~~UNITED~~United ~~STATES~~States

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2024~~2025

ORor

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-36386

Gulf Coast Ultra Deep Royalty Trust

(Exact name of registrant as specified in its charter)

Delaware		46-6448579
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
The Bank of New York Mellon Trust Company, N.A., as trustee 601 Travis Street, 16th Floor Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

The Bank of New York Mellon Trust Company, N.A., as trustee 601 Travis Street, 16th Floor
Houston, TX		77002
(Address of principal executive offices)		(Zip Code)

(512) 236-6555

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Royalty Trust Units

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☐ Yes ☒ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☐ Yes ☐ No

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

	Large accelerated filer ☐	Accelerated filer ☐
	Non-accelerated filer ☒	Smaller reporting company ☒
		Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No

The aggregate market value of Royalty Trust units held by non-affiliates of the registrant was $25,~~182~~204,~~523~~478 on June 2830, ~~2024~~2025 (the last ~~day~~business day of the Royalty Trust’s most recently completed second quarter).

On March 2825, ~~2025~~2026, there were 230,172,696 Royalty Trust units outstanding representing beneficial interests in the registrant.

DOCUMENTS INCORPORATED BY REFERENCE: None

NONE

Gulf Coast Ultra Deep Royalty Trust

Annual Report on Form 10-K for the fiscal year ended December 31, 2025

the fiscal year ended December 31, 2024

TABLE OF CONTENTS

	Page	~~Page~~
Forward-Looking Statements	1	1
Glossary	2	2
Part I
Items 1. and 2. Business and Properties	3	3
Item 1A. Risk Factors	19	18
Item 1B. Unresolved Staff Comments	29	29
Item 1C. Cybersecurity	29	29
Item 3. Legal Proceedings	30	30
Item 4. Mine Safety Disclosures	30	30
Part II
Item 5. Market for Registrant’s Royalty Trust Units, Related Royalty Trust Unitholder Matters and Issuer Purchases of Royalty Trust Units	31	31
Item 6. [Reserved]	31	31
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	32	32
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	35	35
Item 8. Financial Statements and Supplementary Data	36	36
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	45	48
Item 9A. Controls and Procedures	45	48
Item 9B. Other Information	45	48
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	45	48
Part III
Item 10. Directors, Executive Officers and Corporate Governance	46	49
Item 11. Executive Compensation	46	49
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Royalty Trust Unitholder Matters	47	50
Item 13. Certain Relationships and Related Transactions, and Director Independence	48	51
Item 14. Principal Accountant Fees and Services	49	52
Part IV
Item 15. Exhibits and Financial Statement Schedules	50	53
Item 16. Form 10-K Summary	50	53
Signatures	51	54

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (Form 10-K) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). Forward-looking statements are all statements other than statements of historical facts, such as any statements regarding the future financial condition of ~~the~~ Gulf ~~Coast~~ Coast Ultra Deep Royalty Trust (Royalty Trust) or the trading market for the Royalty Trust units, all statements regarding the plans of Highlander Oil & Gas Assets LLC (HOGA) for the subject interests, ~~including any plans to drill a new well on~~ the ~~onshore Highlander subject interest, the~~ potential results of any drilling on the subject interests, anticipated interests of HOGA and the Royalty Trust in any of the subject interests, HOGA’s geologic models and the nature of the geologic trend onshore in South Louisiana discussed in this Form 10-K, the amount and date of quarterly distributions to Royalty Trust unitholders, and all statements regarding any belief or understanding of the nature or potential of the subject interests. The words “anticipates,” “may,” “can,” “plans,” “believes,” “estimates,” “expects,” “projects,” “intends,” “likely,” “will,” “should,” “to be,” “potential,” and any similar expressions and/or statements that are not historical facts are intended to identify those assertions as forward-looking statements.

Forward-looking statements are not guarantees or assurances of future performance and actual results may differ materially from those anticipated, projected or assumed in the forward-looking statements. Important factors that may cause actual results to differ materially from those anticipated by the forward-looking statements include, but are not limited to, the future plans of HOGA for its remaining oil and gas properties; the risk that the subject interests will not produce additional hydrocarbons; general economic and business conditions; variations in the market demand for, and prices of, oil and natural gas; drilling results; changes in oil and natural gas reserve expectations; the potential adoption of new governmental regulations; decisions by HOGA not to develop and/or transfer the subject interests; any inability of HOGA to develop the subject interests; damages to facilities resulting from natural disasters or accidents; fluctuations in the market price, volume and frequency of the trading market for the Royalty Trust units; the amount of cash received or expected to be received by the Trustee from the underlying subject interests on or prior to a record date for a quarterly cash distributions; and other factors described in Part I, Item 1A. “Risk Factors” in this Form 10-K, as updated by the Royalty Trust’s subsequent filings with the United States (U.S.) Securities and Exchange Commission (SEC). Any differences in actual cash receipts by the Royalty Trust could affect the amount of quarterly cash distributions.

Investors are cautioned that current production rates may not be indicative of future production rates or of the amounts of hydrocarbons that a well may produce, and that many of the assumptions upon which forward-looking statements are based are likely to change after such forward-looking statements are made, which the Royalty Trust cannot control. The Royalty Trust cautions investors that it does not intend to update its forward-looking statements, notwithstanding any changes in assumptions, changes in business plans, actual experience, or other changes, and the Royalty Trust undertakes no obligation to update any forward-looking statements except as required by law.

GLOSSARY

In this report the following terms have the meanings specified below.

British thermal unit or Btu. The amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Gross acre. An acre in which HOGA owns a working interest.

MMBtu. Million British thermal units

MMcf. Million cubic feet of natural gas.

Net acre. Deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions of whole numbers.

Overriding royalty interest. A revenue interest, created out of a working interest, that entitles its owner to a share of revenues, free of any operating or production costs. An overriding royalty is often retained by a lessee assigning an oil and gas lease.

