Crane County, Texas Deed Records under Volume 274, Page 639.

West Ranch.    Collectively, the Cutlass Sands Ranch, Pirate Ranch, Smugglers Cove Ranch and Tortuga Ranch, consisting of approximately 35,100 surface acres in Crane County, Texas.

TABLE OF CONTENTS

ANNEXES

QUESTIONS AND ANSWERS

The following questions and answers are intended to briefly address some commonly asked questions regarding the Business Combination, the Combination Agreement and the Transactions and certain procedures for the Unitholders to vote their Trust Units and other matters with respect to the Special Meeting. We urge you to carefully read the entirety of this proxy statement/prospectus, including the annexes to this proxy statement/prospectus, because the information in this section does not provide all the information that might be important to you with respect to the Business Combination, the Combination Agreement and the Transactions and the matters related to the Special Meeting.

QUESTIONS AND ANSWERS ABOUT THE BUSINESS COMBINATION:

Q:     What will happen in the Business Combination and what will Unitholders receive?

A:     Following the Business Combination, New PBT would own (i) a majority of the assets and liabilities of the Trust and (ii) USLG, including approximately 68,000 acres of surface estate and a 15% effective royalty interest associated with certain acreage and certain mineral interests owned directly or indirectly by Blackbeard Holdings. Blackbeard Operating, a subsidiary of Blackbeard Holdings, is the operator of the oil and gas interests in the Waddell Ranch, in Crane County, Texas, in which the Trust currently holds a 75% net overriding royalty interest (equivalent to a net profits interest), which represents most of the value of the Trust.

As a part of the Business Combination, (i) the Trust will terminate and Unitholders will receive one Class A Share, which has both voting and economic rights with respect to New PBT, for each Trust Unit they own, (ii) the Trust’s 75% net overriding royalty interest in the Waddell Ranch oil and gas interests will be effectively converted into a cost-free 15% effective royalty interest that will be owned by New PBT and that eliminates cost exposure associated with the development and production of oil and gas and is expected to generate more predictable and consistent cash flow for New PBT investors going forward and (iii) the Trust’s interest in the Waddell Ranch Properties, which currently underlies the NPI structure, will be transferred to Blackbeard Operating through the Unburdened Mineral Interest Lease, resulting in Blackbeard Operating assuming all operating costs and capital obligations associated with the interest while New PBT retains the cost-free royalty interest described above. In addition, New PBT is expected to derive additional revenue from all operations on lands that will be wholly owned by New PBT going forward. This provides meaningful diversification beyond oil and gas royalties alone and contributes significant real assets to the business of New PBT.

The Combination Agreement, which governs the terms of the Business Combination, is attached to this proxy statement/prospectus as Annex B. For a more complete discussion of the proposed Business Combination, its effects and the other Transactions, please see the section entitled “The Business Combination.”

Q:     What will Blackbeard Security and Greybeard Energy receive?

A:     Following Closing, New PBT will be organized in a structure that is commonly referred to as an “Up-C” structure, which is often used by public companies involving partnerships and limited liability companies. New PBT will be a holding company, the sole material assets of which will consist of units of OpCo, which in turn will directly or indirectly own the operating subsidiaries through which New PBT will conduct its business. New PBT 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 the financial results of OpCo and its subsidiaries.

As a part of the Business Combination, Blackbeard Security and its affiliate Greybeard Energy will receive economic, non-voting OpCo units and a corresponding number of Class B Shares. Class B Shares will have voting but no economic rights with respect to New PBT.

Each OpCo unit, together with the corresponding Class B Share, generally will be equivalent economically (except with respect to taxes) and in respect of voting power to one Class A Share. The OpCo LLC Agreement requires New PBT to take all actions with respect to its interests, including OpCo units, to maintain at all times a one-to-one ratio between the number of Class A Shares (or other equity securities of New PBT, other than the Class B Shares) that are outstanding and the number of OpCo units (or other equity securities in OpCo) owned by New PBT.

Following the Business Combination, pursuant to the OpCo LLC Agreement, each holder of OpCo units (other than New PBT) will have the right (the “Redemption Right”) to cause OpCo to redeem all or a portion of its units 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 stock splits, stock dividends, reclassification and other similar transactions, or (ii) an equivalent amount of cash. Alternatively, for administrative convenience, upon the exercise of the Redemption Right, New PBT will have the right (the “Call Right”) to acquire the tendered OpCo units directly from the redeeming holder for, at its election, (x) Class A Shares at a redemption ratio of one Class A Share for each OpCo unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends, reclassification and other similar transactions, or (y) an equivalent amount of cash. In connection with any redemption of OpCo units, a corresponding number of Class B Shares will be cancelled.

Q:     What equity stake will Unitholders and Blackbeard hold in New PBT following the Business Combination?

A:     Immediately following the Business Combination, (i) former Unitholders will own approximately 59.3% of the outstanding New PBT Common Stock, (ii) Blackbeard Security and Greybeard Energy, together, will own approximately 40.7% of the outstanding New PBT Common Stock, and (iii) New PBT will be the managing member of OpCo.

Q:     If I am a Unitholder, how will I receive the Class A Shares to which I am entitled?

A:     In connection with Closing, the Trust will terminate and distribute to the Unitholders all Class A Shares it receives in the Business Combination, on a pro rata basis and otherwise on the terms and conditions set forth in the Trust’s Royalty Trust Indenture (as amended by the Indenture Amendment).

For more information about the receipt of Class A Shares in connection with the Business Combination, see the section entitled “The Combination Agreement — Closing of the Business Combination.”

Q:     What will be the composition of the New PBT Board following the completion of the Business Combination?

A:     Following Closing, the New PBT Board will consist of seven directors: Eric Oliver (Chairman); Jordan Barrett; Ricky Burnett; Brian Ferguson; Peter Ray; Kaleb Smith and             .

Q:     Will the Class A Shares that I acquire in connection with the Business Combination receive a dividend?

A:     After Closing, as a holder of Class A Shares, you will receive the same dividends on your Class A Shares that all other holders of Class A Shares will receive for any dividend with a record date that occurs after Closing. Although we currently expect New PBT to pay regular dividends to holders of Class A Shares, the New PBT Board will have sole discretion to declare dividend payments.

Q:     Will the Class A Shares received in connection with the Business Combination be traded on an exchange?

A:     Yes. It is a condition to the consummation of the Business Combination that the Class A Shares be authorized for listing on the NYSE, subject to official notice of issuance, and the Class A Shares are expected to be listed for trading on the NYSE and NYSE Texas under the symbol “PBT.” Trust Units currently trade on the NYSE under the symbol “PBT.” When the Business Combination is completed, Trust Units will cease to be traded on the NYSE.

For additional information, please see the section entitled “The Business Combination — Stock Exchange Listing.”

Q:     What are the material U.S. federal income tax consequences of the Business Combination to the Unitholders?

A:     The Trust is classified as a grantor trust for U.S. federal income tax purposes. In accordance with such tax classification, the Trust is generally disregarded for U.S. federal income tax purposes and the Unitholders are treated as directly owning their proportionate share of the Trust’s assets and liabilities. Accordingly, for

U.S. federal income tax purposes, (i) the contribution by the Trust of its assets to New PBT as part of the Business Combination will be treated as a contribution by each Unitholder of its proportionate share of the Trust’s assets (subject to a proportionate share of any Trust liabilities) to New PBT in exchange for Class A Shares, and (ii) the receipt of Class A Shares by the Unitholders will be disregarded.

Assuming that the Business Combination is completed as currently contemplated, for U.S. federal income tax purposes, the contribution by the Trust of its assets to New PBT and receipt of Class A Shares by the Unitholders pursuant to the Business Combination, together with certain other transactions occurring as part of the Business Combination, the exercise of any Subscription Rights and the purchase of Class A Shares pursuant to the Blackbeard and Greybeard Subscription and the Backstop Commitment (if applicable), is intended to qualify as a contribution governed by Section 351(a) of the Code. Assuming that such contribution and receipt is so treated, Unitholders will not recognize any gain or loss for U.S. federal income tax purposes as a result of the Business Combination.

For a more detailed discussion of the material U.S. federal income tax consequences of the Business Combination to U.S. holders (as defined below), see the section entitled “The Business Combination — Material U.S. Federal Income Tax Consequences of the Business Combination.” Tax matters can be complicated, and the tax consequences of the Business Combination to a particular Unitholder will depend on such Unitholder’s particular facts and circumstances. Each Unitholder is strongly encouraged to consult with its own tax advisor to determine the particular U.S. federal, state or local or non-U.S. income or other tax consequences of the Business Combination to it.

Q:     What are the expected U.S. federal income tax consequences for a Unitholder of the ownership and disposition of Class A Shares following the completion of Business Combination?

A:     The Trust is classified as a grantor trust for U.S. federal income tax purposes. In accordance with such tax classification, the Trust is generally disregarded for U.S. federal income tax purposes and Unitholders are treated as directly owning their proportionate share of the Trust’s assets and liabilities. As such, Unitholders generally are subject to U.S. federal income tax directly on their proportionate share of income, gain, deductions and credits of the Trust, and a distribution of cash to a Unitholder by the Trust generally is not taxable for U.S. federal income tax purposes. In addition, a Unitholder generally will recognize capital gain or loss on a disposition of its Trust Units as though it disposed of its proportionate share of the Trust’s assets, except that any amounts treated as recapture of deductions for depletion generally will be recharacterized as ordinary income.

In contrast, New PBT is classified as a corporation for U.S. federal income tax purposes and is subject to U.S. federal income tax on its taxable income. Because New PBT will be classified as corporation for U.S. federal income tax purposes, any future distribution of cash by New PBT will constitute dividends to the extent paid from New PBT’s current or accumulated “earnings and profits,” as determined under U.S. federal income tax principles, and will be reported to such owner on IRS Form 1099-DIV. Distributions in excess of New PBT’s current and accumulated earnings and profits, as determined under U.S. federal income tax principles, will be treated as a non-taxable return of capital, reducing a holder’s adjusted tax basis in such holder’s Class A Shares (but not below zero) and, to the extent the distribution exceeds such holder’s adjusted tax basis, as capital gain from the sale or exchange of Class A Shares. In addition, a holder of Class A Shares who is a U.S. holder generally will recognize capital gain or loss on a taxable disposition of its Class A Shares, and a holder of Class A Shares who is a non-U.S. holder whose ownership of Class A Shares exceeds certain levels will be subject to U.S. federal income tax upon a taxable disposition of Class A Shares. Non-U.S. holders may also be subject to withholding tax on distributions on or dispositions of Class A Shares.

For a discussion of the treatment of U.S. holders, see the section entitled “Material U.S. Federal Income Tax Consequences of the Business Combination — Tax Consequences to U.S. Holders of Owning and Disposing of Class A Shares Received in the Business Combination.” For a discussion of the treatment of non-U.S. holders see the section entitled “Material U.S. Federal Income Tax Consequences of the Business Combination — Tax Consequences to Non-U.S. Holders of Owning and Disposing of Class A Shares Received in the Business Combination.”

Q:     When do you expect to complete the Business Combination?

A:     We currently expect to complete the Business Combination in the second half of calendar year 2026. However, we cannot predict the actual date on which the Business Combination will be completed, nor can we ensure that the Business Combination will be completed, because completion is subject to conditions beyond our control. Please see the sections entitled “The Business Combination — Regulatory Approval”, “The Combination Agreement — Conditions to the Completion of the Business Combination” and “Summary — The Business Combination and the Combination Agreement.”

Q:     What happens if the Business Combination is not completed?

A:     If Unitholders do not approve the Indenture Amendment Proposal, or if the Business Combination is not completed for any other reason, Unitholders will not receive any shares of New PBT. Instead, the Trust will remain an independent public trust and Trust Units will continue to be listed and traded on the NYSE and registered under the Exchange Act, and the Trust will continue to file periodic reports with the SEC.

Q:     What will happen to the Trust after the Business Combination?

A:     If the Indenture Amendment Proposal is approved and the Business Combination is completed, a majority of the assets and liabilities of the Trust will be transferred out of the Trust into New PBT and the Trust will terminate and distribute Class A Shares received for such transfer to Unitholders on a pro rata basis and otherwise on the terms and conditions set forth in the Trust’s Royalty Trust Indenture (as amended by the Indenture Amendment).

QUESTIONS AND ANSWERS ABOUT THE RIGHTS OFFERING:

Q:     What is the Rights Offering?

A:     Concurrently with the solicitation of proxies pursuant to this proxy statement/prospectus, New PBT is conducting the Rights Offering, pursuant to which Unitholders are being offered the right to subscribe for additional Class A Shares on a pro rata basis. Each holder of a Trust Unit has received a non-transferable right to purchase              Class A Share at a subscription price of $           per share (each a “Subscription Right”). Please review carefully the prospectus contained in the Registration Statement on Form S-1 (File No. 333-            ), including the risk factors and other disclosures contained therein, before making any investment decision with respect to the Rights Offering.

         Pursuant to the Commitment Agreement, each of SoftVest, L.P. and Horizon Kinetics has agreed (a) to exercise in full the Subscription Rights allocated to it in the Rights Offering, including their over-subscription rights, and (b) to purchase, at the subscription price applicable to the Rights Offering, an equal portion (50% each) of up to $71.2 million Class A Shares that are not subscribed for by other Unitholders in the Rights Offering. In addition, pursuant to the Commitment Agreement, Blackbeard Security and Greybeard Energy have agreed to purchase, at the subscription price applicable to the Rights Offering, in a private placement exempt from the registration requirements under the Securities Act, an aggregate of              Class A Shares. This amount of shares has been calculated to represent the pro rata portion of shares that Blackbeard Security and Greybeard Energy would be entitled to purchase in the Rights Offering as a combined 40.7% shareholder of New PBT following Closing. The closing of each of the Rights Offering, the Backstop Commitment and the Blackbeard and Greybeard Subscription is conditioned on the closing of the Business Combination.

Q:     Why are we conducting the Rights Offering?

A:     We believe that the Rights Offering will strengthen New PBT’s financial position by enabling the repayment of indebtedness and capitalizing New PBT in a way that reflects its long-term strategic objectives.

Q:     How will the proceeds from the Rights Offering be used?

A:     We intend to use the net proceeds from the Rights Offering for general corporate purposes, including payment of fees relating to the Business Combination, and the repayment of indebtedness.

Q:     Am I required to exercise my Subscription Rights in the Rights Offering if I vote to approve the Indenture Amendment Proposal or any other Proposal at the Special Meeting?

A:     No. How you vote with respect to any proposal presented at the Special Meeting does not affect your decision about whether to exercise your Subscription Rights.

Q:     How do I exercise my Subscription Rights?

A:     You should be receiving concurrently with this proxy statement/prospectus a separate prospectus with information about the Rights Offering and the instructions that you must follow to exercise your Subscription Rights.

QUESTIONS AND ANSWERS ABOUT THE SPECIAL MEETING:

Q:     What are Unitholders being asked to approve?

A:     Unitholders are being asked to approve the following three proposals:

•        an amendment to the Trust Indenture to effect the Business Combination pursuant to the Combination Agreement and related transaction documents (the “Indenture Amendment Proposal”);

•        the PBT Land and Minerals, Inc. Omnibus Incentive Plan (the “2026 Incentive Plan Proposal”); and

•        an adjournment of the Special Meeting, if necessary or appropriate, to permit solicitation of additional proxies in favor of the Indenture Amendment Proposal and the 2026 Incentive Plan Proposal (the “Adjournment Proposal” and, together with the Indenture Amendment Proposal and the 2026 Incentive Plan Proposal, the “Proposals”).

         Your approval of the Indenture Amendment Proposal effectively signifies your approval of all the other transactions that are part of or connected to the Business Combination, including, without limitation, the transfer of a majority of the Trust’s assets to New PBT, completion of the Rights Offering, completion of the Blackbeard and Greybeard Subscription, us entering into the Shareholders’ Agreement (as defined below) with SoftVest, L.P., Blackbeard Security and Greybeard Energy, execution of the Exchange Agreement (as defined below), and termination of the Trust. None of these transactions, nor any other matters contemplated by the Combination Agreement, can be completed without Unitholders approving the Indenture Amendment Proposal.

Q:     Who can vote?

A:     Only Unitholders as of the close of business on             , 2026 (the “Record Date”) will be entitled to vote at the Special Meeting. If you are a Unitholder of record on the Record Date, you will retain the voting rights in connection with the Special Meeting even if you sell such Trust Units after the Record Date. Accordingly, it is important that you vote the Trust Units held by you on the Record Date or grant a proxy to vote such Trust Units on the Proxy Card, even if you sell such Trust Units after such date. We have been advised by the Trustee that, as of the Record Date, we can expect 46,608,796 Trust Units to be outstanding. Each Trust Unit is entitled to one vote at the Special Meeting.

Q:     What is the required quorum at the Special Meeting?

A:     According to the Trust Indenture, for purposes of the Special Meeting there will be a quorum if the holders of a majority of the outstanding Trust Units are present in person or by proxy.

Q:     How do I vote by proxy?

A:     If your Trust Units are held in your name, you may vote by proxy as follows:

•        Vote by Internet:    Please access the website linked on your Proxy Card and follow the on-screen instructions or scan the QR code with your smartphone. You will be required to provide the unique control number printed on your Proxy Card and should have your Proxy Card available when you access the voting website.

•        Vote by Telephone:    Please call toll-free from the U.S. or Canada the phone number listed on your Proxy Card and follow the simple instructions provided. You will be required to provide the unique control number printed on your Proxy Card and should have your Proxy Card available when you call.

•        Vote by Mail:    If you do not have access to a touch-tone telephone or to the Internet or wish to vote by mail, please sign, date and return the Proxy Card in the envelope provided, or mail to: PBT Land and Minerals, Inc., c/o D.F. King & Co., Inc., 28 Liberty Street, 53rd Floor, New York, New York 10005.

You may vote by Internet or telephone 24 hours a day, 7 days a week until 10:59 P.M. Central Time the day before the Special Meeting. Your Internet or telephone vote authorizes the named proxies to vote your Trust Units in the same manner as if you had executed a Proxy Card.

The Internet and telephone voting procedures use a control number that appears on your Proxy Card to authenticate you as a Unitholder of record and to allow you to confirm that your voting instructions have been correctly recorded. If you vote by Internet or telephone, you do not need to return the Proxy Card.

Q:     How do I vote Trust Units that I hold through a broker, bank or other custodian?

A:     If you hold Trust Units through someone else, such as a broker, bank or other custodian, you will receive voting material from that firm. You can complete the voting form and return it as requested by the firm. If the firm offers Internet or telephone voting, the voting form will contain instructions on how to access and utilize those voting methods. If you hold your Trust Units in a stock brokerage account or by a bank or other custodian, you will not be able to vote in person at the Special Meeting, unless you have previously requested and obtained a “legal proxy” from your broker, bank or other custodian and present it at the Special Meeting.

Q:     What if I plan to attend the Special Meeting, should I still submit a Proxy Card?

A:     Yes. Whether or not you plan to attend the Special Meeting, we urge you to submit a Proxy Card. Returning the enclosed Proxy Card will not affect your right to attend and vote at the Special Meeting.

Q:     What if I want to revoke my proxy?

A:     If you are a Unitholder of record, you can revoke your proxy at any time prior to the time a vote is taken by (a) submitting a duly executed proxy bearing a later date or submitting a later proxy using the Internet or telephone voting procedures described above, (b) filing a later-dated written revocation with an agent of the Trust, or (c) attending and voting at the Special Meeting in person. Attendance at the Special Meeting will not in and of itself constitute a revocation.

If you hold your Trust Units in a brokerage account or by a bank or other custodian, unless you have obtained a “legal proxy” from your bank, broker or other custodian, you will need to follow the instructions provided by your bank, broker or other custodian to revoke your voting form or submit a new voting form.

Q:     What Unitholder vote is required to approve each of the proposals?

A:     Your vote “FOR” each Proposal presented at the Special Meeting is very important and you are encouraged to submit a proxy as soon as possible. The Business Combination cannot be completed without, among other things, the approval of the Indenture Amendment Proposal by Unitholders.

Indenture Amendment Proposal.    Approval of the Indenture Amendment Proposal requires the affirmative vote of a majority in interest of Unitholders present at the Special Meeting, assuming a quorum is present. Accordingly, a Unitholder’s abstention from voting and any broker non-vote will have the same effect as a vote “AGAINST” the Indenture Amendment Proposal.

2026 Incentive Plan Proposal.    Approval of the 2026 Incentive Plan Proposal requires the affirmative vote of a majority in interest of Unitholders present at the Special Meeting, assuming a quorum is present. Accordingly, a Unitholder’s abstention from voting and any broker non-vote will have the same effect as a vote “AGAINST” the 2026 Incentive Plan Proposal.

Adjournment Proposal.    The proposal to adjourn the Special Meeting, if necessary or appropriate, to permit the solicitation of additional proxies in favor of the Indenture Amendment Proposal and/or the 2026 Incentive Plan Proposal requires the affirmative vote of Unitholders who, as of the Record Date, held Trust Units representing a majority of the Trust Units represented in person or by proxy at the Special Meeting. Accordingly, a Unitholder’s abstention from voting and any broker non-vote will have the same effect as a vote “AGAINST” the Adjournment Proposal.

For additional information, please see the section entitled “The Special Meeting — Vote Required.”

Q:     How many votes may I cast?

A:     Each issued and outstanding Trust Unit entitles its holder of record to one vote on each matter to be considered at the Special Meeting. The Unitholders of record on the Record Date are the only Unitholders that are entitled to receive notice of, and to vote at, the Special Meeting or any adjournments or postponements thereof.

Q:     What should I do if I receive more than one set of voting materials?

A:     You may receive more than one set of voting materials for the Special Meeting, including multiple copies of this proxy statement/prospectus and multiple proxy cards or voting instruction forms. For example, if you hold your shares of Trust Units in more than one brokerage account, you will receive a separate voting instruction form for each brokerage account in which you hold shares. If you are a holder of record and your shares are registered in more than one name, you will receive more than one proxy card. Please submit each separate proxy or voting instruction form that you receive by following the instructions set forth in each separate proxy or voting instruction form. If you fail to submit each separate proxy or voting instruction form that you receive, not all of your shares will be voted.

Q:     What do I need to do now?

A:     After you have carefully read and considered the information contained in this proxy statement/prospectus, please submit your proxy via the internet or by telephone in accordance with the instructions set forth on the proxy card or voting instruction form you received, or complete, sign, date and return the proxy card or voting instruction form in the self-addressed, stamped envelope provided as soon as possible so that your shares will be represented and voted at the Special Meeting.

For additional information on voting procedures, please see the section entitled “The Special Meeting.”

Q:     How will my proxy be voted?

A:     If you are a record holder and submit your proxy via the internet, by telephone, or by properly completing, signing, dating and returning the enclosed proxy card or voting instruction form, your proxy will be voted in accordance with your instructions. Should the enclosed proxy card be returned without instructions on how you wish to vote on the Indenture Amendment Proposal, the 2026 Incentive Plan Proposal or the Adjournment Proposal, your proxy card will be deemed to grant such authority and will be voted “FOR” the Indenture Amendment Proposal, the 2026 Incentive Plan Proposal and/or the Adjournment Proposal, as the case may be. For additional information on voting procedures, please see the section entitled “The Special Meeting — How to Vote” and “The Special Meeting — Revocation of Proxies.”

Q:     Who will count the votes?

A:     The votes at the Special Meeting will be tabulated and certified by the inspector of elections appointed by the Trustee.

Q:     Where can I find the voting results of the Special Meeting?

A:     The Trust intends to announce the preliminary voting results at the Special Meeting and to disclose detailed, final voting results in a Current Report on Form 8-K, which it will file with the SEC within four business days of the Special Meeting (or, if final results are not available at that time, within four business days of the date on which final results become available).

RISK FACTORS

In addition to the other information contained in this proxy statement/prospectus, you should consider carefully the following risk factors, including the matters addressed under the caption “Cautionary Statement Regarding Forward-Looking Statements.”

Risks Relating to the Business Combination

The Combination Agreement and Proposed Business Combination Were Not Negotiated by the Trust or the Trustee.

Given the limited powers of the Trust and the Trustee under the Trust Indenture, neither the Trust nor the Trustee participated in the negotiations of the Combination Agreement or Business Combination. The negotiations were instead conducted by SoftVest, L.P., a Unitholder that beneficially owns in the aggregate approximately 13.3% of the outstanding Trust Units, at SoftVest, L.P.’s initiative. Neither SoftVest, L.P. nor any of its affiliates has the power or authority to bind the Trust or the Trustee, or act on behalf of either of them or other Unitholders. For that reason, the Business Combination can only occur if the Unitholders approve the Indenture Amendment Proposal, which approves and adopts the Combination Agreement. The amendment also instructs the Trustee to facilitate the consummation of the Business Combination.

We believe SoftVest, L.P.’s interests are generally aligned with those of other Unitholders. However, neither SoftVest, L.P. nor any of its affiliates or respective representatives has any fiduciary or other obligations to the Trust, the Trustee or any other Unitholders. The Trustee is not expected to make a recommendation for or against the Indenture Amendment Proposal or generally with respect to the Business Combination or the Combination Agreement. Therefore, Unitholders are strongly encouraged to carefully review the information in this proxy statement/prospectus, including all annexes and information incorporated by reference, so that they can make their own determination as to whether to approve the Proposals at the Special Meeting.

None of New PBT, the Trust or the Trustee received any opinion from an investment bank regarding the fairness of the Business Combination from a financial point of view, or any other matter.

The Business Combination is subject to conditions, some or all of which may not be satisfied, and may not be completed on a timely basis, if at all. Failure to complete the Business Combination on a timely basis or at all could have adverse effects on the Trust.

The completion of the Business Combination is subject to a number of conditions, including, among others, (i) the approval by the Trust’s Unitholders of the Indenture Amendment Proposal and (ii) certain regulatory approvals, including the expiration or termination of any applicable waiting period under the HSR Act, which make the completion and timing of the Business Combination uncertain. For a more detailed discussion regarding conditions to the Business Combination, see “The Combination Agreement — Conditions to the Completion of the Business Combination,” beginning on page 131. Also, the parties to the Combination Agreement may terminate the Combination Agreement if the Business Combination has not been consummated on or before December 31, 2026, subject to certain exceptions.

If the Business Combination is not completed, the Trust’s ongoing business, financial condition, financial results and stock price could be materially adversely affected, and the Trust would forego any benefit of completing the Business Combination. Without realizing any of the benefits of having completed the Business Combination, the Trust will be subject to a number of risks, including that the market price of Trust Units could decline to the extent that the current market price reflects a market assumption that the Business Combination will be completed.

Similarly, delays in the completion of the Business Combination could, among other things, result in negative effects associated with uncertainty about completion of the Business Combination.

The Blackbeard Contribution Closing may not occur even if the PBT Contribution Closing has been consummated.

The contribution of substantially all of the Trust’s assets to New PBT (which will occur at the PBT Contribution Closing) will occur at least four business days before the time when Blackbeard is required to contribute the USLG Business to New PBT (which will occur at the Blackbeard Contribution Closing). If an event

occurs during those four business days that causes the conditions to the Blackbeard Contribution Closing not to be satisfied such that the Blackbeard Contribution Closing does not occur, Unitholders will not receive Class A Shares and New PBT will remain as a wholly owned subsidiary of the Trust. The tax consequences to Unitholders with respect to the contribution of substantially all of the Trust’s assets to New PBT and indirectly owning and disposing of the Class A Shares through their ownership and disposition of Trust Units will be the same in all material respects to the treatment if the Blackbeard Contribution Closing (and Business Combination) had actually occurred. In such circumstance we intend to work with the Trust and the Trustee to take appropriate steps to cause the distribution of the Class A Shares (which will have no interest in the USLG Business) to Unitholders, but we cannot provide assurances as to the timing of such distribution, or whether it will occur at all. For a discussion of the tax consequences of the contribution by the Trust of its assets to New PBT, the exchange of Trust Units for Class A Shares and of owning and disposing Class A Shares, see “The Business Combination — Material U.S. Federal Income Tax Consequences of the Business Combination.”