Productive well. An exploratory, development, or extension well that is not a dry well. Productive wells include producing wells and wells mechanically capable of production.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved reserves. 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—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

For additional information regarding the definitions contained in this Glossary, and for other oil and gas definitions, please see Rule 4-10 of Regulation S-X.

PART I

Items 1. and 2. Business and Properties

The Royalty Trust’s periodic and current reports filed or furnished with or to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act including its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports are available, free of charge, through the Royalty Trust’s website, http://gultu.q4web.com/home/default.aspx. These reports and amendments are available through the Royalty Trust’s website as soon as reasonably practicable after the Royalty Trust electronically files or furnishes such materials with or to the SEC.

References to “Notes” refer to the Notes to the Financial Statements included herein (refer to Part II, Item 8. “Financial Statements and Supplementary Data” of this Form 10-K). A glossary of definitions for some of the oil and gas industry terms used in this Form 10-K is provided on page 2.

THE ROYALTY TRUST

The Royalty Trust. On June 3, 2013, Freeport-McMoRan Inc. (FCX) and McMoRan Exploration Co. (MMR) completed the transactions contemplated by the Agreement and Plan of Merger, dated as of December 5, 2012 (the merger agreement), by and among MMR, FCX, and INAVN Corp., a Delaware corporation and indirect wholly owned subsidiary of FCX (Merger Sub). Pursuant to the merger agreement, Merger Sub merged with and into MMR, with MMR surviving the merger as an indirect wholly owned subsidiary of FCX (the merger).

FCX’s oil and gas assets are held through its wholly owned subsidiary, FCX Oil & Gas LLC (FM O&G). As a result of the merger, MMR and McMoRan are both indirect wholly owned subsidiaries of FM O&G.

The Royalty Trust is a statutory trust created as contemplated by the merger agreement by FCX under the Delaware Statutory Trust Act pursuant to a trust agreement entered into on December 18, 2012 (inception), by and among FCX, as depositor, Wilmington Trust, National Association, as Delaware trustee, and certain officers of FCX, as regular trustees. On May 29, 2013, Wilmington Trust, National Association, was replaced by BNY Trust of Delaware, as Delaware trustee (the Delaware Trustee), through an action of the depositor. Effective June 3, 2013, the regular trustees were replaced by The Bank of New York Mellon Trust Company, N.A., a national banking association, as trustee (the Trustee).

The Royalty Trust was created to hold a 5% gross overriding royalty interest (collectively, the overriding royalty interests) in future production from each of McMoRan’s Inboard Lower Tertiary/Cretaceous exploration prospects located in the shallow waters of the Gulf of Mexico and onshore in South Louisiana that existed as of December 5, 2012, the date of the merger agreement (collectively, the subject interests). The subject interests were “carved out” of the mineral interests acquired by FCX pursuant to the merger and were not considered part of FCX’s purchase consideration of MMR.

The overriding royalty interests are passive in nature, and neither the Trustee nor the Royalty Trust unitholders has any control over or responsibility for any costs relating to the drilling, development or operation of the subject interests. The Royalty Trust is not permitted to acquire other oil and gas properties or mineral interests or otherwise engage in activities beyond those necessary for the conservation and protection of the overriding royalty interests.

On February 5, 2019, McMoRan completed the sale of all of its rights, title and interest in and to the onshore Highlander subject interest pursuant to a purchase and sale agreement with HOGA (the Highlander Sale). The onshore Highlander subject interest was sold subject to the overriding royalty interest in future production held by the Royalty Trust. As a result of the Highlander Sale, HOGA has a 72% working interest and an approximate 48% net revenue interest in the onshore Highlander subject interest. The Royalty Trust continues to hold a 3.6% overriding royalty interest in the onshore Highlander subject interest. HOGA is the operator of the Highlander subject interest. The onshore Highlander subject interest is the only subject interest in which HOGA has an interest, as McMoRan previously had relinquished, allowed to expire or sold all of the other subject interests.

Effective December 31, 2024 (the Effective Date), FCX, McMoRan and HOGA entered into an Assignment and Assumption Agreement and Bill of Sale, pursuant to which (1) FCX assigned to HOGA, and HOGA assumed, all of the financial and other obligations of FCX as depositor under the Royalty Trust Agreement (defined below), and (2) McMoRan assigned to HOGA, and HOGA assumed, all of the rights and obligations of McMoRan as grantor under the Royalty Trust Agreement and the master conveyance (defined below) that were not previously assumed by HOGA at the time of the Highlander Sale (collectively, the Assignment). Notwithstanding the Assignment, FCX remains obligated to perform the financial and other obligations owed to the Royalty Trust by the depositor under the Royalty Trust Agreement, if HOGA were to be unable to fully perform such obligations in the future. In this Form 10-K, the “Depositor” refers to FCX, for all periods ending prior to the Effective Date, and to HOGA, for all periods beginning on and after the Effective Date; and the “Grantor” refers to McMoRan, for all periods ending prior to the Effective Date, and to HOGA, for all periods beginning on and after the Effective Date.

At December 31, 2024, the Royalty Trust had 230,172,696 Royalty Trust units outstanding. All information in this Form 10-K regarding the subject interests has been furnished to the Trustee by HOGA. The reserve estimates have been prepared by independent petroleum engineers as described herein, based on information furnished by HOGA.3

At December 31, 2025, the Royalty Trust had 230,172,696 Royalty Trust units outstanding. All information in this Form 10-K regarding the subject interests has been furnished to the Trustee by HOGA. The reserve estimates have been prepared by independent petroleum engineers as described herein, based on information furnished by HOGA.