The unaudited pro forma condensed combined financial information set forth in this proxy statement/prospectus is presented for illustrative purposes only and may not be reflective of the operating results and financial condition of New PBT after the completion of the Business Combination.

The unaudited pro forma condensed combined financial information set forth in this proxy statement/prospectus is presented for illustrative purposes only and is not necessarily indicative of what New PBT’s actual financial position or results of operations would have been had the Business Combination been completed on the dates indicated. Further, New PBT’s actual results and financial position after the Business Combination may differ materially and adversely from the unaudited pro forma condensed combined financial information that is included in this proxy statement/prospectus. The unaudited pro forma condensed combined financial information has been prepared with the expectation, as of the date of this proxy statement/prospectus, that New PBT Predecessor will be identified as the accounting acquirer under GAAP and reflects adjustments based upon preliminary estimates of the fair value of assets to be acquired and liabilities to be assumed at the date of the completion of the Business Combination. Subsequent to the Closing Date, there will be further refinements of the acquisition accounting as additional information becomes available. Accordingly, the final acquisition accounting may differ materially from the unaudited pro forma condensed combined financial information reflected in this proxy statement/prospectus. See “Unaudited Pro Forma Condensed Combined Financial Statements” beginning on page 145 for more information.

Completion of the Business Combination may trigger change in control or other provisions in agreements to which the Trust or USLG Legacy are a party, which may have an adverse impact on New PBT’s business and results of operations after the Business Combination.

The completion of the Business Combination may trigger change in control or other provisions in agreements to which the Trust or USLG Legacy are a party, although at this time we are not aware of any. If the Trust or USLG Legacy are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seeking monetary damages. Even if the Trust or USLG Legacy are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to New PBT after the completion of the Business Combination. Any of the foregoing or similar developments may have an adverse impact on New PBT’s business and operations after the completion of the Business Combination.

The Class A Shares to be received by Unitholders upon completion of the Business Combination will have different rights from Trust Units.

The terms of the Trust Indenture are in some respects materially different from the terms of the New PBT Charter, the New PBT Bylaws and Texas law that will govern New PBT. See “Comparison of Unitholder Rights and Corporate Governance Matters” beginning on page 189 for a discussion of the different rights associated with Trust Units and Class A Shares.

The U.S. federal income tax treatment of New PBT’s operations and the ownership and disposition of Class A Shares following the Business Combination will be different from the U.S. federal income tax treatment of the Trust’s operations and the ownership and dispositions of Trust Units.

The Trust is classified as a grantor trust for U.S. federal income tax purposes. In accordance with this such tax classification, the Trust is generally disregarded for U.S. federal income tax purposes and Unitholders are treated as directly owning their proportionate share of the Trust’s assets and liabilities. As such, Unitholders generally are subject to U.S. federal income tax directly on their proportionate share of income, gain, deductions and credits of the Trust, and a distribution of cash to a Unitholder by the Trust generally is not taxable for U.S. federal income tax purposes. In addition, a Unitholder generally will recognize capital gain or loss on a disposition of its Trust Units as though it disposed of its proportionate share of the Trust’s assets, except that any amounts treated as recapture of deductions for depletion generally will be recharacterized as ordinary income.

In contrast, New PBT is classified as a corporation for U.S. federal income tax purposes and is subject to U.S. federal income tax on its taxable income. Because New PBT will be classified as corporation for U.S. federal income tax purposes, any future distribution of cash by New PBT will constitute dividends to the extent paid from New PBT’s current or accumulated “earnings and profits,” as determined under U.S. federal income tax principles, and will be reported to such owner on IRS Form 1099-DIV. Distributions in excess of New PBT’s current and accumulated earnings and profits, as determined under U.S. federal income tax principles, will be treated as a non-taxable return of capital, reducing a holder’s adjusted tax basis in such holder’s Class A Shares (but not below zero) and, to the extent the distribution exceeds such stockholder’s adjusted tax basis, as capital gain from the sale or exchange of Class A Shares. In addition, a U.S. holder generally will recognize capital gain or loss on a taxable disposition of its Class A Shares, and a non-U.S. holder whose ownership of Class A Shares exceeds certain levels will be subject to U.S. federal income tax upon a taxable disposition of Class A Shares. Non-U.S. holders may also be subject to withholding tax on distributions on or dispositions of Class A Shares.

For a discussion of the treatment of U.S. holders, see the section entitled “The Business Combination — Material U.S. Federal Income Tax Consequences of the Business Combination — Tax Consequences to U.S. Holders of Owning and Disposing of Class A Shares Received in the Business Combination”. For a discussion of the treatment of non-U.S. holders see the section entitled “The Business Combination — Material U.S. Federal Income Tax Consequences of the Business Combination — Tax Consequences to Non-U.S. Holders of Owning and Disposing of Class A Shares Received in the Business Combination”.

The Business Combination will involve substantial costs.

SoftVest and Blackbeard have incurred, and expect to continue to incur, substantial costs associated with the Business Combination, including, among others, fees paid to financial, legal and accounting advisors, proxy solicitation costs and filing fees and regulatory costs, which are expected to exceed $50 million. The Combination Agreement, if adopted by Unitholders, provides that these costs will be paid by New PBT.

If the contribution by the Trust of its assets to New PBT and receipt of Class A Shares by the Unitholders as part of the Business Combination were to fail to qualify as a contribution governed by Section 351(a) of the Code or if the IRS were to successfully challenge any aspect of the Intended Tax Treatment, U.S. holders of Trust Units and/or New PBT could be required to pay substantial U.S. federal income taxes.

Assuming that the Business Combination is completed as currently contemplated, for U.S. federal income tax purposes, the contribution by the Trust of its assets to New PBT and receipt of Class A Shares by the Unitholders pursuant to the Business Combination, together with certain other transactions occurring as part of the Business Combination, the exercise of any Subscription Rights and the purchase of Class A Shares pursuant to the Blackbeard and Greybeard Subscription and the Backstop Commitment (if applicable), is intended to qualify as a contribution governed by Section 351(a) of the Code. It is not a condition to the parties’ obligations to complete the Business Combination that such contribution by the Trust of its assets to New PBT and receipt of Class A Shares by the Unitholders be treated as a contribution governed by Section 351(a) of the Code or that the Transactions qualify for the Intended Tax Treatment. None of the parties have sought or intend to seek any ruling from the IRS regarding the qualification of such contribution as a contribution governed by Section 351(a) of the Code or regarding the qualification of any aspect of the Transactions for the Intended Tax Treatment. In connection with the effectiveness of this proxy statement/prospectus, Paul Hastings LLP will provide an opinion to the effect that the contribution by the Trust of its assets to New PBT and receipt of Class A Shares by the Unitholders pursuant to the Business

Combination, together with certain other transactions occurring as part of the Business Combination should be treated for U.S. federal income tax purposes as a contribution governed by Section 351(a) of the Code. However, no assurance can be given that such contribution and receipt will so qualify or that the IRS will not challenge such qualification or the qualification of any aspect of the Transactions for the Intended Tax Treatment or that a court would not sustain such a challenge. If such contribution and receipt were to fail to qualify as a contribution under Section 351(a) of the Code or if the IRS were to successfully challenge any aspect of the Intended Tax Treatment, U.S. holders of Trust Units and/or New PBT could be required to pay substantial U.S. federal income taxes. For a more complete description of the U.S. federal income tax consequences to U.S. holders of Trust Units of the Business Combination to U.S. holders, see the section entitled “The Business Combination — Material U.S. Federal Income Tax Consequences of the Business Combination.”

Risks Relating to New PBT

New PBT will be a holding company. New PBT’s sole material asset following the completion of the Business Combination will be its equity interest in OpCo, and New PBT will accordingly be dependent upon distributions from OpCo to pay taxes, cover its corporate and other overhead expenses and any tax liabilities of New PBT and New PBT Sub that are attributable to any taxable period (or portion thereof) ending on or prior to the Blackbeard Contribution Closing Date, and pay any dividends on Class A Shares.

After giving effect to the Transactions, New PBT will be a holding company and will have no material assets other than its equity interest in OpCo. New PBT will have no independent means of generating revenue. To the extent funds of OpCo are legally available for distribution, subject to any restrictions contained in any agreement to which OpCo or its subsidiaries is bound, OpCo generally will be required to make distributions to all OpCo unitholders (including New PBT) on a pro rata basis (i) in such amounts as are necessary to cause a distribution to New PBT sufficient to enable New PBT to timely satisfy its tax liabilities, and (ii) to the extent the income tax liabilities of certain OpCo unitholders (other than New PBT) with respect to their allocable share of the income of OpCo (based on certain assumptions and conventions) exceed amounts otherwise distributed by OpCo, in amounts generally intended to allow such other OpCo unitholders to satisfy such excess income tax liabilities, which such additional distributed amounts may be re-contributed to OpCo in exchange for additional OpCo units at the election of certain holders (including New PBT). In addition, as the managing member of OpCo, New PBT may cause OpCo to make pro rata distributions of available cash to all of its unitholders, including to New PBT, in an amount sufficient to allow New PBT to fund dividends to its shareholders in accordance with New PBT’s dividend policy, to the extent the New PBT Board declares such dividends. Therefore, while New PBT expects to pay dividends on Class A Shares in amounts determined from time to time by the New PBT Board in the future, New PBT’s 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 New PBT, including due to the restrictions under any New PBT credit facility. Additionally, if OpCo makes such distributions, Blackbeard Security and Greybeard Energy, as OpCo unitholders, will be entitled to receive equivalent distributions from OpCo on a pro rata basis. However, because New PBT must pay taxes, amounts ultimately distributed as dividends to holders of Class A Shares are expected to be less on a per share basis than the amounts distributed by OpCo to Blackbeard Security and Greybeard Energy (in their capacity as holders of OpCo units) on a per unit basis. The OpCo LLC Agreement will also require OpCo to make non-pro rata payments to New PBT to reimburse it for corporate and other overhead expenses, and any tax liabilities of New PBT and New PBT Sub that are attributable to any taxable period (or portion thereof) ending on or prior to the Blackbeard Contribution Closing Date, which payments will not be treated as distributions under the OpCo LLC Agreement. To the extent that New PBT needs funds and OpCo or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect New PBT’s liquidity and financial condition. This and other aspects of our organizational structure following Closing may adversely impact the future trading market for the New PBT Common Stock.

The market price for Class A Shares following the completion of the Business Combination may be affected by factors different from, or in addition to, those that historically have affected or currently affect the market prices of the Trust.

Upon consummation of the Business Combination, existing Unitholders will hold Class A Shares. USLG’s and the Trust’s businesses differ and, accordingly, the results of operations of New PBT will be affected by some factors that are different from those currently or historically affecting the results of operations of USLG or the Trust. The results of operations of New PBT may also be affected by factors different from those that currently affect or have historically affected either USLG or the Trust.

The unaudited pro forma condensed combined financial information included in this proxy statement/prospectus is preliminary and New PBT’s actual financial position and results of operations after the Business Combination may differ materially from these estimates and the unaudited pro forma condensed combined financial information included in this proxy statement/prospectus.

The unaudited pro forma condensed combined financial information included in this proxy statement/prospectus is presented for illustrative purposes only, contains a variety of adjustments, assumptions and preliminary estimates and is not necessarily indicative of what New PBT’s actual financial position or results of operations would have been had the Business Combination been completed on the dates indicated. New PBT’s actual results and financial position after the Business Combination may differ materially and adversely from the unaudited pro forma condensed combined financial statement included in this proxy statement/prospectus.

Declaration, payment and amounts of dividends, if any, to holders of Class A Shares will be uncertain.

Although we currently expect New PBT to pay regular dividends to holders of Class A Shares, the amount of dividends, if any, that are declared or paid to holders of Class A Shares, will depend on a number of factors. The New PBT Board will have sole discretion to determine the dividend policy of New PBT, including whether any dividends will be declared, when dividends, if any, are declared, and the amount of such dividends. New PBT expects that such determination would be based on a number of considerations, including New PBT’s results of operations and capital management plans and the market price of New PBT shares, the availability of funds to New PBT, debt covenant limitations, New PBT’s access to capital markets as well as industry practice and other factors, deemed relevant by the New PBT Board. In addition, New PBT’s ability to pay dividends and the amount of any dividends ultimately paid in respect of Class A Shares will, in each case, be subject to New PBT receiving funds, directly or indirectly, from OpCo. Furthermore, the ability of OpCo to make distributions to New PBT will depend on satisfying applicable law with respect to such distributions. There can be no guarantee that holders of Class A Shares will receive or be entitled to dividends.

Following the Business Combination, Blackbeard will own over 40% of New PBT Common Stock, and their interests could differ from the interests of our other shareholders.

As a result of the Business Combination, Blackbeard Security and Greybeard Energy, together, will own approximately 40.7% of the shares of New PBT Common Stock. Therefore, following the Business Combination, Blackbeard Security and Greybeard Energy will have considerable influence or effective veto control regarding the outcome of any transaction or action that requires shareholder approval, including mergers, acquisitions, amendments to our charter and various corporate governance actions.

Affiliates of Blackbeard and SoftVest will have the right to appoint all or a majority of the New PBT Board of Directors until their ownership of New PBT Common Stock falls under certain ownership thresholds.

In connection with the Business Combination, we intend to enter into the Shareholders’ Agreement with Blackbeard Security, Greybeard Energy and SoftVest, L.P. The Shareholders’ Agreement will provide Blackbeard Security and Greybeard Energy the right, subject to certain terms and conditions contained in the Shareholders’ Agreement, (i) for so long as Blackbeard Security, Greybeard Energy and their permitted transferees collectively beneficially own at least 25% of the New PBT Common Stock, to designate two Blackbeard Nominees to be nominated for election (or re-election) to our Board, and (ii) for so long as Blackbeard Security, Greybeard Energy and their permitted transferees collectively beneficially own at least 10% of the New PBT Common Stock, to designate one Blackbeard Nominee to be nominated for election (or re-election) to our Board.

The Shareholders’ Agreement will also provide SoftVest, L.P. the right, subject to certain terms and conditions contained in the Shareholders’ Agreement, for so long as SoftVest, L.P. and its permitted transferees collectively beneficially own at least 5% of the New PBT Common Stock, to designate one individual (the “SoftVest Nominee”) that qualifies as an independent director to be nominated for election (or re-election) to our Board. Until the second anniversary of the Blackbeard Contribution Closing, such SoftVest Nominee will serve as the Chairperson of the Board, if elected.

In addition, the Shareholders’ Agreement will provide that, subject to certain terms and conditions contained in the Shareholders’ Agreement, for so long as both (x) Blackbeard Security and Greybeard Energy and their respective permitted transferees, collectively beneficially own more than 25% of the New PBT Common Stock, and (y) SoftVest, L.P. and its permitted transferees, beneficially owns at least 5% of the New PBT Common Stock, we will nominate our CEO and three independent directors agreed to in good faith by Blackbeard Security, Greybeard and SoftVest, L.P. for election to the Board. Blackbeard Security, Greybeard and SoftVest, L.P. will consider in good faith that one of such three independent directors will be a representative of another significant shareholder of New PBT.

The Shareholders’ Agreement will also provide that for so long as Blackbeard Security, Greybeard Energy and their permitted transferees collectively beneficially own at least 10% of the New PBT Common Stock and for so long as SoftVest, L.P. and its permitted transferees collectively beneficially own at least 5% of the New PBT Common Stock, the Board will be composed of seven directors.

New PBT may not have sufficient available cash to pay any quarterly dividend on Class A Shares, New PBT’s cash available for dividends may vary significantly from quarter to quarter and the New PBT Board may in the future modify or revoke New PBT’s cash dividend policy at any time at its discretion. New PBT’s dividend policy could limit our ability to grow and make acquisitions.

New PBT may not have sufficient cash available to pay base or variable dividends on its Class A Shares each quarter. Furthermore, its cash dividend policy will not require it to pay dividends on a quarterly basis or otherwise. The amount of cash New PBT has to distribute each quarter principally will depend upon the amount of royalty income OpCo and its subsidiaries generate, which is dependent upon the volumes of production sold and the prices that its operators realize from the sale of such production. In addition, the actual amount of cash New PBT will have to distribute each quarter under its cash dividend policy will be reduced by payments in respect of income taxes, debt service and other contractual obligations and fixed charges, increases in reserves for future operating or capital needs that the New PBT Board may determine is appropriate, lease bonus income, distribution equivalent rights payments and preferred dividends, if any, and any common share repurchases. Additionally, if OpCo makes distributions to fund any such dividends on our Class A Shares, Blackbeard Security and Greybeard Energy, as OpCo unitholders, will be entitled to receive equivalent distributions from OpCo on a pro rata basis. However, because New PBT must pay taxes, amounts ultimately distributed as dividends to holders of Class A Shares are expected to be less on a per share basis than the amounts distributed by OpCo to Blackbeard Security and Greybeard Energy on a per unit basis. The New PBT Board may further modify or revoke its dividend policy at any time in the future at its discretion. As a result, quarterly dividends paid to holders of Class A Shares may vary significantly from quarter to quarter and may be zero.

As a result of New PBT’s cash dividend policy, New PBT will have limited cash available to reinvest in its business or to fund acquisitions, and New PBT will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund its acquisitions and growth capital expenditures. As such, to the extent the New PBT is unable to finance growth externally, its dividend policy will significantly impair its ability to grow.

To the extent that New PBT issues additional shares in connection with any acquisitions or growth capital expenditures or as in-kind dividends, the payment of dividends on those additional shares may increase the risk that New PBT will be unable to maintain or increase our per share dividend level.

Provisions of New PBT’s organizational documents could delay or prevent a change in control, limit shareholder actions and make it more difficult for shareholders to effect changes in its management.

New PBT’s organizational documents contain provisions that could have the effect of discouraging, delaying or preventing a change in control or changes in management or the New PBT Board, even if such changes would be beneficial to holders of Class A Shares. These provisions include, among others, advance-notice procedures and

other procedural requirements for shareholder nominations and proposals, and the authority of the New PBT Board to issue New PBT Preferred Stock with rights and preferences designated by the New PBT Board. These provisions could discourage unsolicited acquisition proposals or activist campaigns, reduce the likelihood that shareholders receive a premium for their shares in connection with a change in control and adversely affect the market price of Class A Shares.

The exclusive-forum provisions in our organizational documents could limit our shareholders’ ability to choose the judicial forum for disputes with us or our directors, officers or other employees.

The New PBT Charter provides that, unless New PBT consents in writing to the selection of an alternative forum, the Texas Business Court in the First Business Court Division of the State of Texas (or, if that court is not then accepting filings or lacks jurisdiction, the U.S. District Court for the Northern District of Texas, Dallas Division, or, if that court also lacks jurisdiction, the state district court of Dallas County, Texas) will be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of New PBT, (ii) any action asserting a claim for or based on a breach of a fiduciary duty owed by any current or former director, officer or other employee of New PBT to New PBT or its shareholders, including any claim alleging the aiding and abetting of such a breach, (iii) any action asserting a claim against New PBT or any current or former director, officer or other employee of New PBT arising pursuant to any provision of the TBOC, the New PBT Charter or the New PBT Bylaws (each as may be amended from time to time), or as to which the TBOC confers jurisdiction on the Business Court, (iv) any action to interpret, apply, enforce or determine the validity of the New PBT Charter or the New PBT Bylaws, (v) any action asserting a claim related to or involving New PBT that is governed by the internal affairs doctrine, (vi) any other action asserting a claim against New PBT, its directors, officers, or employees constituting an “internal entity claim” as that term is defined in Section 2.115 of the TBOC, and (vii) any other action within the jurisdiction of the Business Court, including any claims within the supplemental jurisdiction of the Business Court. In addition, the New PBT Charter provides that the federal district courts of the United States will be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act.

Notwithstanding the foregoing, the Texas exclusive-forum provision will not apply to any direct claims under the Exchange Act or to any other claim for which the federal courts of the United States have exclusive jurisdiction. These provisions may discourage lawsuits against New PBT’s directors and officers by limiting the forums in which such lawsuits may be brought and by requiring shareholders to bring certain claims in the courts of the State of Texas or the federal courts located therein. Although similar provisions have been upheld in some circumstances, a court could determine that such a provision is inapplicable or unenforceable. If a court were to find the exclusive forum provision in the New PBT Charter to be inapplicable or unenforceable with respect to one or more types of actions, New PBT may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, results of operations and financial condition.

In certain circumstances, OpCo will be required to make tax distributions to the OpCo unitholders, including New PBT, and such tax distributions may be substantial. To the extent New PBT receives tax distributions in excess of its actual tax liabilities and retains such excess cash, other OpCo unitholders would benefit from such accumulated cash balances if they exercise their Redemption Right.

To the extent OpCo has available cash, OpCo generally will be required, subject to any restrictions contained in any agreement to which OpCo is bound, to make distributions out of legally available funds to all OpCo unitholders (including New PBT) on a pro rata basis (i) in such amounts as are necessary to cause a distribution to New PBT sufficient to enable New PBT to timely satisfy its tax liabilities, and (ii) to the extent the income tax liabilities of certain OpCo unitholders (other than New PBT) with respect to their allocable share of the income of OpCo (based on certain assumptions and conventions) exceed amounts otherwise distributed by OpCo, in amounts generally intended to allow such other OpCo unitholders to satisfy such excess income tax liabilities, which such additional distributed amounts may be re-contributed to OpCo in exchange for additional OpCo units at the election of certain holders (including New PBT). The amount of such excess tax distributions will be determined based on certain assumptions, including an assumed individual income tax rate, and will be calculated after taking into account other distributions (including other tax distributions) made by OpCo.

Because tax distributions will be made pro rata based on ownership and due to, among other items, differences between the tax rates applicable to New PBT and the assumed individual income tax rate used in the calculation and requirements under the applicable tax rules that OpCo’s net taxable income be allocated disproportionately to its unitholders in certain circumstances, tax distributions may significantly exceed the actual tax liability for many of the OpCo unitholders, including New PBT. If New PBT were to retain the excess cash it receives, the other OpCo unitholders would benefit from any value attributable to such accumulated cash balances upon their exercise of the Redemption Right. However, New PBT expects to take steps to eliminate any material cash balances, including by exercising its right to re-contribute such excess cash to OpCo in exchange for additional OpCo units. Following any such contribution, OpCo will recapitalize its outstanding units to the extent necessary to cause the aggregate number of units held by New PBT to equal the number of Class A Shares outstanding, and corresponding adjustments will be made to the number of Class B Shares outstanding to the extent necessary to cause each OpCo unitholder (other than New PBT) to hold one Class B Share per OpCo unit held by it.

The tax distributions to the OpCo unitholders may be substantial and may, in the aggregate, exceed the amount of taxes that OpCo would have paid if it were a similarly situated corporate taxpayer. Funds used by OpCo to make tax distributions (and that are not re-contributed to OpCo) will not be available for reinvestment in our business.

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

New PBT and OpCo 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 other transfers of units of OpCo 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 New PBT and OpCo intend to operate such that exchanges or other transfers of units of OpCo qualify for one or more such safe harbors. For example, we intend to limit the number of holders of OpCo units, and the OpCo LLC Agreement, which will be entered into in connection with the Closing, will provide for limitations on the ability of holders of OpCo units to transfer their OpCo units and will provide New PBT, as managing member of OpCo, with the right to impose restrictions (in addition to those already in place) on the ability of holders of OpCo units 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 New PBT and for OpCo, including as a result of New PBT’s inability to file a consolidated U.S. federal income tax return with OpCo. In addition, we would no longer receive the benefit of certain increases in tax basis received in connection with the redemption of OpCo units pursuant to the Redemption Right.

USLG relies on Blackbeard to provide certain managerial functions, and pursuant to the Master Services Agreement, New PBT will rely on Blackbeard for certain managerial functions following the Business Combination.

Blackbeard provides managerial functions for USLG. USLG depends to a significant degree on the diligence, skill and network of business contacts of the Blackbeard management team and other key personnel to achieve USLG’s business objectives. Certain services required by USLG for the operation of USLG’s business, including general and administrative services, geological, geophysical and reserve engineering, lease and land administration, marketing, accounting, operational services, information technology services, compliance, insurance maintenance and management of outside professionals, are provided by Blackbeard. USLG’s reliance on Blackbeard for such services could have a material adverse effect on USLG’s business, financial condition and results of operations.

Following the Business Combination, pursuant to the Master Services Agreement, Blackbeard will provide general and administrative services, including, but not limited to, information technology, reporting services, engineering services and land administrative services, to New PBT. Our reliance on Blackbeard for such services could have a material adverse effect on our business, financial condition and results of operations. For more information on the Master Services Agreement, please see “Executive Compensation — Executive Compensation Arrangements for New PBT — Master Services Agreement” elsewhere in this proxy statement/prospectus.

New PBT’s organizational structure following the Business Combination will confer certain benefits upon Blackbeard Security and Greybeard, as OpCo unitholders, that will not benefit the holders of Class A Shares to the same extent as it will benefit Blackbeard Security and Greybeard.

New PBT’s organizational structure following the Business Combination will confer certain benefits upon Blackbeard Security and Greybeard, as OpCo unitholders, that will not benefit the holders of Class A Shares to the same extent as it will benefit Blackbeard Security and Greybeard. New PBT will be a holding company and will have no material assets other than its equity interest in OpCo. As the managing member of OpCo, New PBT may cause OpCo to make pro rata distributions of available cash to all of its unitholders, including to New PBT, in an amount sufficient to allow New PBT to fund dividends on its Class A Shares in accordance with New PBT’s dividend policy, to the extent the New PBT Board declares such dividends. Therefore, while New PBT expects to pay dividends on Class A Shares in amounts determined from time to time by the New PBT Board in the future, New PBT’s 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 New PBT, including due to the restrictions under the outstanding New PBT credit facility. Additionally, if OpCo makes such distributions, Blackbeard Security and Greybeard Energy, as OpCo unitholders, will be entitled to receive equivalent distributions from OpCo on a pro rata basis. However, because New PBT must pay taxes, amounts ultimately distributed as dividends to holders of Class A Shares are expected to be less on a per share basis than the amounts distributed by OpCo to Blackbeard Security and Greybeard Energy on a per unit basis. This and other aspects of New PBT’s organizational structure may adversely impact the future trading market for the Class A Shares.

Changes to applicable tax laws and regulations or exposure to additional income tax liabilities (including as a result of an examination of our income or other tax returns) could adversely affect New PBT’s business, cash flows and financial position.

New PBT and its subsidiaries will be 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 New PBT’s business, cash flows and financial position.

In addition, New PBT and its subsidiaries may be subject to examinations of their income, sales or other tax returns by U.S. federal, state, or local taxing authorities. An adverse outcome arising from such an examination could result in higher tax exposure, penalties, interest or other liabilities that could have an adverse effect on New PBT’s business, cash flows and financial position.

Risks Relating to USLG’s Business

USLG’s revenues are dependent on Blackbeard’s and other operators’ E&P activities on the properties underlying USLG’s mineral and royalty interests. If such companies do not maintain drilling, completion and production, the demand for the use of USLG’s land and resources, as well as the royalties that USLG receives from the production of oil, natural gas and NGLs, and related activities on USLG’s land, could be reduced, which could have a material adverse effect on USLG’s results of operations, cash flows and financial position.