Status of the Onshore Highlander Subject Interest. On January 19, 2023, the sole well producing from the onshore Highlander subject interest experienced an operational issue, resulting in substantial amounts of water entering the well, which caused a shut in of the well before production resumed at significantly reduced levels. Following an evaluation by HOGA’s field operations team, HOGA determined that it would be necessary to commence operations to control the water production, in expectation of eventually initiating “kill” operations on the well. HOGA informed the Trustee that the well was shut in effective March 31, 2023 and production from the well has ceased. After that time the well flowed intermittently but not on a continuous basis. In October 2023, HOGA informed the Trustee that due to the underground flow of fluids into the wellbore, the well could not be salvaged and would be required to be plugged and abandoned. Operations to permanently plug and abandon the well commenced in early March 2024.

The onshore Highlander subject interest is the only subject interest that has established commercial production. Abandoning the well eliminated any production from the onshore Highlander subject interest, which also eliminated any proceeds to which the Royalty Trust would be entitled pursuant to its overriding royalty interests. Unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities, the Royalty Trust does not expect to receive any income attributable to its overriding royalty interests and accordingly, does not expect to have any cash available to distribute to Royalty Trust unitholders in future periods. HOGA ~~has~~previously informed the Trustee that a new well on the onshore Highlander subject interest was spudded on January 30, 2025 and recently reported that the well had reached total depth of 30,862 feet on February 17, 2026; however, the future production status of this well remains unknown. Neither the Trustee nor the Royalty Trust unitholders has any right to control or influence operations of the subject interest.

The Royalty Trust Agreement. In connection with the merger, on June 3, 2013, (1) FCX, as depositor, McMoRan, as grantor, the Trustee and the Delaware Trustee entered into the amended and restated royalty trust agreement to govern the Royalty Trust and the respective rights and obligations of FCX, the Trustee, the Delaware Trustee, and the Royalty Trust unitholders with respect to the Royalty Trust (the Royalty Trust Agreement); and (2) McMoRan, as grantor, and the Royalty Trust, as grantee, entered into the master conveyance of overriding royalty interest (the master conveyance) pursuant to which McMoRan conveyed to the Royalty Trust the overriding royalty interests in future production from the subject interests.

Duties and Limited Powers of the Trustee. The duties of the Trustee are specified in the Royalty Trust Agreement and by the laws of the State of Delaware. The Trustee’s principal duties consist of:

	●	collecting income attributable to the overriding royalty interests;

	●	paying expenses, charges and obligations of the Royalty Trust from the Royalty Trust’s income and assets;

	●	distributing distributable income to the Royalty Trust unitholders; and

	●	prosecuting, defending or settling any claim of or against the Trustee, the Royalty Trust or the overriding royalty interests, including the authority to dispose of or relinquish title to any of the overriding royalty interests that are the subject of a dispute upon the receipt of sufficient evidence regarding the facts of such dispute.

The Trustee has no authority to incur any contractual liabilities on behalf of the Royalty Trust that are not limited solely to claims against the assets of the Royalty Trust.

If a liability is contingent or uncertain in amount or not yet currently due and payable, the Trustee may create a cash reserve to pay for the liability. If the Trustee determines that the cash on hand and the cash to be received are insufficient to cover expenses or liabilities of the Royalty Trust, the Trustee may borrow funds required to pay those expenses or liabilities. The Trustee may borrow the funds from any person, including the Depositor or itself. The Trustee may also encumber the assets of the Royalty Trust (i.e., the overriding royalty interests) to secure payment of the indebtedness. If the Trustee, on behalf of the Royalty Trust, borrows funds, whether from the Depositor or from any other source, to cover expenses or liabilities, the Royalty Trust unitholders will not receive distributions until the borrowed funds are repaid. Since the Royalty Trust does not conduct an active business and the Trustee has little power to incur obligations, it is expected that the Royalty Trust will only incur liabilities for routine administrative expenses, such as the Trustee’s fees and accounting, engineering, legal, tax advisory and other professional fees.

The only assets of the Royalty Trust are the overriding royalty interests and the only investment activity the Trustee may engage in is the investment of cash on hand. Other than (a) its formation, (b) its receipt of contributions and loans from the Depositor for administrative and other expenses as provided for in the Royalty Trust Agreement, (c) its payment of such administrative and other expenses, (d) its repayment of loans from the Depositor, (e) its receipt of the conveyance of the overriding royalty interests from the Grantor pursuant to the master conveyance, (f) its receipt of royalties from McMoRan or HOGA, and (g) its cash distributions to Royalty Trust unitholders, if any, the Royalty Trust has not conducted any activities. The Trustee has no involvement with, control over, or responsibility for, any aspect of any operations on or relating to the subject interests.

The Trustee has the right to require any Royalty Trust unitholder to dispose of his Royalty Trust units if an administrative or judicial proceeding seeks to cancel or forfeit any of the property in which the Royalty Trust holds an interest because of the nationality or any other status of a Royalty Trust unitholder. If a Royalty Trust unitholder fails to dispose of his Royalty Trust units, HOGA is obligated to purchase them (up to a cap of $1 million) at a price determined in accordance with a formula set forth in the Royalty Trust Agreement.

The Trustee is authorized to agree to modifications of the terms of the conveyances of the overriding royalty interests or to settle disputes involving such conveyances, so long as such modifications or settlements do not alter the nature of the overriding royalty interests as rights to receive a share of the proceeds from the underlying properties free of any obligation for drilling, development or operating expenses or rights that do not possess any operating rights or obligations.