USLG is not an E&P company and decisions to pursue development of a potential drilling location are made by operators on and around USLG’s properties and not by USLG. Once acreage is leased to operators, USLG is dependent on its customers to develop its properties, construct infrastructure and commence other operations on and around its land. Any development that materially and adversely affects Blackbeard and USLG’s other operators including a reduction in the expected number of wells to be drilled on USLG’s acreage by Blackbeard or its other operators, or the failure of Blackbeard or USLG’s other operators to act in its best interests and/or adequately and efficiently develop and operate USLG’s acreage could have an adverse effect on its expected growth and operational results.

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

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

•        capital expenditures, including costs required for drilling, completion and production activities, which could be significantly more than anticipated;

•        the ability to access, and cost of, capital;

•        prevailing oil, natural gas and NGLs prices;

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

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

•        regulatory developments.

The agreements USLG enters into and the sand, water and other resources that USLG or its customers sell are substantially dependent on its customers’ operations and/or drilling, completion and production on or around its land. Blackbeard and other operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in USLG’s results of operations. If Blackbeard or other operators were to reduce their development activities or otherwise reduce production on USLG’s properties, USLG’s revenues may also be substantially adversely affected.

Any development and production activities on USLG’s properties by Blackbeard are subject to its reasonable discretion. The level, success and timing of drilling and development activities on USLG’s properties, and whether Blackbeard elects to drill any additional wells on USLG’s properties, depends on a number of factors that will be largely outside of USLG’s control, including: commodity prices; the timing and amount of capital expenditures by it, which could be significantly more than anticipated; the ability of Blackbeard to access capital; the availability, high cost or shortages of rigs and other suitable drilling equipment, raw materials, supplies and oilfield services; the availability of production and transportation infrastructure and qualified operating personnel; regulatory restrictions; Blackbeard’s expertise, operating efficiency and financial resources; approval of other participants in drilling wells; Blackbeard’s expected return on investment in wells drilled on USLG’s properties as compared to opportunities in other areas; the selection of technology; the selection of counterparties for the sale of production; and the rate of production of the reserves.

For the year ended December 31, 2025, New PBT Predecessor received approximately 91% of its total revenue from Blackbeard (inclusive of revenue received from Nile Midstream). While USLG expects these revenue streams to be recurring, its contracts with Blackbeard and other operators, which represent substantially all of its revenues, typically do not contain minimum volume commitment provisions for production amounts, land use or resources to be purchased. As a result, USLG’s revenues are dependent on ongoing demand from these customers, which may decrease due to factors beyond its control. Once acreage is leased to operators, USLG’s customers make all decisions as to their operations on and around, investments in, and production from, USLG’s land, and USLG’s revenues are dependent upon decisions made by such companies, among other factors. There can be no assurance that USLG’s customers will take actions or make decisions that will be beneficial to USLG, which could result in adverse effects on its results of operations, cash flows and financial position.

Because USLG receives a significant portion of its revenue from its relationships with Nile Midstream, any development that materially and adversely affects its business, operations or financial condition could have a material adverse impact on USLG.

Nile Midstream is one of USLG’s most significant customers in the use of its land and its resources. Nile Midstream is expected to play an increasingly important role in USLG’s financial performance over the long term. Accordingly, USLG is indirectly subject to the business risks faced by Nile Midstream. Any development that materially and adversely affects Nile Midstream’s businesses, operations or financial condition could have a material adverse impact on USLG.

In addition, Nile Midstream does not own all of the land on which its infrastructure is located, and certain portions of such infrastructure located outside of USLG’s land are subject to leases, rights-of-way and easements with third parties. Such infrastructure is necessary to deliver oil, natural gas and water volumes to USLG’s land, and if Nile Midstream were to lose these rights or be required to relocate its infrastructure, USLG’s business could be materially and adversely affected as a result of such delivery interruptions. If Nile Midstream is unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, it may not be able to construct and operate its assets as anticipated, or at all, which could negatively affect USLG’s results of operations, cash flows and financial position.

Substantially all of USLG’s current revenues are derived from drilling, completion and production activities on its land that are substantially influenced by, and royalty payments that are based on, the price at which oil, natural gas and NGLs trade. Prices of oil, natural gas and NGLs are volatile due to factors beyond USLG’s control. A substantial or extended decline in commodity prices may adversely affect USLG’s business, financial condition, results of operations and cash flows.

USLG’s revenues, operating results and the carrying value of its mineral and royalty interests depend significantly upon the prevailing prices for oil, natural gas and NGLs, through the royalty payments it receives and the operations of customers on and around its land.

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile. For example, the respective conflicts with Iran and between Russia and Ukraine and Israel and Hamas 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 USLG’s and its customers’ control, including:

•        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 Federal Reserve, impacting the supply and demand for oil, natural gas and NGLs;

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

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

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

•        the level of oil, natural gas and NGLs inventories;

•        prevailing prices, and expectations regarding future prices, on local price indexes in the areas in which USLG owns land and/or mineral and royalty interests;

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

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

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

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

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

•        the price and availability of alternative fuels, including the development of alternative fuels;

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

•        increased end-user conservation;

•        political and economic conditions, such as the conflicts in Ukraine and the Middle East, including the closure of the Strait of Hormuz by Iran, in or affecting other producing regions or countries, including the Middle East, Africa, South America and Russia;

•        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 from Russia and OPEC, particularly Saudi Arabia;

•        the uncertainty in capital and commodities markets and the ability of companies in the energy sector to access capital;

•        expectations about future commodity prices; and

•        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 2025, NYMEX WTI spot prices ranged from $55.44 to $123.64 per Bbl, and the NYMEX Henry Hub spot price of natural gas has ranged from $1.21 to $30.72 per MMBtu, with five-year highs reached in 2022 and 2026, respectively. The war in Ukraine, the Israel-Hamas conflict, increased hostilities in the Middle East (including the conflict with Iran), 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+ continue to contribute to economic and pricing volatility. If the prices of oil, natural gas and NGLs decline, USLG’s operations and financial condition may be materially and adversely affected through a reduction in the use of its land and its resources and/or its customers’ services, as well as reduced revenues generated by USLG’s mineral and royalty interests. 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. Although USLG has not historically entered into any hedging arrangements, it may choose to use various derivative instruments in the future in connection with anticipated oil, natural gas and NGLs sales to minimize the impact of commodity price fluctuations. However, USLG cannot hedge the entire exposure of its operations from commodity price volatility. To the extent it does not hedge against commodity price volatility, or its hedges are not effective, USLG’s results of operations and financial position may be diminished.

USLG cannot reasonably predict whether production levels will remain at current levels or the impact the full extent of the events above may have on its industry and its 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 USLG’s land, which may reduce their willingness to develop USLG’s properties and/or use USLG’s or its customers’ services. This may result in, among other things, USLG’s having to make substantial downward adjustments to USLG’s estimated proved reserves, which could negatively impact USLG’s ability to fund its operations. If this occurs, if production estimates change or if exploration or development results deteriorate, the successful efforts method of accounting principles may require USLG to write down, as a non-cash charge to earnings, the carrying value of its oil, natural gas and NGLs properties. Operators on and around its land could also determine during periods of low commodity prices to shut in or curtail production from wells on USLG’s 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 USLG’s control. USLG’s business may be also 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.

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

The drilling activities of Blackbeard and the operators on USLG’s properties will be subject to many risks. For example, USLG will not be able to assure investors that wells drilled by Blackbeard or other operators on USLG’s properties will be productive. Drilling for oil, natural gas and NGLs often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil, natural gas or NGLs to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil, natural gas or NGLs are present or that it can be produced economically. The costs of exploration, exploitation and development activities

are subject to numerous uncertainties beyond USLG’s control, and increases in those costs can adversely affect the economics of a project. Further, operations on and around USLG’s land may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

•        declines in oil or natural gas prices;

•        infrastructure limitations;

•        the high cost of equipment, materials and services, shortages thereof or delays related thereto;

•        unexpected operational events, pipeline ruptures or spills, adverse weather conditions, facility malfunctions or title problems;

•        compliance with and changes to environmental and other governmental requirements;

•        hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives, and the regulations, restrictions, moratoria and bans thereon;

•        unusual or unexpected geological formations;

•        environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;

•        fires, blowouts, craterings and explosions;

•        uncontrollable flows of oil, natural gas or well fluids; and

•        pipeline capacity curtailments.

In addition to causing curtailments, delays and cancellations of operations, many of these events could result in substantial losses to USLG’s customers due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution, contamination or other environmental damage, clean-up responsibilities, loss of wells, regulatory investigations and penalties, suspension of operations and repairs required to resume operations. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, USLG’s financial condition, results of operations and cash flows may be materially adversely affected.

USLG’s customers may ordinarily maintain insurance against various losses and liabilities arising from their operations; however, insurance against all operational risks is not available to them. Additionally, they may elect not to obtain insurance if they believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on their business activities, financial condition and results of operations, and in turn, USLG’s business.

Blackbeard’s development and exploratory drilling efforts and its well operations may not be profitable or achieve targeted returns.

Blackbeard Holdings owns a significant amount of unproved resources, which it expects to further its development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. USLG cannot assure you that all prospects will be economically viable or that Blackbeard will not abandon its investments, including with respect to USLG’s properties. Additionally, USLG cannot assure you that undeveloped acreage leased by Blackbeard will be profitably developed, that wells drilled by Blackbeard in prospects that it pursues will be productive or that Blackbeard will recover all or any portion of its investment in such unproved property or wells, each of which could negatively affect USLG’s results of operations, cash flows and financial position.

USLG’s business is difficult to evaluate because it has a limited operating history.

New PBT Predecessor has historically not been an existing stand-alone legal entity, but rather it is a combination of certain of the assets that will be contributed to OpCo or subsidiaries of OpCo in connection with the Business Combination. As a result, New PBT Predecessor’s prior operating history and historical financial statements may not be a reliable basis for evaluating its business prospects or the future value of Class A Shares and may make it difficult to assess its ability to operate profitably.

Any acquisitions of additional surface acreage and/or mineral and royalty interests that USLG completes will be subject to substantial risks.

USLG may pursue opportunistic future land and/or mineral and royalty interest acquisitions that it expects to complement or expand its current position. It may not be able to identify attractive acquisition opportunities, and even if it does so, it may not be able to complete the acquisition on commercially acceptable terms, or at all. No assurance can be given that USLG 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 properties.

Even if USLG makes acquisitions that it believes will increase its cash generated from operations, these acquisitions may nevertheless result in a decrease in its cash flows due to, among other things, operators or customers refraining from conducting activities, such as development and production activities, on such acquired assets. Any acquisition involves potential risks, including, among other things:

•        the validity of USLG’s assumptions about estimated proved reserves, as it pertains to mineral and royalty interests, the suitability of such properties for its customers’ anticipated activities, future production and volume and timing of future production, prices, revenues, capital expenditures, the operating expenses and costs its customers would incur to develop its properties;

•        a decrease in its liquidity by using a significant portion of its cash generated from operations or incurring debt to finance acquisitions;

•        a significant increase in its interest expense or financial leverage if USLG incurs debt to finance acquisitions;

•        the assumption of unknown liabilities, losses or costs for which USLG is not indemnified or for which any indemnity USLG receives is inadequate;

•        mistaken assumptions about the overall cost of equity or debt;

•        USLG’s inability to obtain satisfactory title to the assets we acquire;

•        potential environmental and other liabilities;

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

•        regulatory, permitting and other similar matters; and

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

The accuracy of USLG’s assessments of suitable acquisition targets is inherently uncertain. Although USLG will perform a review of the subject properties that it believes to be generally consistent with industry practices, the accuracy of these assessments may not reveal all existing or potential problems or fully assess their deficiencies and capabilities. Inspections may not always be performed for the totality of such properties, 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. For example, acquiring oil and natural gas properties requires USLG to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, USLG performs a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of its due diligence, USLG may not inspect every well or pipeline. USLG cannot necessarily

observe structural and environmental problems, such as pipe corrosion, when an inspection is made. As a result, such properties may not produce as projected, and/or USLG may be unable to determine the actual reserve potential of such properties.

Such acquisitions may require substantial capital expenditures, and USLG may need capital in excess of the amounts it retains in its business. Furthermore, USLG cannot assure you that it will be able to access other external capital on terms favorable to it or at all. Additionally, its ability to secure financing or access the capital markets could be adversely affected if financial institutions and institutional lenders elect not to provide funding for traditional energy companies in connection with the adoption of sustainable lending initiatives or are required to adopt policies that have the effect of reducing the funding available thereto. If it is unable to fund its capital requirements, USLG may be unable to complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on its results of operations and free cash flow.

Further, future growth may place strains on USLG’s resources, possibly negatively affecting its results of operations, cash flows and financial positions. Its ability to grow based on such acquisitions will depend on numerous factors, including the investment by USLG’s customers in infrastructure on and around its land, the amount of use of its resources, the results of operations and drilling on and around USLG’s land and its ability to maintain or enter into new relationships with customers.

Project areas on USLG’s properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Project areas on USLG’s properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, USLG’s financial condition, results of operations and cash available for distribution may be materially affected.

The decision to pursue development of USLG’s properties will be made by operators on and around USLG’s properties and not by USLG.

Recovery of oil and natural gas underlying its mineral and royalty interests requires significant capital expenditures and successful drilling operations, and the decision to pursue development of a potential drilling location will be made by operators on and around USLG’s properties and not by USLG. There is no guarantee that such operators will fund capital expenditures and development at the pace USLG has assumed or that the results of the development will be as estimated. Increases in costs to drill and develop its properties, or decreases in commodity prices, may result in the delay of the development of USLG’s properties or may result in some projects becoming uneconomical.

If there are delays in drilling its properties, USLG’s DUCs may not be converted to producing wells in a timeframe consistent with its historic conversion cycles, and the permits on USLG’s DUCs may expire if those wells are not further developed within a specified period of time. As a result, in environments where costs to produce are high or commodity prices are depressed, operators on and around USLG’s properties may halt or reduce drilling activities.

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

One of USLG’s strategies is to expand the use of its land and resources by customers not engaged in traditional energy development. USLG may not be able to correctly identify such commercial opportunities or may be unsuccessful in attracting industry participants to develop projects on its land or to use its resources. The rapidly evolving and competitive nature of many of the industries USLG is targeting for such development makes it difficult to evaluate the future prospects of these projects. In addition, USLG has limited insight into emerging trends that may adversely affect the development of such projects on its land, the use of its resources or otherwise, and 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 USLG’s land and resources by such potential customers will be affected by many factors outside of its control and may not be successful.

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

USLG receives a portion of its revenues through agreements pursuant to which its customers develop infrastructure on its 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 USLG’s land, intervention in regulatory or administrative proceedings related to USLG’s customers’ permitting efforts or otherwise involving their assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of USLG’s 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 USLG may not realize the anticipated benefits of such projects.

USLG’s customers may also encounter technical difficulties during the construction of such infrastructure leading to a reduction in capacity or a shorter useful life. Moreover, USLG’s 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 USLG’s customers on and around its land may not be able to attract enough demand to achieve their expected investment return, which could materially and adversely affect USLG’s 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. Negative public perception or changes in governmental policies, priorities and direction could cause the permits USLG’s customers require to conduct their operations on and around USLG’s 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 USLG’s land, or which causes them to make significant expenditures not covered by insurance, could adversely affect payments to USLG in respect of use of existing infrastructure as well as future development of infrastructure on and around its land.

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

USLG’s or its 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 USLG’s 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 USLG’s or its 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 USLG’s or its customers’ ability to economically conduct operations. Limitations on USLG’s or its customers’ ability to conduct operations due to the inability to obtain or renew necessary permits or similar approvals could materially and adversely affect its results of operations, cash flows and financial position.

A significant portion of USLG’s properties are located in the CBP, making USLG vulnerable to risks associated with geographic concentration in a single geographic area.

A significant portion of USLG’s properties are located in the CBP in Texas, making USLG vulnerable to risks associated with geographic concentration in that sub-basin. In particular, USLG and its 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 and materials, 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 oil and natural gas, each of which could have a material adverse effect on USLG’s results of operations, cash flows and financial position. In addition, the effect of fluctuations on supply and demand may become more pronounced on its business as the CBP is a narrow sub-basin of the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions.

Additionally, USLG’s sand royalties may be adversely affected by risks associated with its geographic concentration, including the presence of a limited number of potential customers on or near USLG’s 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 of sand in the CBP, which could have a material adverse effect on USLG’s results of operations, cash flows and financial position.

During the year ended December 31, 2025, Blackbeard sold substantially all of the production from USLG’s mineral and royalty interests to a limited number of purchasers. The loss of any purchaser, if not replaced, could reduce USLG’s revenues and have a material adverse effect on its financial condition and results of operations.

For the year ended December 31, 2025, Plains Marketing, L.P., Anchor Crude Marketing, LLC and Energy Transfer Crude Marketing LLC and certain of their subsidiaries accounted for approximately 99% of all oil produced from USLG’s properties that was sold by Blackbeard; Targa Resources Corp. and DCP Operating Company and certain of their subsidiaries accounted for approximately 100% of all gas and NGLs produced from USLG’s properties that was sold by Blackbeard. Blackbeard depends upon a limited number of significant purchasers for the sale of production from USLG’s mineral and royalty interests. The loss of any of these customers, should USLG’s operators be unable to replace them, could adversely affect USLG’s revenues and have a material adverse effect on its financial condition and results of operations. USLG cannot assure you that any of its customers will continue to do business with it and/or its operators or that continued access to suitably liquid markets for future production will be available.

Competition in the energy industry is intense, which may adversely affect USLG’s and its customers’ ability to succeed.

The energy industry is intensely competitive, and USLG’s customers compete with other companies that may have greater resources. Many of these companies explore for and produce oil, natural gas and NGLs and conduct midstream and refining operations 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. USLG’s customers’ larger 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. USLG’s customers 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 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 USLG’s customers or, in the case of consolidation amongst USLG’s customers, may choose to focus their operations on areas outside of USLG’s properties. Further, USLG’s customers previously operated in an area in the CBP that did not have a lot of activities. However, more operators and other competitors are entering into the CBP, which may result in higher prices and expenses, and fewer opportunities, for USLG’s customers. In addition, USLG’s ability to acquire additional properties upon which potential customers may operate and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

SEC rules could limit USLG’s ability to book additional PUDs in the future.

SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. As of December 31, 2025 and 2024, approximately 32% and 30% of USLG’s total proved reserves were classified as PUDs, respectively. The PUDs located in East Ranch that were booked in USLG’s year-end 2025 reserves report were based on a limited number of offset well results that existed at that time in the immediately surrounding area. As a result of successful delineation drilling in East Ranch in 2025, East Ranch wells are expected to comprise an increasing proportion of Blackbeard’s drilling activity in the future.

This requirement may limit USLG’s ability to book additional PUDs as operators on USLG’s properties pursue their drilling programs. Moreover, USLG may be required to write-down its PUDs if those wells are not drilled within the required five-year timeframe. Furthermore, USLG makes its determinations about their estimated drilling schedules from any development plans of its affiliated operators, provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public statements of the operators on USLG’s properties. Any development and production activities on USLG’s properties are subject to its operators’ reasonable discretion, and the level, success and timing of drilling and development activities on its properties, and whether its operators elect to drill any additional wells on its acreage, depends on a number of factors that will be largely outside of its control. The accuracy of any such determination is inherently uncertain and subject to a number of assumptions and factors outside of USLG’s control. A reduction in the expected number of wells to be drilled by the operators on its properties or the failure of such operators to adequately and efficiently develop and operate its properties could have an adverse effect on USLG’s results of operations.

USLG relies on operators on its properties, third parties and government databases for information regarding its mineral and royalty interests and, to the extent that information is incorrect, incomplete, lost or otherwise inaccessible, its financial and operational information and projections may be incorrect.

As an owner of mineral and royalty interests, USLG relies on the operators of its properties to notify it of information regarding production on its properties in a timely and complete manner, as well as the accuracy of information obtained from third parties and government databases. USLG uses this information to evaluate its operations and cash flows, as well as to predict its expected production and possible future locations. To the extent USLG does not timely receive this information or the information is incomplete or incorrect, its results may be incorrect and its ability to project potential growth may be materially adversely affected. If any of such third party or government databases or systems were to fail for any reason, including as a result of a cyberattack or systems outage, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any of the foregoing consequences could material adversely affect USLG’s business.

USLG has not entered into hedging arrangements with respect to the oil and natural gas production from its properties, and it will be exposed to the impact of decreases in the price of oil and natural gas.

USLG has not entered into hedging arrangements to establish, in advance, a price for the sale of the oil and natural gas produced from its properties, although it may enter into such arrangements in the future. As a result, USLG may realize the benefit of any short-term increase in the price of oil and natural gas, but it will not be protected against decreases in price, and if the price of oil and natural gas decreases significantly, USLG’s business, results of operation and cash available for distribution may be materially adversely affected.

Estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these proved reserve estimates or underlying assumptions will materially affect the quantities and present value of USLG’s proved reserves.

It is not possible to measure underground accumulation of oil, natural gas or NGLs in an exact way. Oil, natural gas and NGLs reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGLs prices, production levels, ultimate recoveries and operating and development costs. Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Estimates of USLG’s proved reserves were prepared using SEC pricing and are based upon average commodity prices over the 12 months prior to the determination date, which may not reflect actual prices received for production related to such assets. For example, USLG’s SEC pricing proved reserve volumes and PV-10, as disclosed in this proxy statement/prospectus, are based on assumed commodity prices of $65.34 per Bbl of oil and $3.387 per MMBtu of natural gas as of December 31, 2025, which, in the case of oil, are near the low end of the five-year NYMEX forward curve range of $63.30 to $79.34 per Bbl and, in the case of natural gas, near the midpoint of the five-year NYMEX forward curve range of $2.81 to $4.71 per Mcf (as of July 14, 2026). Accordingly, you are cautioned not to place undue weight on USLG’s proved reserve volumes or PV-10, based on such pricing when evaluating USLG’s financial condition. These estimates are complex and require significant decisions and assumptions in the evaluation of available geological, engineering and economic data for

each reservoir. The reports relating to such assets rely upon various assumptions, including assumptions regarding future oil and natural gas prices, USLG’s drilling program, production levels and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may turn out to be incorrect. Estimates of USLG’s proved reserves and related valuations included in this proxy statement/prospectus were prepared by CG&A. CG&A, USLG’s independent petroleum engineering firm, conducted a detailed review of all relevant properties for the periods covered by its reserve reports using information provided by USLG.

Over time, USLG may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. In estimating reserves, USLG and its reserve engineers make certain assumptions that may prove to be incorrect, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. In addition, certain assumptions regarding future oil, natural gas and NGLs prices, production levels and operating and development costs may prove incorrect. A substantial portion of these reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. As a result, estimated quantities of reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any significant variance from these assumptions to actual figures could greatly affect the estimates of such reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and future cash generated from operations. Numerous changes over time to the assumptions on which USLG’s reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs that are ultimately recovered being different from such reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

USLG’s proved undeveloped reserves may not ultimately be developed or produced by the operators of its mineral and royalty interests or may take longer to develop than anticipated.

As of December 31, 2025, 9,425 Mboe of USLG’s 13,917 Mboe total estimated proved reserves, or 68%, were proved developed reserves. USLG’s remaining total estimated proved reserves are classified as PUDs and may not be ultimately developed or produced by the operators of its mineral and royalty interests. Conversion of PUDs into producing volumes requires significant capital expenditures and successful drilling and development by such operators. The reserve data included in the reserves reports of CG&A, its independent petroleum engineer, assume that substantial capital expenditures by such operators are required to develop such PUDs. USLG cannot be certain that the estimated costs of the development of these PUDs are accurate, that USLG’s operators will develop the properties underlying its mineral and royalty interests in accordance with any publicly announced schedule or that the results of such development will be as estimated. The development of USLG’s PUDs may take longer than expected as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, lack of proximity to, and shortage of capacity of, transportation facilities, equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services and compliance with governmental requirements, and may require higher levels of capital expenditures from the operators than anticipated. Delays in the development of USLG’s PUDs, increases in costs to drill and develop PUDs or decreases or continued volatility in commodity prices will reduce the future net cash flows of USLG’s estimated undeveloped reserves and may result in some projects becoming uneconomic for the operators of USLG’s mineral and royalty interests.

The present value of future net revenues from New PBT Predecessor’s proved reserves and those of the Hilcorp Assets and the Greybeard Assets, as reflected in the standardized measure and PV-10 value related thereto, will not necessarily be the same as the current market value of the estimated proved oil and natural gas reserves related thereto.

You should not assume that the present value of future net revenues from New PBT Predecessor’s proved reserves and those of the Hilcorp Assets and the Greybeard Assets, as reflected in the standardized measure and PV-10 value related thereto, is the current market value of such estimated oil and natural gas reserves. USLG currently bases the estimated discounted future net revenues from New PBT Predecessor’s proved reserves and the proved reserves of Hilcorp Assets and the Greybeard Assets on SEC pricing. Accordingly, you are cautioned not to

place undue weight on such reserve volumes, PV-10 or standardized measure based on such pricing when evaluating USLG’s financial condition or an investment in Class A Shares. USLG is dependent on its operators who will be affected by factors such as:

•        actual prices received for crude oil, natural gas and NGLs;

•        actual cost of development and production expenditures;

•        the amount and timing of actual production;

•        transportation and processing; and

•        changes in governmental regulations or taxation.

The timing of both the production and expenses in connection with the development and production of, and investment in, its oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor USLG uses when calculating discounted future net revenues at PV-10 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with USLG or the energy industry in general. Actual future prices and costs may differ materially from those used in the present value estimates.

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

USLG may experience delays in receiving royalty, fee and other payments from its customers or operators on its land. A failure on the part of such company to make royalty payments typically gives USLG the right to terminate the lease agreement, repossess the property and enforce payment obligations under the agreement. If USLG repossessed any of its mineral and royalty interests, it would seek a replacement operator. However, USLG might not be able to find a replacement operator and, if it did, USLG might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, with respect to a customer or operator that is subject to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), USLG’s right to enforce or terminate the agreement for any defaults, including non-payment, 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 USLG’s 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, USLG’s ability to collect amounts owed would be substantially delayed, and its ultimate recovery may be only a fraction of the amount owed or nothing. In addition, even if it is 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 USLG’s land at the same price as the customer or operator it replaced.

If commodity prices decrease to a level such that USLG’s future undiscounted cash flows from its mineral and royalty interests are less than their carrying value, USLG may be required to take write-downs of the carrying values of its mineral and royalty interests.

Accounting rules require that USLG periodically review the carrying value of its mineral and royalty interests for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, production data, economics and other factors, and the continuing evaluation of development plans, USLG may be required to write down the carrying value of its mineral and royalty interests. USLG evaluates the carrying amount of its proved oil, natural gas and NGLs properties for impairment whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying value exceeds the estimated undiscounted future cash flows, USLG would estimate the fair value of its mineral and royalty interests and record an impairment charge for any excess of the carrying value of the mineral and royalty interests over the estimated fair value of the mineral and royalty interests. Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates and a commensurate discount rate. Should capitalized costs exceed this ceiling, an impairment would be recognized. The risk that USLG will be required to recognize impairments of its oil, natural gas and NGLs reserves increases during periods of low commodity prices. In addition, impairments would occur if USLG were to experience sufficient downward adjustments to its estimated

proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period. USLG may incur impairment charges in the future, which could materially adversely affect its results of operations for the periods in which such charges are taken.

The unavailability, high cost or shortages of equipment, raw materials, supplies or personnel may restrict or result in increased costs for USLG’s customers related to their operations on and around USLG’s 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. USLG 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 USLG’s 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 USLG believes the operators on and around its 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, USLG’s financial condition and results of operations could suffer. In situations where cost inflation exceeds commodity price inflation, USLG’s profitability and cash flow, and the ability of the operators on its land to complete development activities as scheduled and on budget, may be negatively impacted. Any delay in USLG’s customers’ operations could reduce its financial condition and cash flows.