Pursuant to the Royalty Trust Agreement, the Depositor has agreed to pay annual trust expenses up to $350,000, with no right of repayment or interest due, to the extent the Royalty Trust lacks sufficient funds to pay administrative expenses. OnPursuant ~~February~~to 1this provision, ~~2024~~HOGA contributed $200,750 ~~pursuant~~on toApril ~~this~~4, ~~provision~~2025 and $149, ~~FCX~~250 ~~contributed~~on ~~approximately~~May 16, 2025, together representing the maximum contribution of $~~166~~350,000 for the payment of trust expenses incurred during the year ended December 31, ~~2023~~2025. On February 1, ~~and~~2024, FCX contributed the maximum of $350,000 for the payment of trust expenses incurred during the year ended December 31, 2024. In addition to such annual contributions, the Depositor has agreed to lend money, on an unsecured, interest-free basis, to the Royalty Trust to fund the Royalty Trust’s ordinary administrative expenses as set forth in the Royalty Trust Agreement. All funds the Trustee borrows to cover expenses or liabilities, whether from the Depositor or from any other source, must be repaid before the Royalty Trust unitholders will receive any distributions. ~~FCX~~HOGA loaned the Royalty Trust $~~200~~216,~~000~~489 during the year ended December 31, ~~2024~~2025. NoFCX ~~loans~~loaned orthe ~~repayments~~Royalty ~~were~~Trust ~~made~~$200,000 during the year ended December 31, ~~2023~~2024. Pursuant to the Assignment, as of December 31, 2024, FCX assigned to HOGA the promissory note relating to the outstanding loan to the Royalty Trust. As of December 31, 2025, the outstanding note payable to HOGA was $416,489. To the extent annual trust expenses exceed $350,000, the Royalty Trust may be required to borrow funds from HOGA in the future.

Pursuant to the Royalty Trust Agreement, the Depositor also agreed to provide and maintain a $1.0 million stand-by reserve account or an equivalent letter of credit for the benefit of the Royalty Trust to enable the Trustee to draw on such reserve account or letter of credit to pay obligations of the Royalty Trust if its funds are inadequate to pay its obligations at any time. Currently, with the consent of the Trustee, the Depositor may reduce the reserve account or substitute a letter of credit with a different face amount for the original letter of credit or any substitute letter of credit. In connection with this arrangement, FCX provided $1.0 million in the form of a reserve fund cash account to the Royalty Trust. As of December 31, ~~2024~~2025, the Royalty Trust had used $151,632 from the reserve account, and the Depositor had not requested a reduction of such reserve account. Effective December 31, 2024, pursuant to the Assignment, FCX assigned its right, title and interest in the stand-by reserve account to HOGA, and HOGA assumed from FCX the responsibility to maintain the stand-by reserve account.

Fiduciary Responsibility and Liability of the Trustee. The duties and liabilities of the Trustee are set forth in the Royalty Trust Agreement and the laws of the State of Delaware. The Trustee may not make business decisions affecting the assets of the Royalty Trust. Therefore, substantially all of the Trustee’s functions under the Royalty Trust Agreement are expected to be ministerial in nature. See the description in the section above entitled “Duties and Limited Powers of the Trustee.” The Royalty Trust Agreement, however, provides that the Trustee may:

● charge for its services as trustee;

● retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the Trustee to the extent permitted by law);

●Fiduciary Responsibility ~~lend~~and ~~funds~~Liability atof ~~commercial~~the ~~rates~~Trustee. toThe duties and liabilities of the ~~Royalty~~Trustee ~~Trust~~are toset ~~pay~~forth in the Royalty Trust’s ~~expenses~~Agreement and ~~(however,~~the laws of the State of Delaware. The Trustee ~~does~~may not ~~intend~~make tobusiness ~~lend~~decisions ~~funds~~affecting tothe assets of the Royalty Trust);. ~~and~~Therefore, substantially ●all ~~seek~~of ~~reimbursement~~the ~~from~~Trustee’s functions under the Royalty Trust ~~for~~Agreement ~~its~~are ~~out-~~expected to be ministerial in nature. See the description in the section above entitled “Duties and Limited Powers of~~-pocket~~ ~~expenses~~the Trustee.” The Royalty Trust Agreement, however, provides that the Trustee may:

	●	charge for its services as trustee;

	●	retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the Trustee to the extent permitted by law);

	●	lend funds at commercial rates to the Royalty Trust to pay the Royalty Trust’s expenses (however, the Trustee does not intend to lend funds to the Royalty Trust); and

	●	seek reimbursement from the Royalty Trust for its out-of-pocket expenses.

In performing its duties to Royalty Trust unitholders, the Trustee may act in its discretion and is liable to the Royalty Trust unitholders only for willful misconduct, bad faith or gross negligence. The Trustee is not liable for any act or omission of its agents or employees unless the Trustee acted with willful misconduct, bad faith or gross negligence in its selection and retention. The Trustee will be indemnified individually or as trustee out of the Royalty Trust’s assets for any liability or cost that it incurs in the administration of the Royalty Trust, except in cases of willful misconduct, bad faith or gross negligence. The Trustee has a lien on the assets of the Royalty Trust as security for this indemnification and its compensation earned as trustee. The Royalty Trust unitholders are not liable to the Trustee for any indemnification. The Trustee ensures that all contractual liabilities of the Royalty Trust are limited to the assets of the Royalty Trust.

Protection of Trustee. Pursuant to the Royalty Trust Agreement, the Trustee may request certification of any fact, circumstance, computation or other matter relevant to the Royalty Trust or the Trustee’s performance of its duties, and will be fully protected in relying on any such certification or other statement or advice from HOGA or any officer or other employee of HOGA. Any person having any claim against the Trustee by reason of the transactions contemplated by the Royalty Trust Agreement or any of the related documents or agreements will look only to the Royalty Trust’s property for payment or satisfaction thereof.

Amendment of Trust Agreement. Amendments to the Royalty Trust Agreement generally require the affirmative vote of holders of a majority of Royalty Trust units constituting a quorum, although less than a majority of the Royalty Trust units then outstanding (including any Royalty Trust units held by FCX and HOGA, other than with respect to matters where a conflict of interest between FCX or HOGA and unaffiliated Royalty Trust unitholders is present). However, any amendment that would permit holders of fewer than 66⅔% of the outstanding Royalty Trust units to (i) approve a sale of all or substantially all of the overriding royalty interests or (ii) terminate the Royalty Trust requires the affirmative vote of holders of 66⅔% or more of the outstanding Royalty Trust units held by persons other than FCX or HOGA or their respective affiliates.

HOGA and the Trustee are permitted to supplement or amend the Royalty Trust Agreement, without the approval of the Royalty Trust unitholders, in order to cure any ambiguity, to correct or supplement any provision which may be defective or inconsistent with any other provision thereof, or to change the name of the Royalty Trust, as long as such supplement or amendment does not adversely affect the interests of the Royalty Trust unitholders. However, no amendment may:

	●	alter the purposes of the Royalty Trust or permit the Trustee to engage in any business or investment activities other than as specified in the Royalty Trust Agreement;

	●	alter the rights of the Royalty Trust unitholders as among themselves;

	●	permit the Trustee to distribute the overriding royalty interests in kind; or

	●	adversely affect the rights and duties of the Trustee unless such amendment is approved by the Trustee.

Compensation of the Trustee. The Trustee receives $200,000 in annual compensation. Additionally, the Trustee receives reimbursement for its reasonable out-of-pocket expenses incurred in connection with the administration of the Royalty Trust. In the event of litigation involving the Royalty Trust, audits or inspection of the records of the Royalty Trust pertaining to the transactions affecting the Royalty Trust or any other unusual or extraordinary services rendered in connection with the administration of the Royalty Trust, the Trustee would be entitled to receive additional reasonable compensation for the services rendered, including the payment of the Trustee’s standard rates for all time spent by personnel of the Trustee on such matters. The Trustee’s compensation is paid out of the Royalty Trust’s assets. The Trustee has a lien on the Royalty Trust’s assets to secure payment of its compensation and any indemnification expenses and other amounts to which it is entitled under the Royalty Trust Agreement.

Approval of Matters by Royalty Trust Unitholders. The Trustee or Royalty Trust unitholders owning at least 15% of the outstanding Royalty Trust units are permitted to call meetings of Royalty Trust unitholders. Meetings must be held in New York, New York. Written notice setting forth the time and place of the meeting and the matters proposed to be acted upon must be given to all Royalty Trust unitholders of record as of a record date set by the Trustee at least 20 days but not more than 60 days before the meeting. The presence in person or by proxy of Royalty Trust unitholders representing a majority of Royalty Trust units outstanding will constitute a quorum. Subject to the provisions of the Royalty Trust Agreement regarding voting in the case of a material conflict of interest between FCX or HOGA or their respective affiliates, and Royalty Trust unitholders other than FCX or HOGA or their respective affiliates, each Royalty Trust unitholder will be entitled to one vote for each Royalty Trust unit owned.

Unless otherwise required by the Royalty Trust Agreement, any matter (including unit splits or reverse splits) may be approved by the affirmative vote of holders of a majority of Royalty Trust units constituting a quorum, although less than a majority of the Royalty Trust units then outstanding (including any Royalty Trust units held by FCX and HOGA, other than with respect to matters where a conflict of interest between FCX or HOGA and unaffiliated Royalty Trust unitholders is present). The affirmative vote of the holders of 66⅔% of the outstanding Royalty Trust units will be required to (i) approve a sale of all or substantially all of the overriding royalty interests, (ii) terminate the Royalty Trust or (iii) amend the Royalty Trust Agreement to permit the holders of fewer than 66⅔% of the outstanding Royalty Trust units to approve a sale of all or substantially all of the overriding royalty interests, or to terminate the Royalty Trust.

The Trustee may be removed, with or without cause, by the affirmative vote of holders of a majority of the outstanding Royalty Trust units.

Any action required or permitted to be authorized or taken at any meeting of Royalty Trust unitholders may be taken without a meeting, without prior notice and without a vote if a consent in writing setting forth the authorization or action taken is signed by Royalty Trust unitholders holding Royalty Trust units representing at least the minimum number of votes that would be necessary to authorize or take such action at a meeting.

If a meeting of Royalty Trust unitholders is called for any purpose or a written consent is executed at the request of any Royalty Trust unitholder while the Royalty Trust is subject to the requirements of Section 12 of the Exchange Act, the Royalty Trust unitholder requesting the meeting or soliciting the written consent will be required to prepare and file a proxy or information statement with the SEC regarding such meeting or written consent at its expense. The Royalty Trust unitholder requesting the meeting or written consent will bear the expense of distributing the notice of meeting and the proxy or information statement. The Trustee will be required only to provide a list of Royalty Trust unitholders to the extent required by law.

Duration of the Royalty Trust. The Royalty Trust will dissolve on the earliest to occur of (i) June 3, 2033, (ii) the sale of all of the overriding royalty interests, (iii) the election by the Trustee following its resignation for cause (as more fully described in the Royalty Trust Agreement), (iv) a vote of the holders of 66⅔% or more of the outstanding Royalty Trust units held by persons other than FCX, any of its affiliates, or HOGA at a duly called meeting of the Royalty Trust unitholders at which a quorum is present, or (v) the exercise by HOGA of the right to call all of the Royalty Trust units as described in the next paragraph. The overriding royalty interests terminate upon the termination of the Royalty Trust, other than in certain limited circumstances where the Royalty Trust has been permitted to transfer the overriding royalty interests to a third party pursuant to the terms of the Royalty Trust Agreement (in which case the overriding royalty interests may extend through June 3, 2033).

HOGA Call Rights. HOGA has a call right with respect to the outstanding Royalty Trust units at $10 per Royalty Trust unit. In addition, if the Royalty Trust units are then listed for trading or admitted for quotation on a national securities exchange or any quotation system and the volume weighted average price per Royalty Trust unit is equal to $0.25 or less for the immediately preceding consecutive nine-month period, HOGA may purchase all, but not less than all, of the outstanding Royalty Trust units at a price of $0.25 per Royalty Trust unit so long as HOGA tenders payment within 30 days following the end of such nine-month period.