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 USLG’s land.

USLG does not operate the sand mines on its land, but USLG’s customers that conduct such operations are subject to risks normally encountered in the mining industry generally and the sand mining industry in particular. These risks include:

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

•        unanticipated ground, grade or water conditions;

•        unusual or unexpected geological formations;

•        pit wall failures or surface rock falls;

•        inclement or hazardous weather conditions, as well as any effects of climate change;

•        environmental hazards, contamination and industrial accidents;

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

•        inability to maintain necessary permits or mining or water rights;

•        restrictions on blasting operations;

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

•        fires, explosions or industrial accidents or other accidents;

•        technical difficulties or key equipment failures;

•        labor disputes;

•        late delivery of supplies; and

•        facility shutdowns in response to environmental regulatory actions.

Any of these risks could result in damage to current and future mining properties or facilities on USLG’s land, personal injury, environmental damage, delays in mining or processing, losses or possible legal liability. Any prolonged downtime or shutdowns at any of the mining properties or production facilities on USLG’s land could have a material adverse effect on USLG’s 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 USLG’s 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 USLG’s 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 USLG’s land could materially affect USLG’s results of operations, cash flows and financial position.

USLG may be subject to claims for personal injury and property damage, or for catastrophic events, which could materially and adversely affect its results of operations, cash flows and financial position.

USLG’s customers’ operations will be subject to all of the hazards and operating risks associated with their operations, which include oil and natural gas drilling, completion and production activities, sand mining, production and distribution of water, water and waste disposal and any other operations that may occur on USLG’s properties. 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, 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 safety and health issues. The occurrence of any of these events could result in substantial losses to USLG’s 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.

Litigation arising from operations on USLG’s properties may cause USLG to be named as a defendant in lawsuits asserting potentially large claims, including claims for defense, indemnity and exemplary damages. USLG generally seek indemnity from USLG’s customers for liabilities arising from their operations on its land, and USLG maintains what it believes is customary and reasonable insurance to protect its business against these potential losses, but such indemnity and insurance may not be adequate to cover USLG’s liabilities, and USLG is not fully protected or insured against all risks.

Subject to certain exceptions, USLG’s customers assume responsibility for, including control and removal of, all other pollution or contamination that may result from their operations on USLG’s properties. USLG may have liability in such cases if it is grossly negligent or commits willful acts, or as owners of the land under laws that impose strict liability for pollution clean-up, such as CERCLA (as defined herein). USLG’s customers generally agree to indemnify and defend USLG against claims relating to 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 USLG may not be able to collect under these indemnities if the applicable customer is in financial distress. USLG’s 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 USLG’s properties, but sometimes such indemnity and defense is subject to exceptions for claims resulting from USLG’s gross negligence or willful misconduct, and USLG may not be able to collect under these indemnities if the applicable customer is in financial distress. Further, USLG 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 USLG’s customers’ operations or substantial losses to USLG or its customers, which could materially and adversely affect USLG’s results of operations, cash flows and financial position.

If any operators on USLG’s properties suspend its right to receive royalty payments pursuant to its mineral and royalty interests due to title defects or other issues, USLG’s business, financial condition, results of operations and cash flows may be adversely affected.

USLG typically does not incur the expense of a title examination prior to acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights. Prior to acquiring a specific mineral and royalty interest, USLG may rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office, as USLG is not required to, and under certain circumstances it may elect not to, incur the expense of retaining lawyers to examine the title to its mineral and royalty interests. Upon a change in ownership of mineral and royalty interests, and at regular intervals pursuant to routine audit procedures at an operator’s discretion, the operator of the underlying property has the right to investigate and verify the title and ownership of mineral and royalty interests with respect to the properties it operates. It is also the normal practice in the energy industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled prior to drilling to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Furthermore, title issues may arise at a later date that were not initially detected in any title review or examination. Leases can be vulnerable to title deficiencies due to a mix of federal, state, tribal and private land or the history of land ownership in the area, resulting in complex and alternating chains of title. The existence of a material title deficiency can render a mineral and royalty interest worthless and can materially adversely affect USLG’s business results of operations, financial condition and cash flows. No assurance can be given that USLG will not suffer a monetary loss from title defects or title failure.

If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, an operator may suspend the related royalty payment. If an operator on USLG’s properties is not satisfied with the documentation it provides to validate its ownership, it may place USLG’s royalty payment in suspense until such issues are resolved, at which time USLG would receive in full the payments that would have been made during the suspension period, without interest. USLG’s failure to cure any title defects may delay or prevent USLG from utilizing the associated mineral and royalty interest. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which USLG holds a mineral and royalty interest, its business and results of operations may be adversely affected.

USLG’s insurance coverage may not fully cover its losses, and USLG may in the future encounter increased costs related to, and lack of availability of, insurance.

While USLG maintains insurance coverage at levels that it believes to be reasonable and prudent, it can provide no assurance that its current levels of insurance will be sufficient to cover any losses that it has incurred or may incur in the future, whether due to deductibles, coverage challenges or other limitations. Additionally, USLG may not be able to maintain adequate insurance in the future at rates or on other terms that it considers commercially reasonable. Additionally, insurance will not cover many types of interruptions or events that might occur and will not cover all risks associated with USLG’s business. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. The occurrence of a significant 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 materially and adversely affect USLG’s results of operations, cash flows and financial position.

A deterioration in general economic, business, political or industry conditions could materially adversely affect USLG’s results of operations, financial condition and cash flows.

Concerns over global economic conditions, energy costs, U.S. and international trade policy, geopolitical issues, including conflicts between Russia and Ukraine and in the Middle East, including the Israel-Hamas conflict and conflict with Iran, inflation, elevated interest rates, instability in the banking industry, the availability and cost of credit and slow economic growth in the United States have contributed to economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile commodity prices, and declining business and consumer confidence, may have a significant adverse impact on global financial markets

and commodity prices. For example, an oversupply of oil, natural gas or NGLs due to reduced demand as a result of slower global economic growth could lead to a severe decline in worldwide oil, natural gas and NGLs prices. Further, USLG’s customers may also experience supply chain constraints and inflationary pressure on their cost structures, which could impact the revenues USLG receives from them. USLG’s 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 USLG’s land, including regarding drilling and completion of wells, construction of infrastructure and the extraction of resources on USLG’s land. These supply chain constraints and inflationary pressures may continue to adversely impact USLG’s 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 operations on or around USLG’s land.

Cyber incidents or attacks targeting systems and infrastructure used by the energy industry may adversely impact USLG’s operations, and a cyber incident or systems failure could result in information theft, data corruption and operational disruption and USLG’s results of operations, cash flows or financial position may be adversely impacted.

USLG and its customers, and the energy industry generally, increasingly rely on information technology systems and digital technologies to operate their respective businesses. Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. The U.S. government has issued public warnings that specifically indicate energy assets could be targets of cybersecurity threats. USLG’s technologies, systems and networks, and those of USLG’s customers, affiliates and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized access, release, gathering, monitoring, misuse, loss or destruction of proprietary, personal and other information, or other disruption of business operations. USLG’s information technology and other systems for protecting against cybersecurity risks may not be sufficient, and some of these networks and systems are managed by third-party service providers and are not under its direct control. USLG regularly enters into transactions with third parties, some of whom may have less sophisticated electronic systems or networks and may be more vulnerable to cyberattacks. In addition, certain cyber incidents, such as surveillance, may remain undetected for some period of time, and cyber incidents and attacks are continually evolving and unpredictable. As cyber incidents and attacks continue to evolve, USLG may be required to expend additional resources to continue to modify or enhance its protective measures or to investigate and remediate any vulnerability to cyber incidents. While USLG utilizes various procedures and controls to reduce the risk of the occurrence of cyber incidents, there can be no assurance that its business, finances, systems and assets will not be compromised in a cyber incident. Any cyber event may divert management’s attention and could adversely affect USLG’s brand, relationships with its customers, operating results or financial condition.

Risks Relating 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 USLG’s customers, and failure to comply could result in USLG’s customers incurring significant liabilities, either of which may impact USLG’s customers’ willingness to operate on USLG’s surface acreage and/or develop USLG’s mineral and royalty interests, and may subject USLG to strict, as well as joint and several, liability for contamination resulting from such failure, even if USLG does not have control over such operations.

The value of the revenues USLG receives from the use of USLG’s surface acreage and resources, including USLG’s mineral and royalty interests, by USLG’s customers is substantially based on the level of oil and natural gas drilling and production and transportation and gathering activities with respect thereto. USLG’s customers’ level of activities on USLG’s surface acreage and/or with respect to USLG’s mineral and royalty interests are 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.

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 USLG’s 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 USLG’s customers’ operations on USLG’s 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 USLG’s customers must comply with federal, state and local laws and regulations governing conservation matters, including:

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

•        the establishment of maximum rates of production from wells;

•        the spacing of wells;

•        the plugging and abandonment of wells; and

•        the removal of related production equipment.

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has completed several regulatory actions over the last few years, consistent with the Protecting USLG’s Infrastructure of Pipelines and Enhancing Safety Act of 2020, which significantly expand 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 USLG’s customers, which in turn could affect the profitability of USLG’s surface acreage and/or mineral and royalty interests. USLG’s customers must also comply with laws and regulations prohibiting fraud and market manipulation in energy markets. To the extent USLG’s 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, USLG may be required to remediate contaminated properties owned by USLG even if a customer’s operations caused the contamination. In addition, USLG’s 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 USLG’s 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 USLG’s customers. While USLG seeks to mitigate any potential liability it may have through indemnification, customary insurance policies and remediation activities, in each case, required under USLG’s 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 USLG’s customers declare bankruptcy or if USLG’s insurance policies do not fully cover such liabilities, it may not be fully protected. Additionally, although we generally have rights to inspect USLG’s property and the operations thereon, we may not become aware of all environmental, safety and health matters. Moreover, public interest in the protection of the environment has increased over time. The general trend of more expansive and stringent environmental legislation and regulations applied to extractive industries such as those in which USLG’s 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 USLG’s customers’ operations or impose more stringent and costly operating requirements, USLG’s customers’ operations could face increased costs and potential curtailment of operations, which consequently could indirectly materially and adversely affect USLG’s business, cash flows, prospects, financial condition or results of operations. Please read “Information about US Land Guild — Regulation of Environmental and Occupational Safety and Health Matters” for a description of the laws and regulations that affect USLG’s customers and that may affect us if the Business Combination is completed.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause certain of USLG’s customers to incur increased costs, additional operating restrictions or delays and fewer potential drilling locations.

Certain of USLG’s customers engage in hydraulic fracturing. Hydraulic fracturing is an important and a 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.

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 USLG’s 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. This legislation has not been enacted.

Several federal agencies have asserted regulatory authority over certain aspects of the hydraulic fracturing process. For example, the U.S. Environmental Protection Agency (the “EPA”) has published a final rule establishing pretreatment standards that prohibit the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. In addition, the U.S. Department of the Interior’s (“DOI”) Bureau of Land Management (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 May 2026, the BLM finalized its recission of 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. Consistent with this direction, on January 30, 2026, the BLM announced a proposed rule to revise its regulations to allow for commingling of production more broadly in an effort to promote oil and gas production on Federal, Indian, private and State lands. 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. This or other federal legislation related to hydraulic fracturing may be considered again in the future, though we cannot predict the extent of any such legislation at this time.

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 their 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.

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 USLG owns surface acreage and/or mineral and royalty interests. Additional legislation or regulation could also lead to operational delays or increased operating costs for USLG’s 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 USLG’s customers’ completion of new oil and natural gas wells on USLG’s properties and an associated decrease in the production attributable to USLG’s interests, which could have a material adverse effect on USLG’s business, financial condition and results of operations.

Legislation or regulatory initiatives intended to address seismic activity, over-pressurization or subsidence could restrict drilling, completion and production activities, as well as USLG’s customers’ ability to dispose of produced water gathered from such activities, which could have a material adverse effect on their future business, which in turn could have a material adverse effect on USLG’s business.

Certain of USLG’s customers dispose of large volumes of produced water in connection with their, or their customers’, drilling and production operations pursuant to permits issued by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. For example, there exists a growing concern that the injection of produced water into certain disposal wells triggers seismic activity in certain areas, including Texas, where a majority of USLG’s surface acreage is located. This has led to the creation of operator-led response plans in certain areas in Texas by the TRRC, which can include the TRRC suspending or declining to issue produced water disposal permits, restrictions on the amount of material that can be disposed or requiring producers to cease disposal in certain areas.

State and federal regulatory agencies are continuing to study the possible linkage between oil and gas activity and induced seismicity.

In addition, a number of lawsuits have been filed in certain states alleging that disposal well operations have caused damage to neighboring properties, including through inducing seismic events, or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. In some instances, regulators may also order that disposal wells be shut in. For example, the TRRC previously published a rule governing permitting or re-permitting of produced water disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of such disposal well location, as well as logs, geologic cross sections and structure maps relating to the area in question. The TRRC has, at times, suspended produced water disposal permits within the boundaries of certain Seismic Response Areas (“SRAs”). Although USLG’s surface acreage is not currently included in any SRA, there can be no assurance that all or a portion of USLG’s surface acreage will not be included in an SRA in the future. The adoption and implementation of any new laws or regulations that restrict USLG’s customers’ ability to use hydraulic fracturing or dispose of produced water, by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring USLG’s customers to shut down such disposal wells, could limit existing operations and future development activity in affected areas by USLG’s customers and reduce their demand for the use of USLG’s surface acreage and resources, which could have a material adverse effect on USLG’s results of operations, cash flows and financial position.

Restrictions on the ability of USLG’s customers to obtain water may have an adverse effect on USLG’s 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. Historically, USLG’s customers involved in such activities have been able to purchase water from local land owners and other sources for use in their operations. Over the past several years, some areas in which USLG owns surface acreage and/or mineral and royalty interests 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. If USLG’s customers are unable to obtain water to use in their operations from local sources, or if USLG’s operators are unable to effectively utilize flowback water, they may be unable to economically drill for, or produce, oil, natural gas and NGLs from USLG’s properties, which could have an adverse effect on USLG’s financial condition, results of operations and cash flows. In addition, because USLG generates fee revenue by providing freshwater to USLG’s customers, restrictions on the use of freshwater for hydraulic fracturing or other oil and gas operations could have an adverse effect on USLG’s financial condition, results of operation and cash flows.

Produced water disposal activities on USLG’s land expose USLG to potential financial and regulatory risks.

There are unique risks associated with produced water disposal, and the legal requirements related to disposing produced water into a disposal well are subject to change based on concerns of the public or governmental authorities. There remains substantial uncertainty regarding the treatment of produced water disposal into underground formations, the regulation of which could materially and adversely affect USLG and its customers in a manner that cannot be predicted due to such uncertainty. 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 disposal wells. Federal or state regulatory agencies could require the shutdown of produced water disposal wells for safety reasons or refuse to permit the restart of any well after unplanned or planned outages. New or amended safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. Additionally, aging equipment may require more 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. Although the safety record of produced water disposal generally has been very good, accidents and other unforeseen problems have occurred. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a major environmental or catastrophic incident could materially and adversely affect USLG and USLG’s customers and limit operations on USLG’s land.

A series of risks arising out of the threat of climate change could result in increased operating costs for USLG’s 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 USLG’s business.

The operations of USLG’s 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”).

Federal agencies have also regulated various GHGs from oil and natural gas. In March 2024, 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 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, and in July 2025, extended the compliance deadlines for certain provisions until January 2027. In December 2025, the EPA issued a final rule reaffirming the interim rule and further extending the deadline for compliance with net heat value monitoring and annual report submissions. Litigation challenging the EPA’s final rule is held in abeyance while the agency reconsiders the rule, and separate litigation by environmental groups, challenging EPA’s interim final rule extending compliance deadlines remains pending. In April 2026, the EPA published a final rule amending two aspects of the March 2024 rule. First, the rule extends the baseline time limit for temporary flaring of associated gas in certain situations, with allowance in the event of extreme weather. Second, the rule revises the vent gas net heat value continuous monitoring requirements.

At the federal level, no comprehensive climate change law or regulation has been implemented to date. In November 2024, the EPA promulgated a rule implementing the Inflation Reduction Act of 2022’s (“IRA 2022”) methane emissions fee for petroleum and natural gas sources, 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. In March 2025, the EPA issued a final rule removing the methane emissions fee regulations from the Code of Federal Regulations. While the EPA cannot reissue its rule implementing the methane emissions fee (either in substantially the same form or in a new rule), the underlying requirement in the IRA 2022 remains unchanged. In addition, in September 2025, the EPA proposed to amend the Greenhouse Gas Reporting Program to remove program obligations for most source categories, including the distribution segment of the petroleum and natural gas systems source category (subpart W — Petroleum and Natural Gas Systems), and suspend program obligations for the remaining subpart W segments until reporting year 2034. Further, in February 2026, the Trump administration finalized a rule

repealing the EPA’s GHG “Endangerment Finding,” which served as the basis for the majority of the EPA’s GHG regulations, including under Subparts OOOOb and OOOOc. Litigation regarding the recission of the Endangerment Finding is ongoing. Consequently, future implementation and enforcement of these rules remains uncertain at this time.

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, climate “superfund” laws, reporting and tracking programs and restriction of GHG emissions. 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 USLG’s business or USLG’s customers’ operations, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, USLG’s or USLG’s customers’ equipment and operations could require USLG or its 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 demand for natural gas, oil and NGLs, which may also adversely affect USLG’s operations and financial results.

Furthermore, USLG and its 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 USLG’s and USLG’s 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 USLG’s customers or counterparties with which USLG’s customers contract for services may also adversely affect USLG’s operations and financial results.

Increased attention to sustainability-related matters and conservation measures may impact USLG’s business or the business of USLG’s 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 USLG’s and USLG’s customers’ products and services, reduced profits, increased investigations and litigation and negative impacts on USLG’s or USLG’s customers’ suppliers and customers, which may ultimately have adverse impacts on USLG’s or USLG’s customers’ business, such as USLG’s and USLG’s customers’ access to the capital markets as well as the value of USLG’s 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 USLG’s 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 USLG’s and USLG’s 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 ratings processes for evaluating companies on their approach to sustainability concerns. Such ratings are used by some investors to inform their investment and voting decisions. While such ratings do not impact all investors’ 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 USLG, USLG’s customers and USLG’s industry as a whole and to the diversion of investment to other industries, which could have a negative impact on USLG’s access to, and costs of, capital. Also, 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 USLG’s or USLG’s customers’ access to capital for operations. Additionally, insurers may decide to raise rates and/or cease insuring USLG or USLG’s customers based on climate change-related concerns.

COMPARATIVE PER SHARE MARKET PRICE INFORMATION AND DIVIDEND INFORMATION
AND RELATED UNITHOLDER MATTERS

New PBT

None of New PBT’s shares are currently listed or traded publicly. New PBT is a privately held company formed solely for its role in the Business Combination, the Rights Offering and the Blackbeard and Greybeard Subscription and there is no established public trading market for its securities.

New PBT had 100 issued and outstanding shares of its common stock, par value $0.01 per share, as of June 18, 2026.

If the Business Combination is completed, 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 we anticipate the revolving credit facility will contain certain financial tests and covenants that we would have to satisfy in order to have the 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. We cannot provide any assurance that we will pay dividends in the future. The declaration and payment of any dividends by us will be at the sole discretion of our board of directors, which may change any future dividend policy or discontinue payment of dividends at any time. 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, including potential acquisition opportunities;

•        legal, tax, regulatory and contractual (including under our current 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.

We will be a holding company and will have no material assets other than OpCo units. As a consequence, our ability to declare and pay dividends to the holders of our Class A Shares will be subject to the ability of our subsidiaries to make distributions to OpCo and of OpCo to make distributions to us. The ability of our subsidiaries to make distributions to OpCo will depend upon the amount of cash they generate from their businesses, the cash flow needs of our subsidiaries and the restrictions contained in our current and any future financing arrangements or any other arrangement, as well as such subsidiaries’ governing documents. For more information see “Risk Factors — Risks Relating to New PBT — New PBT will be a holding company. New PBT’s sole material asset will be its equity interest in OpCo, and New PBT will accordingly be dependent upon distributions from OpCo to pay taxes, cover its corporate and other overhead expenses and any tax liabilities of New PBT and New PBT Sub that are attributable to any taxable period (or portion thereof) ending on or prior to the Blackbeard Contribution Closing Date, and pay any dividends on New PBT Common Stock.”

If OpCo makes such distributions, holders of OpCo units will generally be entitled to receive equivalent distributions from OpCo on a pro rata basis. However, because we must pay taxes, amounts ultimately paid as dividends to holders of our Class A Shares are expected to be less on a per share basis than the amounts distributed by OpCo to the holders of OpCo units on a per-unit basis.

USLG Legacy

None of USLG Legacy’s securities are listed or traded publicly. USLG Legacy is a privately held company and there is no established public trading market for its securities.

The Trust

Market Information

The Trust Units trade on the NYSE under the ticker symbol “PBT.” As of the Record Date, there were 46,608,796 Trust Units outstanding. The total number of Unitholders as of the Record Date will be approximately        .

Distributions

The Trustee makes monthly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s liabilities, and cash reserves withheld by the Trustee, on or about the 10th business day following the completion of each month. Each distribution covers production for a one-month period. The amount of Trust revenues and cash distributions to Unitholders depends on:

•        oil, natural gas and NGL prices received;

•        volume of oil, natural gas and NGL produced and sold;

•        production costs deducted in the calculation of net proceeds of the Trust; and

•        the Trust’s general and administrative expenses and the amount of any cash reserve.

The amount of the monthly distributions fluctuate from month to month, depending on the factors discussed above. There is no minimum required distribution.

Beginning in May 2024, proceeds from Blackbeard have been received by the Trustee generally in the second month after production after the deadline to notify the NYSE of the current month distribution has passed. These funds are held for future distribution in the third month’s distribution calculation and distributed in the fourth month such that reporting and distribution of funds are one month in arrears. The identity of Unitholders entitled to a distribution is generally determined as of the last business day of each calendar month (the “monthly record date”). The amount of each monthly distribution is generally determined and announced ten days before the monthly record date. Unitholders of record as of the monthly record date are entitled to receive the calculated monthly distribution amount for each month on or before ten business days after the monthly record date. The aggregate monthly distribution amount is the excess of (i) net revenues from the Trust properties, plus any decrease in cash reserves previously established for contingent liabilities and any other cash receipts of the Trust over (ii) the expenses and payments of liabilities of the Trust plus any net increase in cash reserves for contingent liabilities.

The cash received by the Trustee consists of the amounts received by owners of the interest burdened by the Royalties from the sale of production less the sum of applicable taxes, accrued production costs, development and drilling costs, operating charges and other costs and deductions, multiplied by 75% in the case of the Waddell Ranch properties and 95% in the case of the Texas Royalty properties.

Market Value of Securities

The tables below set forth, for the respective calendar quarters indicated, the high and low sale prices reported on the NYSE for the Trust’s Units.

The following table presents trading information for the Trust Units on May 15, 2026, the last trading day before the public announcement of the proposed combination of USLG and the Trust.

The value of the Trust Units will change as the market price of the Trust Units fluctuate during the pendency of the Business Combination, and therefore will likely be different from the prices set forth above at the time you receive your Class A Shares. See the section in this offer to exchange titled “Risk Factors.”

Equity Compensation Plan Information

The Trust does not have any employees and, therefore, does not maintain any equity compensation plans.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This proxy statement/prospectus contains certain “forward-looking statements.” All statements, other than statements of historical fact, included in this proxy statement/prospectus regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this proxy statement/prospectus, the words “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar expressions and the negative of such words and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this proxy statement/prospectus.

Forward-looking statements contained in this proxy statement/prospectus include, but are not limited to, statements about:

•        the Trust’s, USLG’s and New PBT’s ability to consummate the Business Combination, the Rights Offering, the Blackbeard and Greybeard Subscription and the Backstop Commitment, and the use of expected proceeds therefrom;

•        the timing of the consummation of the Business Combination, the Rights Offering, the Blackbeard and Greybeard Subscription and the Backstop Commitment;

•        estimates of USLG’s and New PBT’s outlook on oil and natural gas prices;

•        USLG’s and New PBT’s future financial condition and results of operations, liquidity and cash flows after the Business Combination;

•        USLG’s and New PBT’s future business strategy and other plans and objectives for future operations, including, but not limited to, New PBT’s and USLG’s ability to acquire additional surface acreage and royalty interests, and risks associated thereto;

•        USLG’s and New PBT’s competitive position;

•        the operations and future development of, or on, the properties underlying USLG’s mineral and royalty interests, and related capital expenditures;

•        New PBT’s ability to access the capital markets to fund capital and other expenditures;

•        risks associated with New PBT’s reliance on Blackbeard for certain managerial and other functions pursuant to the Master Services Agreement;

•        New PBT’s payment of dividends on New PBT Common Stock;

•        USLG’s and New PBT’s assessment of their counterparty risk and the ability of their operators, customers and other counterparties to perform their future obligations;

•        the impact of federal, state and local political, regulatory, tax and environmental developments in the United States where USLG and New PBT conduct business operations;

•        the ability of New PBT to integrate the operations of the Trust and USLG and achieve or realize any anticipated benefits and expected synergies of the Business Combination;

•        the expected transfer of the majority of the assets and liabilities of the Trust into New PBT and the liquidation of the Trust thereafter;

•        the effects of USLG’s customers on its long term financial performance;

•        risks associated with macroeconomic conditions affecting the drilling for and producing of oil and natural gas, including but not limited to, declines in oil or natural gas prices, geopolitical conditions, economic conditions, weather related conditions, and the cost of capital expenditures;

•        the oil and natural gas producing abilities of the Permian Basin;

•        advancements in technology related to oil and natural gas procurement; and

•        the diversification of USLG’s revenue streams.

Should one or more of the risks or uncertainties described in this proxy statement/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 us to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this proxy statement/prospectus are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

All forward-looking statements, expressed or implied, included in this proxy statement/prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this proxy statement/prospectus.

INFORMATION ABOUT US LAND GUILD

Overview

US Land Guild: A Modern, Integrated Approach to Land and Resource Management

US Land Guild is a modern land and resource company built to generate diversified, high-margin cash flow from a large, contiguous land position in the heart of the Permian Basin. USLG’s business captures value across all stages of energy and infrastructure development through active management of its land and resources.

USLG Legacy was formed by Blackbeard Holdings, a vertically integrated oil and gas business constructed to maximize operational durability, margins and combined asset value across its footprint in the Central Basin Platform (“CBP”) a sub-basin within the Permian Basin. The upstream business, Blackbeard Operating, operates substantially all of USLG’s mineral and royalty interests today. Blackbeard Holdings is currently the largest oil and gas producer in the CBP. Nile Midstream, an affiliate of Blackbeard Holdings and USLG, services both Blackbeard Operating and third-party operators with its expansive pipeline network of oil, gas and water gathering lines, crude storage systems and water handling, produced water disposal and recycling infrastructure. Employees of Blackbeard Operating manage USLG Legacy and Nile Midstream.

Blackbeard Operating, Nile Midstream and USLG, as subsidiaries of Blackbeard Holdings, are owned by NGP, premier investors in the energy space with more than $25 billion in cumulative capital commitments. NGP has partnered alongside pioneers in natural resources and energy transition for more than 37 years, helping build several well-known Permian-focused publicly traded companies (e.g., Centennial Resources, Energy Transfer, Parsley Energy, Permian Resources, Pioneer Natural Resources and RSP Permian).

Blackbeard Operating and Nile Midstream’s activity on USLG’s land drives a significant portion of USLG’s revenue today, providing it with unique alignment and visibility to growth. USLG aims to support and encourage further commercial development across its assets, by Blackbeard Operating as well as other operators and customers, maximizing the value of each acre it holds, generating sustainable free cash flow and supporting compelling returns to its investors. USLG believes Blackbeard Operating and Nile Midstream, each with the majority of their operations and assets focused across USLG’s footprint, are aligned to extract maximum long-term value per-acre and per-produced boe.

USLG owns approximately 80,000 net royalty acres or “NRAs” (standardized to a 1/8th or 12.5% royalty interest), overlaying 143,000 gross mineral acres, and approximately 68,000 surface acres across several large and adjacent ranches in the CBP. Ownership of mineral and royalty interests and surface acreage is capital-light in nature. After the initial acquisition, USLG’s assets only incur minimal ongoing costs for expenses like taxes and maintenance. In contrast, USLG’s customers and operators bear substantially all of the operating and development costs associated with USLG’s surface acreage and mineral and royalty interests. USLG’s surface acreage is centrally located within the Permian Basin, attracting significant investment in pipelines, roads, electrical transmission and other infrastructure. USLG’s customers pay for use of its land and its resources, and USLG currently generates more than seven distinct surface revenue streams.

The Permian Basin is the oldest and most prolific oil and natural gas producing region in the United States, with approximately 6.6 MMbbls/d of oil production and over 6,900 wells completed in 2025 according to the EIA and Enverus, respectively. As of June 30, 2026, 46% of the active U.S. onshore rigs were operating in the Permian Basin according to Baker Hughes. Sitting between the Delaware and Midland Basins in West Texas and southeastern New Mexico, the CBP spans approximately 6,400 square miles. According to Enverus, about 45% of the total barrels of oil produced to-date in the Permian Basin have come from the CBP. Over the last five years, the CBP has experienced a renaissance through the application of horizontal drilling and advanced completion techniques, as operators leverage the experience gained through expansive, well-studied horizontal development programs in the Midland and Delaware sub-basins of the Permian Basin.

USLG believes it is strategically positioned to benefit from oil and natural gas production growth associated with the continued horizontal development of the CBP, as well as from the increasing demand for the natural resources, surface acreage and associated infrastructure required to facilitate such growth. Beyond the oil and natural gas value chain, USLG’s surface acreage offers multiple avenues for future potential revenue growth, including

through surface use payments from operators engaged in digital asset infrastructure and cryptocurrency mining, wind and solar power infrastructure, carbon capture, utilization and storage (“CCUS”) and non-hazardous oilfield waste reclamation.

USLG’s Sources of Revenue

USLG’s Assets

USLG owns approximately 68,000 surface acres in the CBP across 6 ranches, acquired via 6 distinct acquisitions from 2017 through 2026 — Pirate Ranch, Tortuga Ranch, Smugglers Cove Ranch, Port Royal Ranch, Cutlass Sands Ranch and J-Bar Ranch, located in Crane County, Texas.

USLG also owns mineral and royalty interests and real property interests that are generally perpetual and grant both ownership of the hydrocarbons under a tract of land and the right to lease development rights. According to its lease agreements, Blackbeard Operating operates greater than 90% of USLG’s approximately 80,000 NRAs. USLG owns an approximate 9.3% average net royalty interest across its approximately 79,000 gross mineral acres underlying the Waddell Ranch and an approximate 3.6% average royalty interest across its other approximately 63,000 gross mineral acres.

Blackbeard Operating has drilled over 270 horizontal wells to date and is currently averaging approximately 3 rigs running across USLG’s acreage. The average net production to USLG’s NRAs was approximately 5.5 Mboe/d (59% oil, 22% gas, 19% NGLs) during the first quarter of 2026. Blackbeard Operating has advised USLG that it has more than a decade of remaining drilling inventory across USLG’s position based on its current development pace. USLG’s third party reserve auditor’s forecasts for PUD locations imply an average drilling breakeven price below $40/bbl, at which a well achieves a 10% rate of return across its 90 gross proved undeveloped horizontal locations (excluding wells classified as in process in which capital has been spent prior to December 31, 2025) on USLG’s lands included in USLG’s reserve report for the year ended December 31, 2025, inclusive of its effective net revenue interest, assuming a 20:1 oil to gas pricing ratio.

Blackbeard Operating’s West Ranch development area is characterized by shallower drilling depths, lower well costs and shorter drilling cycle times than most assets in the neighboring Midland and Delaware Basins. Blackbeard Operating’s East Ranch development area is characterized by deeper unconventional reservoirs, including the emerging Barnett & Woodford targets, with higher initial production rates and total well recoveries than West Ranch, on average. Blackbeard Operating has successfully drilled more than 10 distinct horizontal zones on USLG’s land including Judkins, McKnight, Glorieta, Upper Clearfork, Lower Clearfork, Wichita Albany, and Wolfcamp (West Ranch) and Pennsylvanian (Cisco/Canyon and Strawn), Barnett, Woodford and Devonian (East Ranch).

Collectively USLG’s surface, mineral and royalty interests provide the opportunity to receive attractive and diversified income streams and nearly cost-free exposure, after initial acquisition costs, to the entire oil and natural gas life cycle. USLG will continue to evaluate opportunities to develop additional high-growth, non-correlated revenue streams related to the transitioning energy mix and the proliferation of digital technologies, including wind, solar and distributed natural gas power generation, cloud computing, artificial intelligence and cryptocurrencies which have increased the demand for land, inexpensive and reliable power, and other inputs, such as water for cooling (all of which USLG can offer).

Activity on USLG’s Land

The Permian Basin

USLG believes the Permian Basin is the most attractive oil and natural gas producing region in the United States. The Permian Basin is known for having a significant number of zones, or horizons, of oil and natural gas bearing rock that have economically recoverable reserves. The advanced application of oilfield development technologies, including horizontal drilling, modern hydraulic fracturing techniques and cube and manufacturing development designs, have significantly improved recoveries, driven cost reductions and lowered breakeven commodity prices. These technologies have unlocked additional development horizons, including formations that were once developed prior to these advancements. Technology advancements in the CBP are expected to continue to improve recovery factors, with primary recovery in most unconventional reservoirs at only 10% according to the U.S. Department of Energy.

The Central Basin Platform

USLG’s properties are located primarily within the Waddell Ranch in Crane County, Texas, in the heart of the Central Basin Platform and the Permian Basin. The CBP is situated between the Midland and Delaware Basins, the Permian Basin’s other two sub-basins, and its reservoirs are characterized by a structural high that contains trapped hydrocarbons sourced and migrated from both Basins according to the EIA. The Waddell Ranch has produced from stacked Devonian through Permian age reservoirs for more than 100 years, with cumulative oil production of approximately 450 million barrels according to Enverus.

Considered the historical backbone of the Permian Basin, the CBP’s mega fields, such as the Yates, Wasson and Slaughter, have produced billions of barrels of oil and natural gas, with billions of additional barrels still in the ground based on information from Enverus. A combination of early discovery, shallower targets, easier access and conventional characteristics drove the early development of the CBP, which has produced approximately the same amount of oil and natural gas to date as the Midland Basin and more than the Delaware Basin.

Cumulative Wells Drilled and Cumulative Oil Produced Across Permian Sub-Basins

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Source: Enverus.

CBP Renaissance through Horizontal Drilling

Historically, the CBP was developed primarily through vertical drilling and older, more traditional completion techniques. Beginning in 2021, Blackbeard piloted horizontal drilling and other modern techniques, including hydraulic fracturing, in the reservoirs on the Waddell Ranch, producing best-in-basin results.

CBP horizontal drilling activity has materially lagged that of the Midland and Delaware Basins. Operators are in the early stages of horizontal development of the CBP, that USLG believes is comparable to the horizontal development of the Midland and Delaware Basins approximately 10 to 15 years ago. At that time, much of the acreage in these basins was underdeveloped given the historic practice of vertical drilling, which inefficiently recovered oil and natural gas in reservoirs characterized by low permeability and porosity. Today, after unprecedented horizontal development activity in the Midland and Delaware Basins, operators are beginning to exhaust the remaining economically recoverable resources in such positions and USLG believes that the CBP could supply the next wave of economic Permian development.

Historical Wells Spud by Permian Sub-Basin

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Source: Enverus.

Initial horizontal development in the CBP focused on the San Andres formation. Results were highly variable, with economic wells concentrated in a few locations; however, in recent years, a few operators, including Blackbeard, have successfully optimized a sustainable horizontal drilling program in the CBP across multiple horizons. More than 10 horizontal targets have been successfully drilled, including several similar to the emerging, deeper formations now being developed in the Midland and Delaware Basins, like the Barnett, Woodford and Devonian.

Overview of Blackbeard Operating and Nile Midstream

Blackbeard Operating, which was formed by NGP and its management team in 2014, is the largest producer in the CBP with respect to gross operated production, with average gross production over 69,000 boe/d during March 2026. Blackbeard Operating is a leader in the horizontal development of the CBP, having drilled more than 320 gross horizontal wells (more than 270 of which are on USLG’s NRAs) across more than 10 distinct producing horizons since 2020. Blackbeard Operating’s horizontal drilling activity represents approximately 50% of all horizontal wells drilled in the CBP since 2021 according to Enverus, increasing from 7% in 2020 to 60% year-to-date 2026 (as of March 31, 2026).

Blackbeard Operating Historical Production Growth

As Blackbeard Operating develops oil and natural gas properties on USLG’s land, USLG receives a share of recurring revenues from the production of oil and natural gas through USLG’s ownership of royalty interests, as well as certain surface use fees related to Blackbeard’s operations on that land. Blackbeard’s durable business model and high-quality assets have supported an active drilling program through the commodity cycles. Further, Blackbeard Operating has maintained capital discipline and a healthy balance sheet, while reinvesting back into its core Permian Basin assets.

Blackbeard Operating Rigs Over Time

Nile Midstream provides the majority of strategic gathering and flow assurance to Blackbeard Operating and services certain third-party volumes. Nile Midstream’s assets include approximately 100 miles of natural gas, 100 miles of crude oil and 100 miles of water gathering pipelines, crude and water storage stations, 18 active salt water disposal wells, water transfer stations and a produced water recycling facility. Further, Nile Midstream’s assets encompass approximately 140 Mmcf/d of natural gas gathering capacity, 80 Mbpd of oil gathering capacity, 65 MBbls of crude oil storage capacity, 200 Mbpd of water disposal capacity and 120 Mbpd of produced water

recycling capacity, primarily all of which are located on USLG’s land. USLG receives a fixed fee per-barrel for all water transferred across and/or disposed into salt water disposal wells located on USLG’s surface acreage, meaning any increase in Nile Midstream’s water handling activities on USLG’s land will generate additional revenues for USLG.

The integration of these highly synergistic businesses provides Blackbeard with enhanced drilling economics and operational control as it executes its development plans on and around USLG’s land. Further, USLG’s relationship and management overlap with Blackbeard is expected to provide it with unique visibility into Blackbeard’s development plans and the associated organic growth across USLG’s assets. Access to surface, subsurface pore space (for produced water disposal) and natural resources like fresh water and sand is becoming increasing valuable to operators in the Permian Basin (both oil and gas and other industrial activity), and USLG believes it is well positioned to continue to capture value.

Customers; Material Contracts and Marketing

Customers

USLG’s customer base consists primarily of Blackbeard Operating, with respect to production on its NRAs, and Blackbeard Operating, Nile Midstream and Iron Oak Energy Solutions, with respect to the use of its surface acreage and its resources. For the year ended December 31, 2025, Blackbeard comprised more than 99% of USLG’s total oil and gas royalties revenues, and Blackbeard Operating and Nile Midstream, in total, comprised 74% of USLG’s surface use royalties and other surface and land resources revenue. Iron Oak Energy Solutions comprised 16% of USLG’s surface use royalties and other surface and land resources revenue.

Blackbeard Operating

USLG’s revenue-generating agreements with Blackbeard Operating include (i) SUAs, including customary term easements, typically for 5 to 10 year terms, subject to early termination for non-use over a specified period of time and (ii) customer oil and natural gas mineral leases with perpetual terms so long as Blackbeard Operating conducts operations thereunder. See “Certain Relationships and Related Party Transactions” for further information on USLG’s agreements with Blackbeard Operating. The terms and conditions of, and pricing for, USLG’s agreements with Blackbeard Operating are consistent with the descriptions of such agreements set forth in “New PBT Predecessor Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Generate Revenue.” The majority of USLG’s revenues from Blackbeard Operating during the year ended December 31, 2025 were generated by Blackbeard Operating’s production of oil and natural gas under USLG’s oil and natural gas mineral leases and by its other land uses, primarily the construction of oil and gas pads sites, roads and flowlines. USLG’s agreements with Blackbeard Operating do not contain minimum volume commitments, and USLG’s revenues from Blackbeard Operating can fluctuate based on the nature, timing and scope of Blackbeard Operating’s production of oil and natural gas on USLG’s mineral and royalty interests and, to a lesser extent, its activities on its land.

Blackbeard Operating markets its production from properties it operates for both USLG’s account and the account of the other working interest owners in USLG’s properties. Blackbeard Operating sells substantially all of USLG’s production to a variety of purchasers under contracts with remaining contract lives ranging from one month to more than nine years, all at market prices. Blackbeard Operating normally sells production to a relatively small number of customers, as is customary in the oil and natural gas industry. For the year ended December 31, 2025, Plains Marketing, L.P., Anchor Crude Marketing, LLC and Energy Transfer Crude Marketing LLC and certain of their subsidiaries accounted for approximately 99% of all oil produced from USLG’s properties that was sold by Blackbeard Operating, Targa Resources Corp. and DCP Operating Company and certain of their subsidiaries accounted for approximately 100% of all gas and NGLs produced from USLG’s properties that was sold by Blackbeard Operating. If Blackbeard Operating were to lose any one customer, the loss could temporarily delay the production and sale of a portion of USLG’s oil and natural gas in the related producing region; however, USLG believes Blackbeard Operating could identify a substitute customer to purchase the impacted production volumes.

Nile Midstream

USLG’s revenue-generating agreements with Nile Midstream, which is a subsidiary of Blackbeard Holdings, include SUAs, including easements and rights of way, pursuant to which Nile Midstream has constructed and operates produced water handling facilities and water recycling facilities on USLG’s land. See “Certain Relationships and Related Party Transactions — Surface use agreements” for further information on USLG’s agreements with Nile Midstream. The terms and conditions of, and pricing for, USLG’s agreements with Nile Midstream are consistent with the descriptions of such agreements set forth in “New PBT Predecessor Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Generate Revenue.” The majority of USLG’s revenues from Nile Midstream during the year ended December 31, 2025 were generated by water gathering and disposal activities on USLG’s land and its other land uses. USLG’s agreements with Nile Midstream do not contain minimum volume commitments, and USLG’s revenues from Nile Midstream can fluctuate based on the nature, timing and scope of Nile Midstream’s activities on USLG’s land.

Iron Oak Energy Solutions

USLG revenue-generating agreements with Iron Oak Energy Solutions, of which NGP holds more than a 20% equity interest, include SUAs, including easements and rights of way, pursuant to which USLG has granted certain rights to construct, operate and maintain certain sand extraction facilities on USLG’s land. See “Certain Relationships and Related Party Transactions — Transactions with Iron Oak Energy Solutions” for further information on USLG’s agreements with Iron Oak Energy Solutions. The terms and conditions of, and pricing for, USLG’s agreements with Iron Oak Energy Solutions are consistent with the descriptions of such agreements set forth in “New PBT Predecessor Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Generate Revenue.” The majority of USLG’s revenues from Iron Oak Energy Solutions during the year ended December 31, 2025 were generated by sand extraction activities on USLG’s land, with less significant revenues generated by its other land uses. USLG’s agreements with Iron Oak Energy Solutions do not contain minimum volume commitments, and USLG’s revenues from Iron Oak Energy Solutions can fluctuate based on the nature, timing and scope of Iron Oak Energy Solutions’ activities on USLG’s land.

Please see “New PBT Predecessor Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Generate Revenue” for further information regarding the ranges of USLG’s customary royalties and fees, inclusive of USLG’s royalties and fees with Blackbeard and Nile Midstream.

While USLG would expect to be able to replace these customers, the loss of Blackbeard and/or Nile Midstream as a customer could adversely affect USLG’s total revenues and have a material adverse effect on USLG’s results of operations, cash flows and financial position, whether in the short- or long-term. Furthermore, the determination by a customer to initiate or maintain activities on or around USLG’s land or with respect to USLG’s resources largely depends on the location of USLG’s properties relative to the nature and locations of such customer’s operations and such customer’s need for the use of USLG’s land and its resources, including USLG’s mineral and royalty interests. USLG’s customers generally consist of a limited universe of entities operating on and around USLG’s acreage and mineral and royalty interests in the Permian Basin.

Material Contracts and Marketing

USLG enters into various agreements with USLG’s customers in the ordinary course relating to the use of USLG’s surface acreage and its resources, including USLG’s mineral and royalty interests, and the fees, royalty rates, payment structure and other related terms in USLG’s contracts are negotiated on a case-by-case basis, taking into account the use of USLG’s surface acreage, the type of resources extracted, and the amount of use expected to be made of USLG’s surface acreage and the amount of resources to be produced and/or extracted, among other things. For a discussion regarding general market rates for similar uses of surface acreage and resources in USLG’s industry and geographic area, please see “New PBT Predecessor Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Generate Revenue.”

Although USLG’s agreements generally do not contain minimum commitment provisions for activities on or around USLG’s surface acreage, USLG may include such provisions on an individual basis based on a potential customer’s proposed use of USLG’s surface acreage and resources. Under USLG’s contracts, USLG’s customers generally bear liability for environmental, safety and health risks, through indemnification of USLG, mandated insurance coverage and covenants and representations regarding environmental, safety and health compliance for all

such risks, in each case, related to their operations on USLG’s surface acreage. Further, USLG’s contracts include inspection rights such that USLG may enter and oversee certain activities on USLG’s properties to monitor USLG’s customers’ compliance with environmental, safety and health requirements, and, following completion of the term of USLG’s agreements, USLG’s customers typically must remediate USLG’s surface acreage as close as is reasonably practicable to its state prior to such customers’ activities on the land.

•        For a description of USLG’s SUAs, see “New PBT Predecessor Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Generate Revenue — Surface Use Royalties.”

•        For a description of USLG’s oil and natural gas leases, see “New PBT Predecessor Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Generate Revenue — Oil and Natural Gas Royalties.”

In addition, USLG is a party to various agreements with affiliates relating to the use of USLG’s surface acreage and its resources, including:

•        SUAs with Blackbeard Operating, each with an initial term averaging ten years and generally allowing for automatic renewals so long as oil and natural gas operations continue on the properties identified therein, pursuant to which USLG has granted certain exclusive rights to use the surface of certain of USLG’s land as may be necessary, convenient and/or incidental to oil and gas operations and activities, including drilling of horizontal wells, oil and gas exploration and constructing, installing, operating and maintaining facilities. USLG receives compensation for use of such land. Blackbeard Operating is also generally required to purchase from USLG all crushed rock and similar materials utilized in connection with its operations upon such land. These agreements contain standard assignment and indemnification provisions;

•        salt water disposal lease agreements with each of Nile Midstream and Blackbeard Operating, each with an initial term averaging ten years and generally allowing for automatic renewals so long as oil and natural gas operations continue on the properties identified therein, pursuant to which USLG has granted certain exclusive rights on certain of USLG’s land to drill salt water disposal wells or to convert into a salt water disposal well a previously plugged and/or abandoned well and to use such wells for the injection and disposal of salt water or other deleterious substances that may be produced in connection with oil and natural gas operations. USLG receives a royalty fee for each barrel of fluid, saltwater, brackish water, produced water or any other oil or natural gas byproduct that is injected into or through the subject wells, along with fees for any damages to the adjoining land, crops or livestock that may be caused by, or result from, such use of the land. These agreements contain standard assignment and indemnification provisions;

•        right-of-way and easement agreements with each of Nile Midstream and Blackbeard Operating, each with an initial term averaging ten years and generally allowing the grantee the right to renew for additional ten-year terms, pursuant to which USLG has granted non-exclusive right-of-way and easements through certain portions of USLG’s land, including easements for pipelines to be used for transportation of produced and/or fresh water, crude oil, natural gas and associated hydrocarbons, among other materials, overhead electric supply and communications facilities and rights-of-way for the purpose of laying, constructing, installing, inspecting, repairing, maintaining, replacing and operating such facilities. USLG receives initial compensation in the form of payment for any reasonable damages to the land in connection with such easement, with the ability to receive additional payments in connection with each term extension. These agreements contain standard assignment and indemnification provisions; and

•        surface and facility site lease agreements with Nile Midstream, each with an initial term ranging between five to ten years and generally allowing the grantee the right to renew for additional five- and ten-year terms, as applicable, pursuant to which USLG has granted certain exclusive rights to construct, maintain and operate facilities and equipment on certain portions of USLG’s land. USLG receives compensation for the use of such land through lease payments, along with certain fees for surface damages and disturbances to the land, as applicable. These agreements contain standard assignment and indemnification provisions.

In addition to continuing to capitalize on existing agreements and relationships, USLG intends to pursue and acquire new commercial arrangements in an effort to develop and diversify USLG’s revenue streams. As such, USLG is currently pursuing arrangements relating to cryptocurrency mining and battery power storage, among other revenue streams. Similar to the other operations conducted on USLG’s surface acreage, USLG expects to enter into agreements with the owners of these projects from which USLG expects to receive payments in connection with the utilization of USLG’s surface acreage and its resources, but USLG would not own or operate such projects or expect to incur significant capital expenditures in connection therewith.

Infrastructure

In order to use USLG’s surface acreage to, among other things, support all stages of energy development and production to supply growing global demand, USLG has entered into various agreements through which USLG’s customers have built and own or are developing infrastructure on USLG’s land, including oil, natural gas and produced water gathering pipelines, produced water handling facilities, water recycling ponds, sand mines, cryptocurrency facilities and electric substations, as of June 30, 2026.

In addition to the above infrastructure, improvements with respect to permanent electrical infrastructure, including telecommunication lines, drilling pad sites, roads and landfills, among other things, have been made on USLG’s surface acreage that improve reliability and lower operating costs for USLG’s customers. Although infrastructure with the ability to increase revenue-generating activities is already present on USLG’s surface acreage, USLG believes that USLG’s land presents a multitude of additional opportunities for further commercialization and optimization, including coordinating with potential customers to construct infrastructure relating to digital asset infrastructure and cryptocurrency mining, data centers, wind and solar power infrastructure, CCUS and non-hazardous oilfield waste reclamation.

Oil, Natural Gas and NGLs Data

Proved Reserves

Evaluation of Proved Reserves.    Estimates of USLG’s proved reserves and PV-10 as of December 31, 2025 and 2024 reflect the arithmetic sum of the proved reserves attributable to the New PBT Predecessor, the Hilcorp Assets and the Greybeard Assets from individual reserve reports prepared by CG&A, USLG’s independent petroleum engineers, which are included as exhibits to the registration statement of which this proxy statement/prospectus forms a part. The reports of CG&A contain further discussion of the reserves estimates and its preparation procedures.

CG&A was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CG&A, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve reports incorporated herein is J. Zane Meekins, Executive Vice President. Mr. Meekins has been an employee of CG&A since 1989 and has over 39 years of industry experience. Mr. Meekins received a Bachelor of Science in Petroleum Engineering from Texas A&M University and is a registered Professional Engineer in Texas. CG&A’s responsibilities include reserves and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis.

Mr. Meekins meets or exceeds the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Mr. Meekins is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. CG&A does not have any ownership in any of USLG’s properties, and no portion of CG&A’s compensation is directly dependent on the quantity of reserves booked.

USLG’s reserve estimation process is a collaborative effort overseen by Blackbeard’s Vice President of Reservoir Engineering, who has over 16 years of experience in the estimation and evaluation of petroleum reserves. USLG’s technical staff uses historical information for USLG’s properties such as ownership interest, oil, natural gas and NGLs production, well test data, commodity prices and operating and development costs to formulate USLG’s

reserves estimates. The preparation of USLG’s proved reserve estimates is completed in accordance with USLG’s internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

•        review and verification of historical production, cost and capital expenditures data, which data is based on actual production as reported by USLG’s operators;

•        verification of property ownership;

•        preparation of reserves estimates by USLG’s lead reservoir engineers;

•        review by USLG’s management, including USLG’s Chief Executive Officer, of all significant reserve changes and all new PUDs additions; and

•        no employee’s compensation is tied to the amount of reserves booked.

Estimation of Proved Reserves.    In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. USLG’s proved reserves as of December 31, 2025 and 2024 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods, (ii) material balance-based methods, (iii) volumetric-based methods and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing and PUDs for USLG’s properties, due to the abundance of analog data.

To estimate economically recoverable proved reserves and related future net cash flows, USLG considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to USLG’s estimated proved reserves, the technologies and economic data used in the estimation of USLG’s proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core data, and historical well cost and operating expense data.

Any development and production activities on USLG’s properties are subject to USLG’s operators’ reasonable discretion, and the level, success and timing of drilling and development activities on USLG’s properties, and whether the operators elect to drill any additional wells on USLG’s acreage, depends on a number of factors that will be largely outside of USLG’s control; accordingly, USLG generally books PUDs in-line with Blackbeard’s near-term drilling schedule. As of December 31, 2025, approximately 32% of USLG’s total proved reserves based on volumes were classified as PUDs.

Summary of Reserves.    The following table sets forth estimates of USLG’s net proved oil, natural gas and NGLs reserves, PV-10 and standardized measure as of December 31, 2025 and 2024 in accordance with the rules and regulations of the SEC. All of USLG’s proved reserves are located in the United States. The increase in USLG’s estimated net proved reserves was primarily driven by extensions from Blackbeard’s ongoing development activities, which converted additional locations to proved.

The USLG reserve data presented below gives effect to the Hilcorp Assets and the acquisition of the Greybeard Assets as if each transaction had been consummated on January 1, 2024. This reserve data generally represents the arithmetic sum of the proved reserves attributable to the New PBT Predecessor and the Hilcorp Assets and the Greybeard Assets. This combined reserve data is presented for illustrative purposes only and should not be relied upon as an indication of the reserves estimates that would have been achieved if the acquisition of the Hilcorp Assets and the acquisition of the Greybeard Assets had taken place on the specified dates. In addition, future results may vary significantly from the results reflected and should not be relied on as an indication of future results. Please refer to New PBT Predecessor’s reserves reports and the reserves reports related to the Hilcorp Assets and the Greybeard Assets, which are included as exhibits to the registration statement of which this proxy statement/prospectus forms a part.

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(1)      USLG’s estimated proved reserves, PV-10 and standardized measure were determined using the average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGLs volumes, the average WTI posted price of $65.34 per barrel and $75.48 per barrel as of December 31, 2025 and 2024, respectively, was adjusted for items such as gravity, quality, local conditions, gathering transportation and distance from market. For natural gas volumes, the average Henry Hub Index spot price of $3.387 per MMBtu and $2.130 per MMBtu as of December 31, 2025 and 2024, respectively, was similarly adjusted for items such as quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted realized product prices over the remaining lives of the properties are $64.94 per barrel of oil, $0.85 per Mcf of natural gas and $20.62 per barrel of NGLs as of December 31, 2025. The average adjusted product prices over the remaining lives of the properties were $74.58 per barrel of oil, $0.25 per Mcf of natural gas and $17.08 per barrel of NGLs as of December 31, 2024.

(2)      We present total proved reserves on an Mboe basis, calculated at the rate of one barrel of oil per six Mcf of natural gas based upon the relative energy content. This is an energy content correlation and does not reflect the price or value relationship between oil and natural gas.