Resignation of Trustee. The Trustee may resign, with or without cause, at any time by providing at least 60 days’ notice to HOGA and the Royalty Trust unitholders of record, but the resignation of the Trustee will not be effective until a successor trustee has accepted its appointment. The Trustee may nominate a successor trustee, which may be approved and appointed by HOGA without a meeting or vote of the Royalty Trust unitholders. If the Trustee has given notice of resignation for cause and a successor trustee has not accepted its appointment as successor trustee during the 90-day period following HOGA’s receipt of such notice, the annual fee payable to the Trustee will be increased by 5% as of the end of such 90-day period, and will be further increased by 5% for each month or portion of a month thereafter (up to a maximum of two times the fee payable at the time the notice of resignation was received by HOGA) until a successor trustee has accepted its appointment.

If at any time (a) the Trustee has not received compensation for its services or expenses or other amounts owed to the Trustee pursuant to the Royalty Trust Agreement, (b) HOGA has failed to fully fund a loan to the Royalty Trust in a reasonably timely manner after the Trustee has requested the loan pursuant to the Royalty Trust Agreement or has failed to contribute funds to the Royalty Trust as required by the Royalty Trust Agreement, (c) the Royalty Trust’s obligations exceed the amount of funds of the Royalty Trust available to pay such obligations, and (d) a stand-by reserve account or letter of credit is available to the Trustee as described in the Royalty Trust Agreement, the Trustee is entitled to draw on the stand-by reserve account or letter of credit, then the Trustee would be permitted to resign for cause, and would be entitled to cause the sale of the overriding royalty interests and to dissolve, windup and terminate the Royalty Trust.

Overriding Royalty Interests. The Royalty Trust units represent beneficial interests in the Royalty Trust, which holds a 5% gross overriding royalty interest in future production from each of the subject interests during the life of the Royalty Trust. An “overriding” royalty interest in general represents a non-operating interest in an oil and gas property that provides the owner a specified share of production without any related operating expenses or development costs and is carved out of an oil and gas lessee’s working or cost-bearing interest in the lease. In contrast, a “working” or “cost-bearing” interest in general represents an operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expenses and development costs. An owner of a working or cost-bearing interest, subject to the terms of an applicable operating agreement, generally has the right to participate in the selection of a prospect, drilling location or drilling contractor; to propose the drilling of a well; to determine the timing and sequence of drilling operations; to commence or shut down production; to take over operations; or to share in any operating decision. An owner of an overriding royalty interest generally has none of the rights described in the preceding sentence, and neither the Royalty Trust nor the Royalty Trust unitholders has any such rights.

The Royalty Trust’s 5% gross overriding royalty interest in future production from each subject interest is proportionately reduced based on HOGA’s working interest in the subject interest. The overriding royalty interests are free and clear of any and all drilling, development and operating costs and expenses, except that the overriding royalty interests bear a proportional share of costs incurred for activities downstream of the wellhead for gathering, transporting, compressing, treating, handling, separating, dehydrating or processing the produced hydrocarbons prior to their sale, and certain production, severance, sales, excise and similar taxes related to the sale of the produced hydrocarbons and property or ad valorem taxes to the extent assessed on the subject interests (the specified post-production costs and specified taxes, respectively). The hydrocarbons underlying the overriding royalty interests are valued at the wellhead (after deduction or withholding of specified taxes and less any specified post-production costs) and HOGA has no duty to transport or market the produced hydrocarbons away from the wellhead without cost. The hydrocarbons underlying the overriding royalty interests are subject to and bear production and similar taxes.

Royalty Trust Units. Each Royalty Trust unit represents a pro rata undivided share of beneficial ownership in the Royalty Trust. Each Royalty Trust unit entitles its holder to the same rights and benefits as the holder of any other Royalty Trust unit, and the Royalty Trust has no other authorized or outstanding class of equity security.

Distributions and Income Computations. Royalties received by the Royalty Trust must first be used to (i) satisfy Royalty Trust administrative expenses and (ii) reduce Royalty Trust indebtedness. The Royalty Trust has an outstanding note payable to HOGA of $~~200~~416,~~000~~489 outstanding as of December 31, ~~2024~~2025. As of December 31, ~~2024~~2025, the Trustee has established a minimum cash reserve of $302,500. As a result, distributions will be made to Royalty Trust unitholders only when royalties received less administrative expenses incurred and repayment of any indebtedness exceeds the minimum cash reserve.

Commencing with the distribution to Royalty Trust unitholders in the first quarter of 2022, the Royalty Trust withheld $8,750 from the funds otherwise available for distribution each quarter through the first quarter of 2023, with the intent of gradually building a cash reserve of approximately $350,000. As no proceeds have been available for distribution since the first quarter of 2023, the Royalty Trust has not withheld any funds for the cash reserve with respect to those periods. Unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities, as discussed in “—The Royalty Trust” above, the Royalty Trust does not intend to withhold funds for the cash reserve, as the Royalty Trust does not expect to have any cash available to distribute to unitholders in future periods. This cash is reserved for the payment of future known, anticipated or contingent expenses or liabilities of the Royalty Trust. The Trustee may increase or decrease the targeted cash reserve amount at any time, and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the Royalty Trust unitholders. Cash held in reserve will be invested as required by the Royalty Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to Royalty Trust unitholders, together with interest earned on the funds.

There was no distributable income for the ~~year~~years ended December 31, ~~2024.~~2025 ~~Distributable~~and ~~Income totaled $197,331 for the year ended December 31, 2023~~2024. These distributions are not necessarily indicative of future distributions. As previously disclosed, the sole well producing from the onshore Highlander subject interest experienced an operational issue on January 19, 2023, resulting in substantial amounts of water entering the well, which caused a shut in of the well before production resumed at significantly reduced levels. Following an evaluation by HOGA’s field operations team, HOGA determined that it would be necessary to commence operations to control the water production, in expectation of eventually initiating “kill” operations on the well. HOGA informed the Trustee that the well was shut in effective March 31, 2023 and production from the well has ceased. After that time the well flowed intermittently but not on a continuous basis. In October 2023, HOGA informed the Trustee that due to the underground flow of fluids into the wellbore, the well could not be salvaged and would be required to be plugged and abandoned. HOGA subsequently informed the Trustee that operations to permanently plug and abandon the well commenced in early March 2024. The onshore Highlander subject interest is the only subject interest that has established commercial production. Abandoning the well eliminated any production from the onshore Highlander subject interest, which also eliminated any proceeds to which the Royalty Trust would be entitled pursuant to its overriding royalty interests during the same period. Unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities, the Royalty Trust does not expect to receive any income attributable to its overriding royalty interests and accordingly, does not expect to have any cash available to distribute to Royalty Trust unitholders in future periods. HOGA ~~has~~previously informed the Trustee that a new well on the onshore Highlander subject interest was spudded on January 30, 2025 and recently reported that the well had reached total depth of 30,862 feet on February 17, 2026; however, the future production status of this well remains unknown. Neither the Trustee nor the Royalty Trust unitholders has any right to control or influence operations of the subject interest.

The Royalty Trust’s only other sources of liquidity are mandatory annual contributions, any loans and the required standby reserve account or letter of credit from HOGA. As a result, any material adverse change in HOGA’s financial condition or results of operations could materially and adversely affect the Royalty Trust and the underlying Royalty Trust units. Royalty Trust unitholders that own their Royalty Trust units on the close of business on the record date for each calendar quarter will receive a pro-rata distribution of the amount of the cash available for distribution generally 10 business days after the quarterly record date.

Unless otherwise advised by counsel or the Internal Revenue Service (IRS), the Trustee will record the income and expenses of the Royalty Trust for each quarterly period as belonging to the Royalty Trust unitholders of record on the quarterly record date. The Royalty Trust unitholders will recognize income and expenses for tax purposes in the quarter of receipt or payment by the Royalty Trust, rather than in the quarter of distribution by the Royalty Trust. Minor variances may occur; for example, a reserve could be established in one quarterly period that would not give rise to a tax deduction until a later quarterly period, or an expenditure paid in one quarterly period might be amortized for tax purposes over several quarterly periods.

Transfer of the Royalty Trust Units. Royalty Trust unitholders are permitted to transfer their Royalty Trust units in accordance with the Royalty Trust Agreement. The Trustee will not require either the transferor or transferee to pay a service charge for any transfer of a Royalty Trust unit. The Trustee may require payment of any tax or other governmental charge imposed for a transfer. The Trustee may treat the owner of any Royalty Trust unit as shown by its records as the owner of the Royalty Trust unit. The Trustee will not be considered to know about any claim or demand on a Royalty Trust unit by any party except the record owner. A person who acquires a Royalty Trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly record date. Delaware law and the Royalty Trust Agreement govern all matters affecting the title, ownership or transfer of Royalty Trust units.

Periodic Reports. Within 45 days following the end of each of the first three fiscal quarters, and within 90 days following the end of each fiscal year, the Royalty Trust files a quarterly report on Form 10-Q, or annual report on Form 10-K, as appropriate, with the SEC.

The Royalty Trust files all required federal and state income tax and information returns. Within 75 days following the end of each fiscal year, the Royalty Trust prepares and mails to each Royalty Trust unitholder of record as of a quarterly record date during such year a report in reasonable detail with the information that Royalty Trust unitholders need to correctly report their share of the income and deductions of the Royalty Trust.

The terms of the Royalty Trust Agreement require HOGA to provide to the Royalty Trust such other information available to HOGA concerning the overriding royalty interests and the subject interests burdened by the overriding royalty interests and related matters as may be necessary for the Royalty Trust to comply with its reporting obligations. In addition, the Royalty Trust Agreement requires HOGA to provide to the Royalty Trust all information required to comply with the requirements of the Exchange Act (including a “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” relating to the Royalty Trust’s financial statements) and such further information as may be required or reasonably requested by the Trustee from time to time.

Pursuant to the Royalty Trust Agreement, the Royalty Trust and the Trustee are entitled to rely on the information provided without investigation and are fully protected and will incur no liability in doing so. None of HOGA or its affiliates may be required to disclose, produce or prepare any information, documents or other materials which were generated for analysis or discussion purposes, contain interpretative data, or are subject to the attorney-client or attorney-work-product privileges, or any other privileges to which they may be entitled pursuant to applicable law.

A Royalty Trust unitholder and his representatives may examine, during reasonable business hours and at the expense of such Royalty Trust unitholder, the records of the Royalty Trust and the Trustee.

Liability of the Royalty Trust Unitholders and the Royalty Trust. Under the Delaware Statutory Trust Act, Royalty Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private for-profit corporations under the Delaware General Corporation Law. Nevertheless, courts in jurisdictions outside of Delaware may not give effect to such limitation of personal liability.

Uncertificated Interests; Transfer Agent. The Royalty Trust units are uncertificated, and ownership of the Royalty Trust units is evidenced by entry of a notation in an ownership ledger maintained by the Trustee or a transfer agent designated by the Trustee. The transfer agent is Equiniti Trust Company, LLC. The Trustee may dismiss the transfer agent and designate a successor transfer agent at any time.

THE SUBJECT INTERESTS

The subject interests originally consisted of 20 specified Inboard Lower Tertiary/Cretaceous prospects (with target depths generally greater than 18,000 feet total vertical depth) located in the shallow waters of the Gulf of Mexico and onshore in South Louisiana. The offshore subject interests consisted of the following exploration prospects: (1) Barataria; (2) Barbosa; (3) Blackbeard East; (4) Blackbeard West; (5) Blackbeard West #3; (6) Bonnet; (7) Calico Jack; (8) Captain Blood; (9) Davy Jones; (10) Davy Jones West; (11) Drake; (12) England; (13) Hook; (14) Hurricane; (15) Lafitte; (16) Morgan; and (17) Queen Anne’s Revenge. The onshore subject interests consisted of (1) Highlander; (2) Lineham Creek; and (3) Tortuga.