(3)      PV-10 is not a financial measure calculated in accordance with GAAP because it does not include the effects of income taxes. Neither PV-10 nor standardized measure represent an estimate of the fair market value of oil and natural gas properties or proved reserves. See “Information about US Land Guild — Oil, Natural Gas and NGLs Data — PV-10” for reconciliation of PV-10 to standardized measure, its most directly comparable GAAP financial measure.

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

PV-10

PV-10 is a non-GAAP financial measure and differs from the standardized measure, which is the most directly comparable GAAP financial measure. USLG refers to PV-10 as the present value of estimated future cash flows of estimated proved reserves as calculated in USLG’s reserve reports using a discount rate of 10%. This amount includes projected revenues and estimated production costs. The amount does not include any future development or abandonment costs because USLG’s interests are limited to mineral and royalty interests. Thus, USLG does not incur capital or abandonment expenditures related to the development of proved reserves.

Unlike PV-10, standardized measure takes into account future income tax expense. Neither PV-10 nor standardized measure represents an estimate of the fair market value of the applicable oil and natural gas properties. USLG believes that the presentation of PV-10 is relevant and useful because it presents the discounted future net cash flows attributable to reserves prior to taking into account future income taxes. USLG and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities. Investors should be cautioned that neither PV-10 nor standardized measure represent an estimate of the fair market value of proved reserves.

The following table presents the undiscounted estimated future net cash flows, PV-10 and standardized measure of the proved reserves of USLG at December 31, 2025 and 2024 at SEC pricing (in millions):

PUDs

The following table summarizes USLG’s changes in PUDs during the year ended December 31, 2025:

Changes in PUDs that occurred during the year ended December 31, 2025 were primarily due to:

•        well additions, extensions and discoveries of approximately 2,799 MBoe primarily due to the addition of 54 new gross well locations based on Blackbeard’s continued development of its Central Basin Platform assets;

•        Positive volume revisions of 202 MBoe consisted of positive 472 MBoe due to updates to development plans, partially offset by negative 270 MBoe related primarily to Blackbeard’s operational shift from vertical to horizontal development; and

•        the transfer of approximately 1,531 MBoe that were previously categorized as PUDs to proved developed reserves as 23 well locations were drilled and completed.

PUDs will be converted from undeveloped to developed as the applicable wells begin production. As mineral and royalty interests owners, USLG does not incur any capital expenditures or lease operating expenses in connection with the development of its PUDs, which costs are borne entirely by the working interest owners. As a result, during the year ended December 31, 2025, USLG had no expenditures to convert PUDs to proved developed reserves.

While many of USLG’s locations qualify as geologic PUDs, USLG limits its PUDs to the quantities of oil and natural gas that are reasonably certain to be recovered in the next five years. In accordance with SEC rules, its PUDs are only booked if they relate to wells that USLG reasonably expect, based on the above described assessment, to be scheduled to be drilled within five years after the date of booking. As of December 31, 2025 and 2024, approximately 32% and 30% of USLG’s total proved reserves were classified as PUDs, respectively.

Oil, Natural Gas and NGLs Production Prices and Costs

Production and Price History

The following table sets forth information regarding USLG’s operators’ net production of oil, natural gas and NGLs, all of which is from the Permian Basin in West Texas, and certain price and cost information for each of the periods indicated.

____________

(1)      We present total production on an Mboe basis, calculated at the rate of one barrel per six Mcf based upon the relative energy content. This is an energy content correlation and does not reflect the price or value relationship between oil and natural gas.

(2)      Average costs are calculated based on costs attributed to USLG’s oil, natural gas and NGL revenue. Average cost calculations do not include any costs attributed to USLG’s Surface Use or Other Surface and Land Resource Revenue.

(3)      Income tax expense reflects impacts of the Texas margin tax.

Productive Wells

Productive wells consist of producing vertical and horizontal wells, wells capable of production and exploratory, development or extension wells that are not dry wells. The table below sets forth the number of gross productive wells in which USLG owns mineral and royalty interests as of December 31, 2025. As of December 31, 2025, USLG owned an average 7.6% royalty interest in the productive oil wells and an average 9.0% royalty interest in the productive natural gas wells, in each case, as presented below. USLG’s productive wells consist of approximately 949 gross productive vertical wells and 219 gross productive horizontal wells.

Drilling Results

For the year ended December 31, 2025, 105 gross horizontal wells were drilled (9.3 net). For the year ended December 31, 2024, 91 gross horizontal wells were drilled (7.4 net). As a holder of mineral and royalty interests, USLG generally is not provided information as to whether any wells drilled on the properties underlying USLG’s acreage are classified as exploratory or as developmental wells. USLG is only aware of one dry hole drilled on the acreage underlying USLG’s mineral and royalty interests during the relevant periods.

Acreage

The following table sets forth information about USLG’s developed and undeveloped net mineral acres and NRAs as of December 31, 2025.

____________

(1)      The total gross acres in which a mineral or royalty interest is owned.

(2)      The number of acres in which an owner owns a mineral and royalty interest without giving effect to the incorporation of such acreage into a larger drilling spacing unit. For example, an owner who owns a 25%, or 1/4th, undivided interest in 100 gross mineral acres has 25 net mineral acres.

(3)      The number of acres in which an owner owns a standardized 12.5%, or 1/8th, royalty interest based on the actual number of net mineral acres in which such owner has an interest and the average mineral and royalty interest such owner has in such net mineral acres. For example, an owner who has a 25%, or 1/4th, interest in 100 net mineral acres would own 200 NRAs on a 1/8th basis (100 multiplied by 25% divided by 12.5%).

(4)      The number of acres in which an owner owns a standardized 100% royalty interest based on the actual number of net mineral acres in which such owner has an interest and the average royalty interest such owner has in such net mineral acres. For example, an owner who has a 25%, or 1/4th, royalty interest in 100 net mineral acres would own 25 NRAs on an actual or a 100% basis (100 multiplied by 25%).

Historically, a significant majority of USLG’s mineral acres have been held in fee and unleased given an affiliate of USLG was both the mineral owner and operator. Accordingly, USLG had no gross and net expiring undeveloped acreage associated with these minerals. However, in connection with the Business Combination, Blackbeard Holdings is expected to contribute certain assets to New PBT that are subject to oil and gas leases with Blackbeard with respect to a significant majority of New PBT’s net unleased mineral acres. The terms of these leases are held by existing production on the leasehold.

Regulation of Environmental and Occupational Safety and Health Matters

USLG’s customers’ business operations are subject to numerous environmental and occupational safety and health laws and regulations that may be imposed at the federal, regional, state and local levels. The activities that USLG’s customers conduct in the course of oil and natural gas exploration and production, midstream servicing, transportation and gathering, produced water disposal, sand mining and other activities are subject to or may become subject to stringent environmental regulation. USLG’s customers are responsible for compliance with various environmental laws and regulations in the course of their operations. Although USLG generally has the right to inspect its properties and the activities thereon, USLG typically does not have any control with respect to such activities. For properties in which USLG holds mineral and royalty interests, USLG generally is not subject to direct environmental liability because USLG does not own, operate or otherwise have control over any of the equipment, facilities, or operations occurring on such properties. However, with respect to land owned by USLG and leased to a customer, USLG may be subject to strict, joint and several liability for any spills or contamination on those properties, even though USLG generally has no control over operations on properties. For further information, see “Risk Factors — Risks Relating 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 USLG’s customers, and failure to comply could result in USLG’s customers incurring significant liabilities, either of which may impact USLG’s customers’ willingness to operate on USLG’s surface acreage and/or develop USLG’s mineral and royalty interests, and may subject USLG to strict, as well as joint and several, liability for contamination resulting from such failure, even if USLG does not have control over such operations.” To mitigate the risk of potential environmental liabilities that may arise in the course of operations on its properties that USLG does not control, USLG generally seeks to partner with reputable customers and seek indemnification from USLG’s customers for liabilities arising from their operations on USLG’s land, and USLG maintains what USLG believes is customary and reasonable insurance to protect USLG’s business against these potential losses. USLG also typically includes covenants relating to compliance with environmental, health and safety regulations and remediation provisions in USLG’s contracts. Additionally, USLG 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 USLG’s customers or operators. However, such actions may not

be adequate to cover USLG’s liabilities, and USLG is 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 USLG’s results of operations, cash flows and financial position, or on those of USLG’s customers.

The following is a summary of the more significant of these existing environmental and occupational safety and health laws and regulations, as amended from time to time:

•        the Clean Air Act (the “CAA”), which restricts the emission of air pollutants from many sources and imposes various pre-construction, operational, monitoring and reporting requirements;

•        the Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), which regulates discharges of pollutants into “waters of the United States,” the discharge of dredged or fill materials and imposes water quality standards;

•        the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), which imposes strict, joint and several liability on past and current owners and operators of sites where releases of hazardous substances have occurred or are threatening to occur, as well as generators, transporters and arrangers of such transport or disposal of hazardous substances disposed at such sites;

•        the Resource Conservation and Recovery Act (“RCRA”), which governs the generation, treatment, storage, transport, and disposal of hazardous wastes and establishes criteria for non-hazardous solid waste management;

•        the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provision of the CWA and imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines;

•        the SDWA, which regulates the quality of water supplied by public water systems through the adoption of drinking water standards and control of the injection of waste fluids and other substances into below-ground formations that may adversely affect drinking water sources;

•        the ESA, which requires federal agencies to ensure that actions they authorize, fund, or carry out are not likely to jeopardize the continued existence of any listed species or result in the destruction or adverse modification of designated critical habitat of such species and prohibits any action that causes a “taking” of any listed species;

•        the MBTA, which prohibits the intentional “take” (including killing, capturing, selling, trading and transport) of protected migratory bird species without prior authorization;

•        the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions significantly affecting the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment; and

•        the Occupational Safety and Health Act (“OSHA”), which establishes workplace standards for the protection of the safety and health 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 environmental 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 ground water. Additionally, there exist state and local jurisdictions in the United States where USLG operates that also have, or are developing or considering developing, similar environmental and occupational safety and health laws and regulations governing many of these same types of activities. Any failure by USLG, or USLG’s 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 and other third parties to act in place of the government and sue for alleged violations of environmental law. The ultimate financial impact arising from compliance with 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 USLG’s land has been or is now operated on by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons is not under USLG’s control. Under environmental laws such as CERCLA and RCRA, USLG could incur strict, joint and several liability for remediating hydrocarbons, hazardous substances or wastes disposed of or released by USLG, USLG’s customers or prior owners or operators. USLG also could incur costs related to the clean-up of third-party sites to which USLG sent regulated substances for disposal or to which USLG 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 can 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 exploration 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 USLG and certain of USLG’s customers’ costs to manage and dispose of generated wastes, which could have a material adverse effect on USLG and USLG’s customers’ results of operations, cash flows and financial position. Texas has received authority from the EPA to administer the RCRA program, in addition to its own state regulations.

Wastes containing naturally occurring radioactive materials (“NORM”) may also be generated in connection with USLG’s customers’ operations. Certain processes used to produce oil and natural gas may enhance the radioactivity of NORM, which may be present in oilfield wastes. Comprehensive federal regulation does not currently exist for NORM; however, the EPA has studied the impacts of technologically enhanced NORM. NORM is subject primarily to individual state radiation control regulations. For example, the TRRC generally regulates 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. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned treatment works into surface waters), which may increase the costs associated with management of NORM. To the extent that federal or state regulation increases the compliance costs for NORM disposal, USLG’s customers may incur additional costs that may make some properties unprofitable to operate.

CERCLA, also known as the “Superfund” law, and comparable state laws impose joint and several liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These potentially responsible parties include current and former owners or operators of the site where the release occurred and anyone who disposed or arranged for the disposal of, or transported, a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment, and to seek to recover from the responsible classes of person the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. While petroleum and crude oil

fractions are generally not considered hazardous substances under CERCLA and its analogues because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past.

Water Discharges

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. The discharge of dredge and fill material into regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers.

The scope of these regulated waters has been subject to controversy in recent years. In January 2023, the EPA and U.S. Army Corps of Engineers published a final rule defining “waters of the United States” according to the broader pre-2015 standards. In August 2023, the agencies issued a final rule conforming the definition of “waters of the United States” with the Supreme Court of the United States May 2023 opinion in Sackett v. EPA, which adopted the “continuous surface connection” test to determine if wetlands are “waters of the United States.” As a result of ongoing litigation challenging the January 2023 rule, the agencies are implementing the January 2023 rule, as amended by the conforming August 2023 rule, in 24 states, the District of Columbia, and the U.S. Territories. In the other 26 states, which includes Texas, the agencies are interpreting “waters of the United States” consistent with the pre-2015 regulatory regime and the Supreme Court’s decision in Sackett until further notice. In November 2025, the EPA and the U.S. Army Corps of Engineers issued a proposed rule revising the definition of “waters of the United States” as guided by the Sackett decision. The final rule, once published, is expected to be subject to challenge. Accordingly, the scope of jurisdictional waters remains uncertain at this time. To the extent any judicial ruling or administrative rulemaking or other action further changes the scope of the CWA’s jurisdiction, USLG, and USLG’s customers, could face increased costs to comply and delays with respect to obtaining permits, including for dredge and fill activities in wetland areas.

Air Emissions

The CAA and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and other requirements. These laws and regulations may require USLG’s customers to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, USLG’s customers may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in December 2020, the EPA announced its intention to leave the ozone National Ambient Air Quality Standards (“NAAQS”) unchanged at 70 parts per billion (set in October 2015); however, several groups filed litigation and the Biden Administration subsequently announced that it would reconsider the 2020 decision. In August 2023, the EPA announced a new review of the ozone NAAQS and in January 2025, promulgated a final rule setting requirements for areas reclassified as nonattainment areas for ozone. However, in June 2026, the EPA proposed a rule to revise requirements for reclassified ozone nonattainment areas such that reclassified areas must meet only the requirements for their current classification. To the extent more stringent standards are implemented, USLG’s customers could be required to incur further costs for pollution control equipment or other compliance measures, and be subject to stricter permitting requirements, which could delay or prohibit their ability to obtain such permits. Federal agencies have also regulated various GHGs from oil and natural gas operations. In March 2024, 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 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, and in July 2025, extended the compliance deadlines for certain provisions until January 2027. In December 2025, the EPA issued a final rule reaffirming the interim rule and further extending the deadline for compliance with net heat value monitoring and annual report submissions. Litigation challenging the EPA’s final rule is held in abeyance

while the agency reconsiders the rule, and separate litigation by environmental groups challenging EPA’s interim final rule extending compliance deadlines remains pending. In April 2026, EPA published a final rule amending two aspects of the March 2024 rule. First, the rule extends the baseline time limit for temporary flaring of associated gas in certain situations, with allowances in the event of extreme weather. Second, the rule revises the vent gas net heat value continuous monitoring requirements.

At the federal level, no comprehensive climate change law or regulation has been implemented to date. In November 2024, the EPA promulgated a rule implementing the IRA 2022’s methane emissions fee for petroleum and natural gas sources, 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. In March 2025, the EPA issued a final rule removing the methane emissions fee regulations from the Code of Federal Regulations. While the EPA cannot reissue its rule implementing the methane emissions fee (either in substantially the same form or in a new rule), the underlying requirement in the IRA 2022 remains unchanged. In addition, in September 2025, the EPA proposed to amend the Greenhouse Gas Reporting Program to remove program obligations for most source categories, including the distribution segment of the petroleum and natural gas systems source category (subpart W — Petroleum and Natural Gas Systems), and suspend program obligations for the remaining subpart W segments until reporting year 2034. Further, in February 2026, the Trump administration finalized a rule repealing the EPA’s GHG “Endangerment Finding,” which served as the basis for the majority of the EPA’s GHG regulations, including under Subparts OOOOb and OOOOc. Litigation regarding the recission of the Endangerment Finding is ongoing. Consequently, future implementation and enforcement of these rules remains uncertain at this time.

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 state oil and gas commissions in the jurisdiction in which USLG holds surface acreage and/or mineral and royalty interests. Although USLG’s 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 USLG’s 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 USLG and USLG’s customers’ ability to handle produced water and other substances on USLG’s land, which could adversely affect USLG’s 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 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.

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 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 seismic response areas; and (iii) suspending all produced water handling permits to inject oil and natural gas waste into deep strata within the boundaries of seismic response areas. 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 USLG’s customers’ ability to dispose of wastewater on USLG’s land by limiting volumes, disposal rates, produced water handling facility locations or otherwise, or requiring USLG’s customers to shut down produced water handling facilities, could reduce the demand for use of USLG’s land and resources and limit the fees USLG receives from the transportation and the handling of produced water on USLG’s land, which could have a material adverse effect on USLG’s results of operations, cash flows and financial position.

Hydraulic Fracturing

Certain of USLG’s customers engage in hydraulic fracturing. Hydraulic fracturing is an important and a 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. 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 upon 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. This legislation has not been enacted.

Currently, hydraulic fracturing (other than that using diesel) is generally exempt from regulation under the UIC program of the SDWA and is typically regulated by state oil and gas commissions or similar agencies. While USLG’s 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.

However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has published a final rule establishing pretreatment standards that prohibit the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. In addition, the BLM finalized a rule in April 2024 increasing royalty rates, rentals, and minimum bids for oil and gas leases on federal lands, although the Trump Administration has since proposed to rescind this rule. Separately, the BLM finalized a rule in May 2024 updating the agency’s interpretation of its mandate that conservation is a use of federal land on par with mineral extractions and other uses. Litigation challenging this rule was held in abeyance in early 2025, pending review of the rule by the Trump Administration, and the Trump Administration finalized repeal of that rule in May 2026. 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 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. Consistent with this direction, on January 30, 2026, the BLM announced a proposed rule to revise its regulations to allow for commingling of production more broadly in an effort to promote oil and gas production on Federal, Indian, private and State lands. 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. This or other federal legislation related to hydraulic fracturing may be considered again in the future, though USLG cannot predict the extent of any such legislation at this time.

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.

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

USLG owns surface acreage and/or mineral and royalty interests. Additional legislation or regulation could also lead to operational delays or increased operating costs for USLG’s 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 USLG’s customers’ completion of new oil and natural gas wells on its properties and an associated decrease in the production attributable to USLG’s interests, which could have a material adverse effect on USLG’s business, financial condition and results of operations.

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, USLG’s operations as well as the operations of USLG’s customers are subject to a series of regulatory, political, litigation, and financial risks associated with USLG and their operations, including those related to the production and processing of fossil fuels and emission of GHGs.

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, climate “superfund” laws, reporting and tracking programs and restriction of GHG emissions. Litigation risks are also increasing, as a number of parties have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. Recently, there have also been a number of lawsuits filed against companies alleging that such companies have made misleading or unsubstantiated claims with respect to the environmental benefits of their products or services, also known as greenwashing.

Endangered Species Act

In the United States, 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 MBTA. 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 USLG owns surface acreage and/or mineral and royalty interests and USLG’s customers operate, USLG’s customers’ abilities to conduct or expand operations could be limited, or USLG’s customers could be forced to incur material additional costs. For example, in May 2024, the FWS issued a final rule listing the Dunes Sagebrush Lizard as endangered under the ESA. Blackbeard has specific land reserved for the Dunes Sagebrush Lizard, which is actively present on their acreage. In November 2022, the FWS formally listed two distinct population segments of the lesser prairie-chicken under the ESA. In November 2025, the FWS and the NMFS proposed a series of rules revising the ESA regulations governing designating critical habitat, interagency cooperation, threatened species protections and critical habitat exclusions. In addition, in April 2025, the DOI reinstated a 2017 legal opinion that determined that the MBTA’s prohibitions on pursuing, hunting, taking, capturing and killing migratory birds does not apply to accidental or incidental taking or killing of migratory birds. Most recently, in July 2026, the FWS and NMFS issued a final rule rescinding the regulatory definition of “harm” to species under the ESA.

The identification or designation of previously unprotected species, such as the Dunes Sagebrush Lizard and lesser prairie chicken, as threatened or endangered, or the redesignation of a species from threatened to endangered, in areas on or around USLG’s land and/or mineral and royalty interests could cause USLG’s customers’ operations to become subject to operating restrictions or bans, including restrictions of future development activities in the subject areas, or cause USLG’s customers to incur additional costs associated with their operations on USLG’s surface acreage or with respect to USLG’s mineral and royalty interests, which could have a material adverse effect on USLG’s results of operations, cash flows and financial position.

Oil Pollution Act

The primary federal law related specifically to oil spill liability is the OPA, which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect USLG or USLG’s customers, which could have a material adverse effect on USLG’s results of operations, cash flows and financial position.

National Environmental Policy Act

NEPA requires federal agencies to evaluate major agency actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. NEPA reviews can also be challenged by environmental groups and other parties that have participated in the administrative process in court. This process can result in delaying the permitting and development of projects, may increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases. There have been several recent developments in the NEPA regulatory regime. Prompted by a Trump Administration Executive Order, in February 2025, the White House Council on Environmental Quality (“CEQ”) released an interim final rule rescinding its regulations implementing NEPA and encouraging agencies to revise their own NEPA implementing procedures. Federal agencies have begun the process of preparing their own new or updated NEPA-implementing rules or guidelines, with the first batch of updates released in July 2025. In April 2025, the DOI issued a new “alternative arrangements” policy for NEPA review of proposed fossil fuel projects, significantly expediting environmental review. In May 2025, the Supreme Court issued an opinion in Seven County Infrastructure Coalition v. Eagle County emphasizing the “substantial judicial deference” that courts must grant agencies when considering NEPA challenges. Then, in September 2025, CEQ issued new guidance to federal agencies implementing NEPA encouraging such agencies to limit their NEPA reviews, rely more heavily on sponsor-prepared documents, and streamline the NEPA process. Finally, in January 2026, CEQ adopted a final rule rescinding its regulations implementing NEPA. Congress is also considering legislation designed to streamline NEPA through the SPEED Act. The SPEED Act aims to redefine what qualifies as a “major Federal action” and impose stricter deadlines for NEPA review. The SPEED Act has passed the House of Representatives, but final passage and enactment remains uncertain. The impact of the recent and potential future changes to the NEPA regulations on USLG’s and its customers’ operations is uncertain.

Pipeline Safety Regulations

The PHMSA regulates safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural gas gathering lines. From time to time, PHMSA, the courts or Congress may make determinations that affect PHMSA’s regulations or their applicability to USLG’s customers’ pipelines. These determinations may affect the costs USLG’s customers incur in complying with applicable safety regulations.

Related Permits, Authorizations and Considerations

Many environmental laws require USLG and USLG’s customers to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

resulting in higher natural gas prices for natural gas production during the first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit exploration, drilling and producing activities and other energy operations in a portion of USLG’s operating areas. USLG’s other revenue streams 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 USLG’s control and the control of customers on or around or surface acreage.

Further, the areas in which USLG holds its properties may be impacted by certain seasonal factors. Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters resulting in higher prices. 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. Due to these seasonal fluctuations, USLG’s results of operations for individual quarterly periods may not be indicative of the results that USLG may realize on an annual basis.

Cyclical Nature of Oil and Natural Gas Industry

The oil and natural gas industry is a highly cyclical industry. Demand for the use of USLG’s surface acreage and its resources, including USLG’s mineral and royalty interests, depends substantially on activity levels by producers on and around USLG’s surface acreage. Prevailing commodity prices and future demand for, and price of, oil, natural gas and NGLs and volatility in the prices for such resources (or the perception that such prices will decrease) affects such producers’ capital expenditures and willingness to pursue development activities. As such, the willingness of USLG’s producers to engage in drilling activities on and around USLG’s surface acreage is substantially influenced by the market prices of oil, natural gas and NGLs. Producers tend to increase capital expenditures in response to increases in oil, natural gas and NGLs 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, natural gas and NGLs that can, in turn, reduce prices thereby leading to a reduction in activity levels. For these reasons, the results of USLG’s 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.

Human Capital

Employees

Following the completion of the Business Combination, New PBT’s operations will be managed through (i) its board of directors, (ii) its executive officers, (iii) management and corporate-level services provided by Blackbeard pursuant to the Master Services Agreement (the “MSA”), and (iv) management services provided by certain key employees who are expected to be directly employed by New PBT.

The management team of Blackbeard, which includes the individuals who will manage USLG, also performs similar services for Blackbeard and certain affiliates, and thus will not solely be focused on USLG’s business. See “Risk Factors — Risks Relating to USLG’s Business — USLG relies on Blackbeard to provide certain managerial functions, and pursuant to the Master Services Agreement, New PBT will rely on Blackbeard for certain managerial functions following the Business Combination.” New PBT expects Blackbeard will engage independent contractors and consultants involved in land, technical, regulatory and other disciplines to provide service with respect to the New PBT business on an as-needed basis.

Values and Culture

USLG relies on Blackbeard to provide it with management and operational services in part because of Blackbeard’s commitment to fostering a work environment in which everyone treats each other with dignity and respect and that is consistent with USLG’s core values. USLG believes that a focus on working together as a team to achieve outstanding results is key to attracting and retaining talented people. We anticipate that New PBT’s culture will be reinforced by Blackbeard’s management through holding open meetings, communicating regularly with the workforce and working to foster a culture of open communication.

Personnel Safety and Health

Safety is important to USLG and begins with the protection and safety of personnel and the communities in which USLG operates. USLG values people above all else and remain committed to making safety and health a top priority. USLG strives to comply, and expects its service providers to comply with, with all applicable safety and health laws and regulations.

Community and Social Engagement

USLG is committed to supporting and giving back to the communities in which USLG operates and live. USLG also recognizes the link between local communities, the success of USLG’s service providers and, ultimately, the success of USLG’s business.

Insurance

USLG maintains insurance coverage at levels that USLG believes are reasonable and prudent; however, as is customary in USLG’s industry, USLG does not insure fully against all risks associated with USLG’s business, either because such insurance is not available or because premium costs are considered prohibitive. USLG may not be able to maintain adequate insurance in the future at rates or on other terms USLG considers commercially reasonable and USLG’s actual coverage may not insure against many types of interruptions or events that might occur, including as a result of a lack of insurance providers offering services in USLG’s areas of operation. 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 materially adverse effect on USLG’s results of operations, cash flows and financial position. Certain of USLG’s arrangements with USLG’s customers operating on USLG’s land require the maintenance of certain levels of insurance and such customers’ indemnification of USLG to protect for such events occurring with respect to their operations.

Legal Proceedings

USLG may, from time to time, be involved in litigation, claims and other proceedings arising out of USLG’s operations in the normal course of business. USLG is currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on its financial position, results of operations or cash flows. Due to the nature of its business, USLG is, from time to time, involved in litigation or subject to disputes or claims related to its business activities, including the non-payment of royalties. In the opinion of its management, none of the pending litigation, disputes or claims against USLG, if decided adversely, will have a material adverse effect on its financial condition or results of operations.

NEW PBT PREDECESSOR MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of the results of operations, financial condition and liquidity position of New PBT Predecessor for the three months ended March 31, 2026 and 2025 and the years ended December 31, 2025 and 2024 should be read in conjunction with the accompanying financial statements and related notes included elsewhere in this proxy statement/prospectus.

The following discussion and analysis of New PBT Predecessor’s financial condition and results of operations covers periods prior to the consummation of the Business Combination described elsewhere in this proxy statement/prospectus and does not reflect its effect on future periods. The Business Combination will result in financial results that are materially different from those reflected in the historical financial statements included elsewhere in this proxy statement/prospectus.

The following discussion contains forward-looking statements that reflect New PBT Predecessor’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside its control. Its actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include market prices for oil, natural gas and natural gas liquids, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this proxy statement/prospectus, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. New PBT Predecessor does not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Unless otherwise indicated, all references in this section to “we,” “us,” or “our” refer to New PBT Predecessor before giving effect to the Business Combination. Further, the historical combined financial data included in this proxy statement/prospectus does not necessarily reflect what our financial position or results of operations would have been had we operated as a separate, stand-alone entity during those periods.

Company Overview

PBT Land and Minerals Inc. Predecessor is a modern land and resource company built to generate diversified, high-margin cash flow from a large, contiguous land position in the heart of the Permian Basin. Our business captures value across the entire energy lifecycle through active management of our land and its resources.

New PBT was formed by SoftVest, L.P. to facilitate the proposed series of asset and legal entity in a business transaction between the Trust, Greybeard Energy and Blackbeard Holdings, a large, privately held and vertically integrated energy producer in the Permian Basin of West Texas that has “cracked the code” on the economic development of oil and natural gas in the CBP, sub-basin within the Permian Basin. The upstream business, Blackbeard Operating, operates substantially all of PBT Land and Minerals, Inc.’s mineral and royalty interests today. Blackbeard’s activity on our land drives a significant portion of our revenue today, providing us with unique alignment and visibility to growth. We aim to support and encourage further commercial development across our assets, by Blackbeard as well as other operators and customers, maximizing the value of each acre we hold, generating sustainable free cash flow and supporting compelling returns to our investors.

We own approximately 80,000 NRAs, overlaying 143,000 gross mineral acres, and approximately 68,000 surface acres across several large and adjacent ranches in the CBP. Our surface acreage is centrally located within the Permian Basin, attracting significant investment in pipelines, roads, electrical transmission and other infrastructure. Our customers pay us for use of our land and its resources, and we currently generate more than seven distinct surface revenue streams.

Market Condition and Outlook

Prices for oil, natural gas and NGLs have experienced significant volatility in recent years and may continue to fluctuate due to a variety of factors, including changes in supply and demand, uncertainties regarding monetary policy, tariffs on global trade and geopolitical risks, including the conflicts between Russia and Ukraine and the Middle East. During 2025 and into 2026, commodity prices fluctuated amid continued global economic uncertainty and the recent conflict in Iran.

During 2025, demand for oil, natural gas and NGLs reflected uneven global economic activity, as elevated interest rates and inflationary pressures continued to weigh on growth. Although central banks began to ease monetary policy, rates remained relatively high, and U.S. trade policy developments, including tariffs and the potential for retaliatory measures, contributed to uncertainty and may have adversely affected global demand.

Through the first half of 2026, commodity prices initially increased significantly compared to recent periods and remain volatile amid uncertainty in global economic conditions and energy markets. Most notably, the recently conflict in Iran has had a pronounced impact on oil markets, with Brent crude rising from approximately $70 per Bbl at the beginning of the conflict to nearly $120 per Bbl at its peak. Iran’s actions in the Strait of Hormuz, which carries roughly one-fifth of global oil supply, have created significant cargo traffic bottlenecks and caused significant tightening of supply. Although prices have eased from recent peaks, they remain elevated compared to recent periods, with long-term forecasts dependent on any increased tension in the Middle East and the stability of supply through the Strait of Hormuz.

High levels of activity in the Permian Basin have resulted in industry consolidation and labor and supply chain challenges, which has impacted drilling, completion and production activity. If more operators enter into or if existing operators increase activity in the CBP, these challenges may be exacerbated. All such volatility has driven material swings in commodity prices, which has subsequently impacted development and production decisions of E&P companies. Such volatility may lead to a more difficult investing and planning environment for us and our customers.

Periods of elevated commodity prices are often accompanied by increased operating and capital costs, including higher costs for labor, oilfield goods and services. Inflationary pressures also have resulted in and may result in additional increases to costs of our customers’ oilfield goods, services and personnel, which may impact their activity on our land. Announced tariffs and international trade policies may also increase operating costs. Although the financial health of the oil and gas industry has shown improvement as compared to prior periods, to the extent elevated interest rates and inflation remain, as well as any announced or future federal or foreign tariffs, our customers may experience further cost increases for their operations which may impact their operations on our acreage and/or with respect to our mineral and royalty interests. Higher oil, natural gas and NGL prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation, any subsequent monetary policy changes or federal or international trade policies, and a significant increase in inflation and/or tariff rates, to the extent our customers are unable to recover higher costs through higher oil, natural gas and NGL prices and revenues, could negatively impact our business, financial condition and results of operations.

How We Generate Revenue

We generate revenue from multiple sources, including oil and natural gas royalties received in connection with mineral and royalty interests owned by us, the use of our surface acreage and the sale of resources from our land, among other sources. The royalty rates, fee, payment structure and other related terms in our contracts are negotiated on a case-by-case basis, and consider the surface use of our land, the type of resources extracted, the amount of use expected to be made of our land and the amount of resources to be produced and/or extracted. In any given period, the amount and sources of revenues we receive from related party transactions can fluctuate based on the nature, timing and scope of such activities on our land.

The following table presents the amount and relative percentage of each component of our revenues for the following periods:

____________

(1)      Resource royalties and other revenue for the three months ended March 31, 2025 and the years ended December 31, 2025 and 2024 have been combined into other surface and land resources revenue for comparability with the presentation adopted for the three months ended March 31, 2026. See Note 2 — Basis of Presentation to the unaudited condensed combined financial statements included elsewhere in this proxy statement/prospectus.

Our revenues depend heavily on our customers’ activities on and around our land and may vary significantly from period to period as a result of the development of new revenue streams, fluctuations in commodity prices, regulatory developments, changes in volumes produced on our land and our acquisition strategy, among other factors. For example, oil and natural gas prices have historically been volatile. Lower commodity prices may decrease our revenues as customers on and around our land decrease their activity levels in response to low commodity prices. Although we intend to pursue additional opportunities to increase our revenue streams and introduce additional revenue components, there can be no assurance that such revenue will materially diversify our revenue streams.

Oil and Natural Gas Royalties

Our oil and natural gas royalties are earned on oil and natural gas mineral interests owned by us and is our largest source of revenue. Mineral interests are real property interests that are typically perpetual and grant both ownership of the hydrocarbons under a tract of land and the right to lease development rights to a third-party. Oil and natural gas royalties are recognized as revenue when oil and natural gas products are produced or severed from the mineral lease by the operator of the properties and sold to third-party purchasers. The oil and natural gas royalties we receive are dependent upon market prices for oil and natural gas, and producer specific location and contractual price differences. Royalties from oil and natural gas production are generally negotiated on a case-by-case basis, depending on the particular mineral interests and holder of such mineral interests.

Surface Use Royalties

Our surface use royalties revenue stream derives passive, fee-based revenue from customers conducting operations on our surface acreage. We actively manage the commercial development of our land, seeking to maximize the long-term value of our surface acreage and its resources by partnering with trusted developers and by identifying and capturing new sources of revenue for our land and its resources.

SUAs, including easements and rights of way, each define allowable uses of the surface and specify payment terms. SUAs permit customers to construct and operate drilling sites, pipeline easements, roadways, electric transmission easements and other facilities and equipment on land owned by us. We typically receive a per-rod or per-acre fee based on the aggregate amount of our land that is utilized under such SUA, and often additional fees at the beginning of each renewal period. Such agreements typically include pre-defined terms for fees that we will receive for our customers’ development and use of drilling sites, new and existing roads, pipeline easements and electric transmission easements. Our SUAs generally have terms ranging between 5 years to 10 years, with early termination rights for non-use over a pre-determined period of time.

Further, certain of our SUAs require payment to us of a royalty based on a percentage of the customer’s gross revenues derived from use of our land and/or volumetric use of infrastructure installed on our land in exchange for rights of use of our land. Such SUAs typically obligate the operator to meter its volumetric utilization of

infrastructure installed on our land and to include a report of such utilization for our review along with its periodic payment. Royalties we receive from operations under such SUAs include water disposal activities on our land. Such SUAs generally have terms ranging from a minimum of 5 years to 10 years. PBT Land and Minerals, Inc. receives a royalty fee for each barrel of fluid, saltwater, brackish water, produced water or any other oil or natural gas byproduct that is injected into or through the subject wells, along with fees for any damages to the adjoining land, crops or livestock that may be caused by, or result from, such use of the land.

As discussed above, in any given year, the sources and amounts of revenues received under our SUAs may change based on the nature and scope of our customers’ activity on our land. Further, the terms of our SUAs are negotiated on a customer-by-customer basis. Our SUAs typically do not include minimum commitments with respect to the type and amount of infrastructure to be installed on our property or the amount of revenue to be received by us but do generally provide for automatic renewal-based increases in royalties that are tied to the CPI or negotiated on a case-by-case basis, depending on a number of factors, such as general economic conditions, the surface use of our land, competitor pricing and/or customer specific considerations. Our contractual provisions providing for inflation escalators are generally based on CPI or a specified fixed percentage, which may limit the amount of any single pricing increase. Such provisions may also vary as to the commencement date of such increase and the timing and calculation of the applicable adjustment based on the term of the agreement or particular use of our land. Our SUAs generally include standard provisions relating to maintenance by our customers of insurance of specified types and amounts, environmental, safety and health covenants and indemnification of us for environmental claims.

Other Surface and Land Resources Revenue

We lease our surface acreage to customers to construct and operate sand mines at their expense to provide in-basin sand for use in oil and natural gas completion operations. Such customers hold the exclusive right to mine sand from the leased surface acreage and may be required to make minimum royalty payments as a result.

Our agreements related to the sale of resources generally have terms ranging from a minimum of 1 year to 25 years, with early termination rights for non-use over a pre-determined period of time, typically 6 months. Such agreements may include certain exclusivity rights, such as the exclusive right to require the purchase of the subject resource for any operations on our land. Certain of our resource sales contracts may include minimum commitments that are negotiated on a case-by-case basis, taking into account the amount of activity on our land, the specific use of our land and any resultant production thereon, among other things. The agreements pursuant to which we receive resource royalties from sand mining activity generally have a primary term of 25 years and contain rights for renewal so long as the customer continues to operate on our land. We typically receive a fee when the contract is executed and a fixed royalty per ton of sand extracted. Such fees are negotiated on a case-by-case basis, depending on a number of factors, such as general economic conditions, the type of resources extracted the amount of use expected to be made of our land and the amount of resources to be produced and/or extracted, competitor pricing and/or customer specific considerations. During the three months ended March 31, 2026 and the year ended December 31, 2025, we did not execute any new contracts and thus did not receive such fees. For the three months ended March 31, 2026, resource royalties were derived from 10% to 15% effective royalty interests, with gross rates per ton of sand extracted ranging from $16.98 to $19.24, subject to certain minimum payment obligations. For the year ended December 31, 2025, gross resource royalty rates ranged from $17.00 to $19.73 per ton of sand extracted, subject to certain minimum payment obligations. These leases generally do not impose minimum production requirements on our customers.

These agreements typically provide rights to monitor activities on our land and contain standard provisions relating to confidentiality, indemnification of us for environmental claims, and maintenance of insurance of specified types and amounts. As discussed above, in any given year, the sources and amounts of revenues received from resource sales may change based on the nature and scope of our customers’ activity on our land.

Oil and natural gas minerals also can generate mineral lease bonus revenues. We did not receive any lease bonuses for any of the periods presented. We are eligible to receive lease bonus revenue by leasing our mineral and royalty interests to E&P companies, primarily Blackbeard. When we execute a mineral lease, the lease generally transfers the rights to any oil or natural gas discovered to the E&P company and grants us the right to a specified royalty interest payable on future production. Mineral lease bonuses are nonrefundable.

Additionally, our revenue is further supported by stable, long-term income from freshwater sales to operators for completions and other industrial uses, as well as leasing, rental and ranching income derived from our ranched acres. For our freshwater sales, we collect fee revenue on a per-barrel basis for fresh water sold to Blackbeard

and other operators, which is then used by such operators to support well completions and sand mining and other operations. Our agreements related to the sale of freshwater generally have terms ranging from a minimum of 1 year to 5 years, with early termination rights for non-use over a pre-determined period of time, typically 6 months. For the three months ended March 31, 2026, per barrel prices for freshwater sold on a spot basis ranged from $0.20 to $1.07. For the year ended December 31, 2025, per barrel prices for freshwater sold on a spot basis ranged from $0.10 to $1.07. We also receive fixed payments associated with leasing and rentals (electric substation and various surface leases) and ranching payments. We also contribute computational resources to mining pools by executing cryptographic hash functions to validate blockchain transactions in exchange for payment in the form of non-cash consideration, primarily Bitcoin.

Costs of Conducting our Business

Our costs consist primarily of production and ad valorem taxes, general and administrative, other operating expenses and depreciation, depletion and amortization. Our principal costs are as follows:

Production and Ad Valorem Taxes

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues and at fixed per-unit rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural properties and on our other property and equipment.

General and Administrative Expenses

In connection with Closing, New PBT will enter into the MSA with Blackbeard, in combination with certain key employees that are directly employed by New PBT. Pursuant the MSA, Blackbeard will manage the strategy, assets and day-to-day business and affairs of New PBT and its subsidiaries, subject to all times to applicable law, the further terms and conditions set forth in the MSA and to the supervision of the New PBT Board. As consideration for the services rendered pursuant to the MSA and Blackbeard’s overhead, including the compensation of New PBT’s executive management team that are employees of Blackbeard Holdings, New PBT will reimburse Blackbeard for all direct costs incurred on its behalf and pay an annual fee equal to $5.0 million. General and administrative expenses related to being a publicly traded company include expenses associated with annual and quarterly reporting, tax return preparation, Sarbanes-Oxley compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal fees, registrar and transfer agent fees, director and officer liability insurance costs and director/direct employee compensation.

The audited combined financial statements included elsewhere in this proxy statement/prospectus include certain support and services, including accounting, engineering, human resources, executive management, information technology, field operating support and other support. The cost of these services has been allocated to us from Blackbeard Holdings’ total general and administrative expenses on the basis of revenues. Such amounts allocated may not be indicative of the cost of operations of New PBT or the amount of future allocations.

Transaction Costs

Transaction costs consist of third-party accounting, legal and financial advisory fees incurred in connection with the Business Combination and a previously contemplated initial public offering which we are no longer pursuing. The costs of these services were paid by Blackbeard and allocated across affiliated entities contributing assets to New PBT on the basis of revenues.

Other Operating Expenses

Other operating expenses are costs incurred related to our land operations, including power and fuel, overhead and other operating expenses.

Depreciation, Depletion and Amortization

Oil and natural gas properties are accounted for in accordance with the successful efforts method of accounting. Costs of our proved oil and natural gas properties are depleted on a basin-wide basis utilizing the units-of-production method using total proved reserves.

How We Evaluate Our Operations

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

Revenue

Revenue is a key performance metric of our company. We analyze realized monthly, quarterly and annual revenues and compare the results against our internal projections and budgets. Results are used to validate existing, or when applicable update, assumptions on macroeconomic drivers of our business, contractual mix driving average unit-level revenues and E&P customer development activity and commodity pricing, absent the impact of our operating costs.

Volumes of Oil, Natural Gas and NGLs Produced

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

Number of Rigs, Permits, DUCs and Producing Wells

In order to track and assess the performance of our assets, we monitor and analyze the number of rigs currently drilling our properties. We also constantly monitor the number of permits, DUCs, completions and producing wells that are applicable to our mineral and royalty interests in an effort to evaluate near-term production from our oil and natural gas assets.

Commodity Prices

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

Oil.    The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil-pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials. The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur. Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

Natural Gas.    The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. Quality differentials result from the heating value of natural gas measured in btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher btu value and will realize a higher volumetric

price than natural gas that is predominantly methane, which has a lower btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications. Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.

NGLs.    The pricing for NGLs is generally tied to the price of oil, but varies based on geographic location and the liquid components extracted, including ethane, propane, and butane and natural gasoline, among others, and the respective market pricing for each component.

Factors Affecting the Comparability of Our Financial Results

In this proxy statement/prospectus, we present our predecessor’s historical results of operations for three months ended March 31, 2026 and 2025 and the years ended December 31, 2025 and 2024. Our future results of operations will not be comparable to the historical results of operations of our predecessor for the periods presented as a result of the acquisition of the Hilcorp Assets, as well as any new contracting activity completed through our operations. The factors described below may also affect the comparability of our financial results.

Long-Term Incentive Plan

In order to incentivize individuals providing services to New PBT, we expect the New PBT Board to adopt the 2026 Incentive Plan prior to the consummation of the Business Combination, which will become effective upon the consummation of the Business Combination, subject to the approval by Unitholders of the 2026 Plan Proposal. Any individual who is an officer or employee of New PBT, and any other person who provides services to New PBT, including the New PBT Board, will be eligible to receive awards under the 2026 Incentive Plan at the discretion of the New PBT Board or a committee thereof, as applicable. The 2026 Incentive Plan will provide for awards, from time to time, at the discretion of the New PBT Board, or a committee thereof, of options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards, and performance awards intended to align the interests of directors and service providers with those of New PBT’s 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 2026 Incentive Plan prior to the periods presented within the audited combined financial statements included elsewhere in this proxy statement/prospectus.

Acquisitions

We plan to pursue potential attractive acquisitions of additional surface acreage and/or mineral and royalty interests. We believe we will be well positioned to acquire such assets and, should such opportunities arise, identifying and executing acquisitions will be a key part of our strategy. However, if we are unable to make acquisitions on economically acceptable terms, our future growth may be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to pay dividends to our shareholders.

On June 3, 2026, we completed the acquisition of certain ranch properties (the “Ranch Acquisition”) located in the Permian Basin in Crane County, Texas for $20.0 million.

On May 30, 2025, Blackbeard Holdings completed an acquisition of both 40,400 NRAs and 14,300 surface acres located in the Permian Basin primarily in Crane County, Texas from Hilcorp Permian CT TXNM, LLC. The acquired asset value attributed to us was $60.6 million based on the fair market value of our share of assets acquired.

Any additional acquisitions will further impact the comparability of our results of operations.

Indebtedness and Interest Expense

On June 1, 2026, we entered into a secured revolving credit agreement with JPMorgan Chase Bank as the administrative agent and issuing bank (the “JPM Credit Agreement”). The JPM Credit Agreement provides for a revolving credit facility (the “JPM Revolving Credit Facility”) in the maximum aggregate revolving commitment amount of $250.0 million. The JPM Revolving Credit Facility matures on May 30, 2031. The JPM Credit Agreement

is secured by our property and equipment and requires us to maintain certain leverage and liquidity ratios. As of July 22, 2026 we had total outstanding borrowings of $98.0 million under the JPM Revolving Credit Facility and had incurred bank fees of $2.9 million.

On May 30, 2025, we entered into a secured revolving credit agreement (the “Comerica Credit Agreement”) with Comerica Bank as the administrative agent, sole book runner and lead arranger. The Comerica Credit Agreement provided for a revolving credit facility in the maximum amount of $10.0 million (the “Comerica Revolving Credit Facility”) and a term loan in the amount of $20.0 million (the “Comerica Term Loan” and, together with the Comerica Revolving Credit Facility, the “Comerica Credit Facilities”). The Comerica Revolving Credit Facility was to mature on May 30, 2030. The Comerica Term Loan required quarterly payments with final maturity on May 30, 2030. As of March 31, 2026, the Comerica Term Loan balance was $17.1 million and incurred interest at a rate of 6.5%. There were no outstanding borrowings under the Comerica Revolving Credit Facility as of March 31, 2026. The Comerica Credit Agreement was secured by our property and equipment and required us to maintain certain leverage and debt service coverage ratios. Using the borrowings under the JPM Credit Agreement and cash on hand, on June 1, 2026, we settled the outstanding debt under the Comerica Credit Agreement and terminated the Comerica Credit Agreement in connection therewith.

Historically, Blackbeard’s debt has been partially collateralized by our assets and as a result, interest expense has been allocated to us based on the relative value of our oil and natural gas interests utilized to fund its business operations and the prevailing interest rates. Any future borrowings will incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.

Public Company Expenses

Following Closing, we anticipate New PBT will incur incremental, non-recurring costs as a result of operating as a publicly traded company, including the costs associated with the initial implementation of our Sarbanes-Oxley Act internal controls and testing, as applicable. We also expect New PBT will incur additional significant and recurring expenses as a publicly traded company, including expenses associated with SEC reporting requirements, including the preparation and filing of annual and quarterly reports, Sarbanes-Oxley Act compliance expenses, expenses associated with listing the Class A Shares on the NYSE, independent auditor fees, independent petroleum engineers fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental costs and expenses are not reflected in the audited combined financial statements included elsewhere in this proxy statement/prospectus.

Income Taxes

Following Closing, New PBT will be subject to U.S. federal, state and local income taxes as a corporation on its allocable share of income of OpCo. Our predecessor was not subject to U.S. federal income tax at the entity level as our results were reported in Blackbeard Holdings’s consolidated financial results of operations. Blackbeard Holdings is a limited liability company and treated as a flow-through entity for U.S. federal income tax purposes. Thus, the audited combined financial statements included elsewhere in this proxy statement/prospectus do not contain a provision for U.S. federal income taxes. The only income tax expense that appeared in the audited combined financial statements was the Texas margin tax, to which New PBT will continue to be subject as a corporation.

Results of Operations

The following table summarizes our income and expenses for the periods indicated:

____________

(1)      Income tax expense reflects impacts of the Texas margin tax.

The following table summarizes our production data and realized prices for the periods indicated:

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025

Oil and Natural Gas Royalties

Our oil and natural gas royalty revenue is a function of oil, natural gas and NGLs production volumes sold and average prices received for those volumes. Oil and natural gas royalties increased by $10.0 million, or 106% to $19.4 million for the three months ended March 31, 2026, as compared to $9.4 million for the three months ended March 31, 2025. This increase is primarily driven by the Hilcorp Acquisition which closed after March 31, 2025 and contributed an additional 0.1 million Mboe and accounted for $6.4 million of the increase in revenue. The remaining $3.6 million increase in revenue was attributable to higher production volumes from new wells placed into service since March 31, 2025. These volume-driven increases were partially offset by lower average realized commodity prices, as reflected in the table above.

Oil revenue increased as a result of a 128% increase in production volumes sold, which added $10.1 million of revenue, partially offset by a $1.71 per barrel decrease in oil prices that reduced revenue by $0.2 million. Natural gas revenue decreased both as a result of the $2.05 per mcf decrease in natural gas price, which reduced revenue by $0.6 million and the 86% increase in volumes, which reduced revenue by $0.1 million as a result of the negative gas prices for the three months ended March 31, 2026. The NGL revenue increased as a result of a 128% increase in production volumes sold, resulting in $0.9 million in revenue partially offset by a $1.86 per barrel price decrease that reduced revenue by $0.1 million.

Surface Use Revenue

Surface use revenue decreased by $0.3 million, or 6%, to $4.8 million for the three months ended March 31, 2026, as compared to $5.1 million for the three months ended March 31, 2025. The decrease was attributable to a $2.0 million decline in surface usage governed through SUAs partially offset by increased produced water gathering and injection volumes on our properties which resulted in $1.7 million of higher revenues during the three months ended March 31, 2026, as compared to the three months ended March 31, 2025.

Other surface and land resources revenue

Other surface and land resources revenue decreased by $0.1 million, or 7%, to $1.4 million for the three months ended March 31, 2026, as compared to $1.5 million for the three months ended March 31, 2025. The gross realized prices on sand extracted and shipped from our land decreased 3% to $17.78 per ton for the three months ended March 31, 2026 as compared to $18.32 per ton for the three months ended March 31, 2025. Sand volumes extracted and shipped from our land decreased 19% which, together with lower realized sand prices, contributed to a $0.3 million decrease in other surface and land resources revenue. This decline was partially offset by a $0.2 million increase in freshwater sales.

Change in Fair Value of Digital Assets

Change in fair value of digital assets decreased by $0.1 million, or 100%. The change in fair value of digital assets resulted in a loss of $0.2 million for the three months ended March 31, 2026, as compared to a loss of $0.1 million for the three months ended March 31, 2025. The change was primarily driven by fluctuations in Bitcoin indexed pricing as reported on Coinbase at 23:59:59 coordinated universal time.

Production and Ad Valorem Taxes

Production and ad valorem tax expenses increased by $0.9 million, or 150%, to $1.5 million for the three months ended March 31, 2026, as compared to $0.6 million for the three months ended March 31, 2025. Taxes are based, among other factors, on property values driven by prior year commodity prices. Oil prices decreased for the year ended December 31, 2025, as compared to the year ended December 31, 2024; however, increased production volumes from the Hilcorp Acquisition accounted for $0.3 million of the increase in production and ad valorem taxes during 2026. The remaining $0.6 million increase was primarily attributable to continued increased drilling and property development during the three months ended March 31, 2026.

General and Administrative

General and administrative expenses increased by $0.4 million, or 80%, to $0.9 million for the three months ended March 31, 2026, as compared to $0.5 million for the three months ended March 31, 2025. These expenses consist of allocations from Blackbeard for corporate support services, including accounting, engineering, human resources, executive management, information technology, field operations support and other administrative functions. Blackbeard allocates these costs on the basis of revenues. Our growing share of Blackbeard’s revenue base, inclusive of the Hilcorp Acquisition, resulted in the additional $0.4 million of allocated general and administrative expenses.

Transaction Costs

Transaction costs were $1.2 million for the three months ended March 31, 2026. These costs are legal, tax and accounting advisory fees initially incurred in connection with a previously contemplated initial public offering which we are no longer pursuing. There were no transaction costs for the three months ended March 31, 2025.

Other Operating Expenses

Other operating expenses remained relatively consistent for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expenses increased by $1.7 million, or 68%, to $4.2 million for the three months ended March 31, 2026, as compared to $2.5 million for the three months ended March 31, 2025. The increase was primarily attributable to a 117% increase in production as a result of the Hilcorp Acquisition and operational growth. The increase was partially offset by a lower depletion rate of $9.26 per boe for the three months ended March 31, 2026, as compared to $12.09 per boe for the year ended March 31, 2025, resulting from an increase in our reserves estimates used in the unit-of-production calculation primarily as a result of the uplift in reserves resulting from Blackbeard’s continued development.

Interest Expense, Net

Interest expense, net increased by $0.4 million, or 100%, to $0.8 million for the three months ended March 31, 2026, as compared to $0.4 million the three months ended March 31, 2025 primarily due to the Comerica Term Loan which was drawn after March 31, 2025 and resulted in $0.3 million of interest expense. The remaining $0.1 million increase is related to additional interest expense allocated from Blackbeard Holdings after the Hilcorp Acquisition.

Income Tax Expense

Income tax expense remained relatively consistent for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025.

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

Oil and Natural Gas Royalties

Our oil and natural gas royalty revenue is a function of oil, natural gas and NGLs production volumes sold and average prices received for those volumes. Oil and natural gas royalties increased by $23.6 million, or 86%, to $51.1 million for the year ended December 31, 2025, as compared to $27.5 million for the year ended December 31, 2024 primarily resulting from the Hilcorp Acquisition which closed on May 30, 2025, which contributed an additional 0.3 million Mboe and accounted for $11.6 million of the increase in revenue. The remaining $12.0 million increase in revenue was attributable to higher production volumes resulting from new wells placed into service during 2025. These volume-driven increases were partially offset by lower average realized commodity prices, as reflected in the table above.

Oil revenue increased as a result of a 121% increase in production volumes sold, generating $25.4 million in additional revenue, partially offset by an $11.37 per barrel decrease in oil prices, which reduced revenue by $3.8 million. Natural gas revenue increased as a result of a 61% increase in natural gas volumes sold, contributing $0.4 million in additional revenue, while the $0.28 per Mcf increase in natural gas prices contributed $0.3 million in higher revenue. The NGL revenue increased as a result of a 68% increase in production volumes sold, resulting in $1.5 million in additional revenue, partially offset by a $1.49 per barrel price decline, which reduced revenue by $0.2 million.

Surface Use Revenue

Surface use revenue increased by $8.5 million, or 91%, to $17.8 million for the year ended December 31, 2025, as compared to $9.3 million for the year ended December 31, 2024. The increase was primarily attributable to increased surface usage governed through SUAs of $7.0 million, of which $2.9 million is related to one-time surface use payments for discrete, defined, non-exclusive surface use rights. Additionally, increased produced water injection volumes on our properties resulted in approximately $1.5 million higher revenues during the year ended December 31, 2025, as compared to the year ended December 31, 2024.

Other surface and land resources revenue

Other surface and land resources revenue increased by $0.1 million, or 2%, to $6.4 million for the year ended December 31, 2025, as compared to $6.3 million for the year ended December 31, 2024. The increase was driven by a $0.3 million in increased freshwater sales due to higher water demand and a $0.3 million increase in revenue generated from use of the electrical substation on our land. These increases were partially offset by a $0.3 million decrease in resource royalties revenue, attributable to an 18% decline in gross realized sand prices to $18.24 per ton for year ended December 31, 2025 as compared to $22.28 per ton for the year ended December 31, 2024. Sand volumes extracted and shipped from our land increased 12%, partially offsetting the unfavorable impacts of the drop in prices. There was a decrease in third-party resource royalties, resulting from one customer becoming a related party in late 2024. In addition, the increase was further offset by a $0.1 million decrease in cryptocurrency mining revenue related to Bitcoin and a $0.1 million decrease in rental and ranching income associated with various surface leases.

Change in Fair Value of Digital Assets

Change in fair value of digital assets decreased by $0.6 million, or 150%. The change in fair value of digital assets resulted in a loss of $0.2 million for the year ended December 31, 2025, as compared to a gain of $0.4 million for the year ended December 31, 2024. The change in fair value was primarily attributable to fluctuations in Bitcoin indexed pricing as reported on Coinbase at 23:59:59 coordinated universal time.

Production and Ad Valorem Taxes

Production and ad valorem tax expenses increased by $1.1 million, or 52%, to $3.2 million for the year ended December 31, 2025, as compared to $2.1 million for the year ended December 31, 2024. Taxes are based, among other factors, on property values driven by prior year commodity prices. Commodity prices decreased for the year ended December 31, 2024, as compared to the year ended December 31, 2023; however, increased production volumes from the Hilcorp Acquisition accounted for $0.8 million of the increase in production and ad valorem taxes during 2025. The remaining $0.3 million increase was attributable primarily to increased drilling and property development during the year ended December 31, 2025.

General and Administrative

General and administrative expenses increased by $1.9 million, or 112%, to $3.6 million for the year ended December 31, 2025, as compared to $1.7 million for the year ended December 31, 2024. These expenses consist of allocations from Blackbeard for corporate support services, including accounting, engineering, human resources, executive management, information technology, field operations support and other administrative functions. Blackbeard allocates these costs on the basis of revenues. Our growing share of Blackbeard’s revenue base, inclusive of the Hilcorp Acquisition, resulted in an additional $1.4 million of allocated general and administrative expenses. The remaining $0.5 million increase was attributable to a higher ratio of Blackbeard’s general and administrative expenses to revenue.

Transaction Costs

Transaction costs were $4.5 million for the year ended December 31, 2025. These costs are legal, tax and accounting advisory fees initially incurred in connection with a previously contemplated initial public offering which we are no longer pursuing. There were no transaction costs for the year ended December 31, 2024.

Other Operating Expenses

Other operating expenses remained relatively consistent for the year ended December 31, 2025 as compared to the year ended December 31, 2024.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expenses increased by $3.2 million, or 30%, to $13.9 million for the year ended December 31, 2025, as compared to $10.7 million for the year ended December 31, 2024. The increase was primarily attributable to a 93% increase in production as a result of the Hilcorp Acquisition and operational growth as described above, for the year ended December 31, 2025, as compared to the year ended December 31, 2024. The increase was offset by a lower depletion rate of $10.78 per boe for the year ended December 31, 2025, as compared to $15.94 per boe for the year ended December 31, 2024, resulting from an increase in our reserves estimates used in the unit-of-production calculation, primarily due to Blackbeard’s continued development.

Interest Expense, Net

Interest expense, net increased by $1.1 million, or 61%, to $2.9 million for the year ended December 31, 2025, as compared to $1.8 million the year ended December 31, 2024 primarily due to the entry into the Comerica Revolving Credit Facility and Comerica Term Loan on May 30, 2025, which resulted in $0.1 million and $0.9 million of interest expense, respectively.

Income Tax Expense

Income tax expense increased by $0.2 million, or 100%, to $0.4 million for the year ended December 31, 2025, as compared to $0.2 million for the year ended December 31, 2024 due to increased total revenues, a percentage of which were subject to the Texas margin tax.

Non-GAAP Financial Measures

We use certain non-GAAP measures to assess the financial performance of our assets. These non-GAAP financial measures are supplemental measures of our performance that we believe help investors understand our operating results. Additionally, these measures are often used by analysts and other interested parties to evaluate companies in our industry. We believe these non-GAAP financial measures, in addition to the corresponding GAAP financial measure, are important supplemental measures that exclude non-cash or other items that may not be indicative of, or are unrelated to, our core operating results and the overall health of our business.

These measures are not prepared in accordance with GAAP and may be different from the non-GAAP measures used by other companies. These non-GAAP measures are provided in addition to, and should not be considered a substitute for, or superior to, any performance measure derived in accordance with GAAP. Further, these measures have limitations as analytical tools and you should not consider such measures either in isolation or as substitutes for analyzing our results as reported under GAAP.

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 shareholders or service indebtedness. We define Adjusted EBITDA as net income before interest; income taxes; depreciation, depletion and amortization; change in fair value of digital assets; non-cash consideration of digital assets and other gain/loss. 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 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 as determined in accordance with GAAP to Adjusted EBITDA and Adjusted EBITDA Margin for the periods indicated.

____________

(1)      Income tax expense reflects impacts of the Texas margin tax.

(2)      Digital assets are recorded as other surface and land resources revenue as non-cash consideration of digital assets.

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 and fund potential acquisitions without access to external sources of financing for such purposes. We define Free Cash Flow as cash flow from operating activities less acquisitions, including deposits and investment in capital expenditures. We define Free Cash Flow Margin 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 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 net cash provided by operating activities as determined in accordance with GAAP to Free Cash Flow and Free Cash Flow Margin for the periods indicated.

PV-10

PV-10 is a non-GAAP financial measure and differs from the standardized measure, which is the most directly comparable GAAP financial measure. We refer to PV-10 as the present value of estimated future cash flows of estimated proved reserves as calculated in our reserve reports using a discount rate of 10%. This amount includes projected revenues and estimated production costs. The amount does not include any future development or abandonment costs because our interests are limited to mineral and royalty interests. Thus, we do not incur capital or abandonment expenditures related to the development of proved reserves.

Unlike PV-10, standardized measure takes into account future income tax expense. Historically, we have not been subject to entity level taxes since Blackbeard is a limited liability company. Neither PV-10 nor standardized measure represents an estimate of the fair market value of the applicable oil and natural gas properties. We believe that the presentation of PV-10 is relevant and useful because it presents the discounted future net cash flows attributable to reserves prior to taking into account future income taxes. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities. Investors should be cautioned that neither PV-10 nor standardized measure represent an estimate of the fair market value of proved reserve. See “Information about US Land Guild — Oil, Natural Gas and NGLs Data — PV-10” for reconciliation of PV-10 to standardized measure, its most directly comparable GAAP financial measure. For more information regarding our presentation of standardized measure, see “Note 12 — Supplemental Oil and Natural Gas Disclosures (Unaudited)” to the combined financial statements included elsewhere in this proxy statement/prospectus.

The following table sets forth estimates of our net proved oil, natural gas and NGLs reserves, PV-10 and standardized measure as of December 31, 2025 based on SEC pricing.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been capital contributions from Blackbeard, cash flows from operating activities and borrowings under the credit facility. Following the completion of the Business Combination, we expect our primary sources of liquidity will be cash flows from operating activities and, if required, proceeds from borrowings under the revolving credit facility. Further, we expect our primary liquidity and capital requirements will be for our operating expenses, the payment of dividends to our shareholders, if any, servicing of our debt, general company needs and investing in our business, including the potential acquisition of additional surface acreage and mineral and royalty interests. Future sources of liquidity may also include issuances of debt or equity securities.

We believe that we will be able to fully fund our ongoing capital expenditures, working capital requirements and other capital needs for the foreseeable short- and long-term future through cash on hand, cash flows from our operating activities, borrowings under the JPM Credit Facility, and access to capital markets. Although we believe that we will be able to fully fund our ongoing capital expenditures, working capital requirements and other capital needs for the foreseeable future through cash on hand, cash flows from our operating activities and access to capital markets, we may choose to use borrowings under our debt instruments to finance our operating and investing activities. See “— Debt Instruments.”

As an owner of surface acreage and mineral and royalty interests, we incur the initial cost to acquire our interests but thereafter do not incur any development or maintenance capital expenditures, which are borne entirely by our operators and customers on our land. As a result, our only capital expenditures are related to other property and equipment, such as the development of digital asset infrastructure. In the future, we may incur capital expenditures to acquire additional surface acreage and mineral and royalty interests. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing and financing activities and our ability to integrate acquisitions. We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. Our ability to generate cash is subject to several factors, some of which are beyond our control, including commodity prices, our operators and customers activities on our land, including the development and production of wells, and general economic, financial, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may raise such capital through borrowings under our debt instruments, asset sales, offerings of equity and debt securities or other means. If we are unable to obtain funds needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us.

As of March 31, 2026, we had $17.1 million of total debt outstanding and $5.1 million of cash and cash equivalents. As of December 31, 2025, we had $17.9 million of total debt outstanding and $1.1 million of cash and cash equivalents.

Cash Flows

The following table summarizes our cash flows for the periods indicated:

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased by $6.0 million, or 54%, to $17.1 million for the three months ended March 31, 2026, as compared to $11.1 million for the three months ended March 31, 2025. Cash flow from operations is primarily driven by the level of our income-generating activities and the timing of cash payments related to our operating assets and liabilities. Net income excluding non-cash activities was $21.0 million for the three months ended March 31, 2026 compared to $14.2 million for the three months ended March 31, 2025, which contributed to a $6.8 million net increase in cash provided by operating activities. This increase was primarily driven by higher income from oil, natural gas, and NGLs resulting from Hilcorp Acquisition and higher production volumes. See “— Results of Operations” above for further discussion of changes in our income and expenses.

Changes in our operating assets and liabilities resulted in a $0.8 million decrease in net cash provided by operating activities. The key drivers include a $1.2 million decrease due to timing differences in net payables and receivables balances offset by a $0.4 million increase due to upfront payments received in 2026 for exclusive surface utilization under lease arrangements.

Net Cash Used in Investing Activities

Net cash used in investing activities increased by $0.6 million to $0.6 million for the three months ended March 31, 2026, as compared to no investing activities for the three months ended March 31, 2025. The increase was driven by $0.5 million as a result of a deposit related to the Ranch Acquisition along with $0.1 million attributable to higher investment in other property and equipment.

Net Cash Used in Financing Activities

Prior to the Business Combination, most of our predecessor’s cash flow was advanced through Blackbeard’s centralized cash management system. Net cash used in financing activities decreased by $0.8 million, or 6%, to $12.5 million for the three months ended March 31, 2026, as compared to $13.3 million for the three months ended March 31, 2025. The decreased was primarily driven by a reduction of net transfers to Blackbeard Holdings of $2.1 million offset by $0.7 million in repayments of Comerica Credit Facilities which was drawn after March 31, 2025 and $0.6 million related to payments of deferred offering costs of a previously contemplated initial public offering which we are no longer pursuing. Transfers of cash to and from Blackbeard Holdings are reflected as a component of net parent investment.

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

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased by $25.6 million, or 80%, to $57.7 million for the year ended December 31, 2025, as compared to $32.1 million for the year ended December 31, 2024. Cash flow from operations is primarily driven by the level of our income-generating activities and the timing of cash payments related to our operating assets and liabilities. Net income excluding non-cash activities was $60.2 million in 2025 compared to $36.5 million in 2024, which contributed to a $23.7 million net increase in cash provided by operating activities. This increase was primarily driven by higher income from oil, natural gas, and NGLs resulting from Hilcorp Acquisition and increased production from new wells placed into service during 2025, as well as increased surface use activities. See “— Results of Operations” above for further discussion of changes in our income and expenses.

Changes in our operating assets and liabilities resulted in a $1.9 million increase in net cash provided by operating activities. The key drivers include an increase of $0.8 million in ad valorem tax payable due to higher 2025 balances, as compared to 2024, from acquisitions of additional NRAs and surface acres and a lower 2024 balance reflecting the lagged impact of 2023 commodity price declines on tax assessments and payment timing. Additionally, $0.7 million of the increase is driven by upfront payments received in 2025 for exclusive surface utilization under lease arrangements. The remaining net $0.4 million increase is due to timing differences in net payables and receivables balances as well as an increase in income tax payable due to higher revenues.

Net Cash Used in Investing Activities

Net cash used in investing activities decreased by $0.1 million to $0.3 million for the year ended December 31, 2025, as compared to $0.4 million for the year ended December 31, 2024. The decrease was driven by $0.1 million attributable to lower investment in other property and equipment.

Net Cash Used in Financing Activities

Prior to the Business Combination, most of our predecessor’s cash flow was advanced through Blackbeard’s centralized cash management system. Net cash used in financing activities increased by $30.2 million, to $59.6 million for the year ended December 31, 2025, as compared to $29.4 million for the year ended December 31, 2024. The increase was primarily attributable to an increase in cash transfers to Blackbeard Holdings of $45.5 million, $2.1 million related to payments of deferred offering costs of a previously contemplated initial public offering which we are no longer pursuing and $0.5 million in payments of debt issuance costs offset by $17.9 million in net cash provided by borrowing and repayments on the Comerica Credit Facilities which was drawn after March 31, 2025.

Debt Instruments

JPM Credit Facility

On June 1, 2026, we entered into the JPM Credit Agreement. The JPM Credit Agreement provides for the JPM Revolving Credit Facility in the maximum aggregate revolving commitment amount of $250.0 million. The JPM Revolving Credit Facility matures on May 30, 2031. The JPM Credit Agreement is secured by our property and equipment and requires us to maintain certain leverage and liquidity ratios. As of July 22, 2026, we had total outstanding borrowings of $98.0 million under the JPM Revolving Credit Facility and had incurred bank fees of $2.9 million.

In connection with Closing, it is expected that, if the required lender consents are obtained, the JPM Credit Facility will be amended (or replaced) to provide that a subsidiary of New PBT will be the new borrower thereunder. However, no guarantee can be made as to whether such consents will be obtained. If such consents are not obtained, the indebtedness outstanding under the JPM Credit Facility is instead expected to be paid off in full at Closing pursuant to one or more payoff letters.

Comerica Credit Facility

On May 30, 2025, we entered into the Comerica Credit Agreement. The Comerica Credit Agreement provided for the Comerica Revolving Credit Facility in the maximum amount of $10.0 million and the Comerica Term Loan in the amount of $20.0 million. The Comerica Revolving Credit Facility was to mature on May 30, 2030. The Comerica Term Loan required quarterly payments with final maturity on May 30, 2030. As of March 31, 2026, the Comerica Term Loan incurred interest at a rate of 6.5%, and there were not outstanding borrowings under the Comerica Revolving Credit Facility. As of December 31, 2025, the Comerica Term Loan incurred interest at a rate of 6.6%, and there were no outstanding borrowings under the Comerica Revolving Credit Facility. The Comerica Credit Agreement was secured by our property and equipment and requires us to maintain certain leverage and debt service coverage ratios.

Using the borrowings under the JPM Credit Agreement and cash on hand, on June 1, 2026, we settled the outstanding debt under the Comerica Credit Agreement and terminated the Comerica Credit Agreement in connection therewith.

Contractual Obligations

As of March 31, 2026, we had total debt outstanding under our Comerica Term Loan of $17.1 million, including $2.8 million classified as current, with interest accruing 6.5% per annum. As of December 31, 2025, we had total debt outstanding under our Comerica Term Loan of $17.9 million, including $2.8 million classified as current, with interest accruing at 6.6% per annum.

Off Balance Sheet Arrangements

We currently have no material off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our predecessor’s audited combined financial statements and unaudited condensed combined financial statements included elsewhere in this proxy statement/prospectus, which have been prepared in accordance with GAAP. The preparation of our predecessor’s audited combined financial statements and unaudited condensed combined financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. We consider our critical accounting estimates those that require subjectivity and that could inherently influence our financial result based on changes in those estimates. See Note 3 — Summary of Significant Accounting Policies to the audited combined financial statements included elsewhere in this proxy statement/prospectus for additional information regarding these accounting policies.

Method of Accounting for Oil and Natural Gas Properties

We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, costs to acquire mineral and royalty interests in oil and natural gas properties are capitalized when incurred.

Costs of proved oil and natural gas properties are depleted on a basin-wide basis utilizing the units-of production method using total proved reserves. Costs of unproved oil and natural gas properties are not subject to depletion. These costs are transferred into costs subject to depletion on an ongoing basis as wells are completed and as proved reserves are established or confirmed.

Impairment of Proved Oil and Natural Gas Interests

The fair value of proved reserves is used for impairment purposes, which is evaluated whenever events or changes in circumstances indicate that the carrying value of the assets might not be recoverable. Fair value of proved reserves is determined primarily by discounted cash flows, supported by available market valuations, if applicable. Significant inputs and assumptions to the valuation of proved oil and natural gas interests include estimates of reserves, future production volumes, future commodity prices and a market-based weighted average cost of capital rate.

Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve estimates and their associated future net cash flows were prepared by CG&A, our independent reserve engineers, as of December 31, 2025 and 2024. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs included in the calculation of future net cash flows include anticipated production of proved reserves and other relevant data. The data for a given property may also change substantially over time as a result of numerous factors, including evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time, and reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future net cash flows and result in impairment of assets that may be material. No impairments were recorded on our proved oil and natural gas properties for the three months ended March 31, 2026 and 2025 and the years ended December 31, 2025 and 2024.

Revenue Recognition

Oil and Natural Gas Royalties

Oil and natural gas royalties are earned on oil and natural gas mineral interests owned by us. Oil and natural gas royalties are recognized when oil and natural gas products are produced or severed from the mineral lease by the operator of the properties and sold to third-party purchasers.

The oil and natural gas royalties we receive are dependent upon market prices for oil and natural gas, and producer specific location and contractual price differences. Oil and natural gas royalty payments are typically received within three months after the month of production.

We accrue oil and natural gas royalties based on an estimate of the production sold to the customer and the price that will be received for the sale of the product. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market. Volume estimates are based upon historical actual data, which is compared to engineering estimates. In these situations, differences are recorded between estimates and the actual amounts received for product sales in the month that revenue is processed after payment is received from the customer. Any identified differences between the revenue estimates and actual revenue received have historically been insignificant.

Recently Issued Accounting Pronouncements

For a summary of recently issued accounting pronouncements, see Note 3 — Summary of Significant Accounting Policies to the audited combined financial statements and unaudited condensed combined financial statements included elsewhere in this proxy statement/prospectus.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risks, including the effects of adverse changes in commodity prices, counterparty and customer credit risks and interest rate risks 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 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 Risks

One of our major market risk exposures is in the pricing applicable to the oil, natural gas and NGLs production from, or serviced on, our surface acreage. The market for the use of our surface acreage and its resources is indirectly exposed to fluctuations in the price of oil, natural gas and NGLs, to the extent such fluctuations impact drilling, completion and production activity levels and thus impact the activity levels of our customers, including our E&P operators, in the E&P and oilfield services industries. The prices that our E&P operators receive for production depend on many factors outside of our or their control. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGLs production has been volatile historically, and we expect this volatility to continue in the future. We are also directly exposed to these risks with respect to revenues we receive from our mineral and royalty interests.

During the past five years, the Henry Hub spot market price for natural gas has ranged from a low of $1.21 per MMbtu in November 2024 to a high of $30.72 per MMbtu in January 2026. The posted price for WTI has ranged from a low of $55.44 per barrel in December 2025 to a high of $123.64 per barrel in March 2022. As of March 31, 2026, the Henry Hub spot market price of natural gas was $2.88 per MMbtu and the posted price for oil was $102.86 per barrel. As of December 31, 2025, the Henry Hub spot market price of natural gas was $4.00 per MMbtu and the posted price for oil was $57.26 per barrel.

A $1.00 per Bbl change in our realized oil price would have resulted in a $0.3 million change in our oil revenues for the three months ended March 31, 2026. A $0.10 per mcf change in our realized natural gas price would have less than a $0.1 million impact to our natural gas revenues for the three months ended March 31, 2026. A $1.00 per Bbl change in NGLs prices would have resulted in a $0.1 million change in our NGLs revenues for the year ended March 31, 2026. Royalties on oil, natural gas and NGL sales contributed 93%, (1)% and 8%, respectively, of our oil and natural gas revenues for the three months ended March 31, 2026.

A $1.00 per Bbl change in our realized oil price would have resulted in a $0.7 million change in our oil revenues for the year ended December 31, 2025. A $0.10 per mcf change in our realized natural gas price would have resulted in a $0.2 million change in our natural gas revenues for the year ended December 31, 2025. A $1.00 per Bbl change in NGLs prices would have resulted in a $0.2 million change in our NGLs revenues for the year ended December 31, 2025. Royalties on oil, natural gas and NGL sales contributed 91%, 2% and 7%, respectively, of our oil and natural gas revenues for the year ended December 31, 2025.

Counterparty and Customer Credit Risks

We are subject to risks of loss resulting from nonpayment or nonperformance by our counterparties and customers of their contractual obligations. Our principal exposure to credit risk is through receivables generated by the activities of customers on our land and the production activities of our E&P operators. The inability or failure of our significant customers, including our E&P operators, to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We examine the creditworthiness of any counterparty and customer and monitor our exposure to such counterparties and customers through credit analysis and monitoring procedures, including reviewing credit ratings, financial statements and payment history. For the three months ended March 31, 2026 and 2025, Blackbeard accounted for approximately 91% and 92% of our total revenue, respectively. For the three months ended March 31, 2026 and 2025, there were no other customers that represented 10% or more of our total revenue. For the years ended December 31, 2025 and 2024, Blackbeard accounted for approximately 91% and 87%, respectively, of our total revenue. For the years ended December 31, 2025 and 2024, there were no other customers that represented 10% or more of our total revenue. However, we believe that the credit risk associated with our counterparties and customers is acceptable.

Interest Rate Risks

Our ability to borrow and the rates offered by lenders can be adversely affected by deterioration in the credit markets and/or deterioration of our credit profile rating.

As of March 31, 2026, we had $17.1 million of outstanding borrowings under our Comerica Term Loan. The interest rate on the borrowings outstanding as of March 31, 2026 was 6.5%. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the interest rate would be $0.2 million per year.

As of December 31, 2025, we had $17.9 million of outstanding borrowings under our Comerica Term Loan. The interest rate on the borrowings outstanding as of December 31, 2025 was 6.6%. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the interest rate would be $0.2 million per year.

Additionally, Blackbeard’s debt has been partially collateralized by our assets and as a result, interest expense has been allocated to us based on the relative value of our oil and natural gas interests utilized to fund its business operations and the prevailing interest rates. For the three months ended March 31, 2026, the average interest rate on the borrowings outstanding under Blackbeard Holdings’ debt that was collateralized by our assets was 7.3%. Assuming no additional borrowings from Blackbeard, the impact on interest expense of a 1.0% increase or decrease in the allocated interest rate would be $0.3 million per year. For the year ended December 31, 2025, the average interest rate on the borrowings outstanding under Blackbeard Holdings’ debt that was collateralized by our assets was 7.8%. Assuming no additional borrowings from Blackbeard, the impact on interest expense of a 1.0% increase or decrease in the allocated interest rate would be $0.3 million per year.

Market Risks

Demand for the use of land and resources is largely dependent upon the level of activity in the energy industry in the Permian Basin, specifically in the CBP. These activity levels are influenced by numerous factors over which we have no control, including: the supply of and demand for oil, natural gas and NGLs; the level of prices and expectations about future prices of oil, natural gas and NGLs; the cost of exploring for, developing, producing and delivering oil, natural gas and NGLs; the expected rates of declining current production; the discovery rates of new reserves; available pipeline, rail and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political activity domestically and in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; technological advancements in the production of alternative energy; the ability of energy companies to raise equity capital and debt financing; and merger and divestiture activity among energy companies.

The level of U.S. energy production, including oil, natural gas and NGLs development activity, is volatile. Any prolonged and substantial reduction in oil, natural gas and NGLs prices would likely affect development and production activity levels and therefore affect demand for oil, natural gas and NGLs and the use of our land and its resources and amounts we receive for production on our mineral and royalty interests. A material decline in energy, including oil, natural gas and NGLs prices, or Permian Basin, specifically CBP, activity levels could have an adverse effect on our results of operations, cash flows and financial position.

INFORMATION ABOUT THE TRUST

The Trust is an express trust created under the laws of the State of Texas by the Permian Basin Royalty Trust Indenture entered into on November 3, 1980, between Southland Royalty Company and The First National Bank of Fort Worth, as Trustee. Argent Trust Company, a Tennessee chartered trust company, is the current Trustee of the Trust. The net overriding royalties conveyed to the Trust include (1) a 75% net overriding royalty in Southland Royalty Company’s fee mineral interest in the Waddell Ranch in Crane County, Texas and (2) a 95% net overriding royalty carved out of Southland Royalty Company’s major producing royalty properties in Texas. The net overriding royalty for the Texas Royalty properties is subject to the provisions of the lease agreements under which such royalties were created.

The information contained in the Trust’s most recent Annual Report on Form 10-K (as amended) is incorporated herein by reference. See “Where You Can Find More Information” in this proxy statement/prospectus. Notwithstanding the incorporation by reference of Trust filings and business and financial information hereby, neither the Trust nor the Trustee are making a solicitation in this proxy statement/prospectus, nor are they offering any securities in this proxy statement/prospectus.

THE BUSINESS COMBINATION

The Parties to the Business Combination

PBT Land and Minerals, Inc.

New PBT is a wholly owned subsidiary of SoftVest, L.P., a Unitholder that beneficially owns in the aggregate approximately 13.3% of the outstanding Trust Units. SoftVest, L.P. created New PBT to facilitate the Business Combination, the Rights Offering and the Blackbeard and Greybeard Subscription; SoftVest, L.P. will transfer full ownership of New PBT to the Trust before the Business Combination is completed. New PBT has not engaged in any other business activities and has not incurred any liabilities or obligations, except for activities, liabilities or obligations incidental to its formation or in connection with the Business Combination, the Combination Agreement, the Rights Offering, the Backstop Commitment and the Blackbeard and Greybeard Subscription.

New PBT was incorporated in the State of Texas on June 18, 2026. New PBT’s principal executive offices are located at 400 Pine Street, Suite 1010, Abilene, TX 79601 (telephone number (325) 677-6177).

PBT Sub, Inc.

New PBT Sub is a wholly owned subsidiary of New PBT. New PBT Sub was formed solely for the purpose of completing the Business Combination. New PBT Sub has not engaged in any other business activities and has not incurred any liabilities or obligations, except for activities, liabilities or obligations incidental to its formation or in connection with the Business Combination or the Combination Agreement.

New PBT Sub was incorporated in the State of Texas on June 25, 2026. New PBT Sub’s principal executive offices are located at 400 Pine Street, Suite 1010, Abilene, TX 79601 (telephone number (325) 677-6177).