On February 5, 2019, McMoRan completed the Highlander Sale. The onshore Highlander subject interest was sold subject to the overriding royalty interest in future production held by the Royalty Trust. As a result of the Highlander Sale, HOGA has a 72 percent working interest and an approximate 48 percent net revenue interest in the onshore Highlander subject interest. The Royalty Trust continues to hold a 3.6 percent overriding royalty interest in the onshore Highlander subject interest. HOGA is the operator of the Highlander subject interest. The onshore Highlander subject interest is the only subject interest in which HOGA has an interest, as McMoRan previously had relinquished, allowed to expire or sold all of the other subject interests.

On January 19, 2023, the sole well producing from the onshore Highlander subject interest experienced an operational issue, resulting in substantial amounts of water entering the well, which caused a shut in of the well before production resumed at significantly reduced levels. Following an evaluation by HOGA’s field operations team, HOGA determined that it would be necessary to commence operations to control the water production, in expectation of eventually initiating “kill” operations on the well. HOGA informed the Trustee that the well was shut in effective March 31, 2023 and production from the well has ceased. After that time the well flowed intermittently but not on a continuous basis. In October 2023, HOGA informed the Trustee that due to the underground flow of fluids into the wellbore, the well could not be salvaged and would be required to be plugged and abandoned. HOGA subsequently informed the Trustee that operations to permanently plug and abandon the well commenced in early March 2024.

The onshore Highlander subject interest is the only subject interest that has established commercial production. Abandoning the well eliminated any production from the onshore Highlander subject interest, which also eliminated any proceeds to which the Royalty Trust would be entitled pursuant to its overriding royalty interests during the same period. Unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities, the Royalty Trust does not expect to receive any income attributable to its overriding royalty interests and accordingly, does not expect to have any cash available to distribute to Royalty Trust unitholders in future periods. HOGA ~~has~~previously informed the Trustee that a new well on the onshore Highlander subject interest was spudded on January 30, 2025 and recently reported that the well had reached total depth of 30,862 feet on February 17, 2026; however, the future production status of this well remains unknown. Neither the Trustee nor the Royalty Trust unitholders has any right to control or influence operations of the subject interest.

Exploratory and Development Drilling. Other than the new well that HOGA spudded on the onshore Highlander subject interest on January 30, 2025, which reached total depth of 30,862 feet on February 17, 2026 as disclosed elsewhere in this Form 10-K, HOGA did not drill any exploration or development wells on the subject interests during the years ended December 31, 2024 and ~~2023. Additionally~~2025, and there were no in-progress or suspended wells associated with the subject interests during the years ended December 31, 2024 ~~and~~or ~~2023~~2025.

Acreage. At December 31, ~~2024~~2025, HOGA owned interests in approximately 4134 gas leases onshore in South Louisiana, covering approximately 49,~~747 gross~~000 gross acres (36,~~417~~480 acres net to HOGA’s interests) associated with the onshore Highlander subject interest. The onshore Highlander ~~subject~~ subject interest is the only subject interest in which HOGA has an interest, as McMoRan previously had relinquished, allowed to expire or sold all of the other subject interests.

Natural Gas Reserves. In prior years, HOGA’s estimated proved reserves related to the onshore Highlander subject interest have been based upon reserve reports prepared by Netherland, Sewell & Associates, Inc. (NSAI), an independent petroleum engineering firm. Because the sole well on the onshore Highlander subject interest has been shut in, and a decision to abandon it was made in October 2023, there were no proved reserves related to the Highlander subject interest as of December 31, ~~2024~~2025. Accordingly, as Section 3.17 of the Royalty Trust Agreement only requires the preparation and delivery of a reserve report if there are quantifiable reserves attributable to the royalty interests as of December 31 of any year, NSAI has not provided a reserve report for the year ended December 31, ~~2024~~2025. NSAI prepared a letter stating there are no proved reserves associated with the onshore Highlander subject interest. A copy of NSAI’s letter is filed as an exhibit to this Form 10-K.

HOGA’s Vice President & General Manager is a Licensed Professional Engineer in the State of Texas and has over 35 years of technical experience in petroleum engineering and reservoir evaluation and analysis. This individual is the technical person primarily responsible for overseeing the internal reserves estimation process and providing the appropriate data to NSAI for the year-end natural gas reserves estimation process. When applicable, the preparation of proved natural gas reserve estimates related to the subject interest are completed in accordance with HOGA’s internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include (i) the review and verification of historical production data, (ii) the review by HOGA’s management of annually reported proved reserves, including the review of significant reserve changes and new proved undeveloped reserves additions, if any, (iii) the verification of property ownership; and (iv) none of HOGA’s employee’s compensation being tied to the amount of reserves reported.

Production and Productive Well Interests. As of December 31, ~~2024~~2025, the only onshore Highlander subject interest that established commercial production, which began on February 25, 2015, was shut in. Prior to February 25, 2015, there had been no commercial production of hydrocarbons from any of the subject interests. Unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities, the Royalty Trust does not expect to receive any income attributable to its overriding royalty interests and accordingly, does not expect to have any cash available to distribute to Royalty Trust unitholders in future periods. HOGA ~~has informed~~previously informed the Trustee that a new well on the onshore Highlander subject interest was spudded on January 30, 2025 and recently reported that the well had reached total depth of 30,862 feet on February 17, 2026; however, the future production status of this well remains unknown. Neither the Trustee nor the Royalty Trust unitholders has any right to control or influence operations of the subject interest. As there was no production in 2025 and 2024, the Royalty Trust did not receive any royalties for the ~~year~~years ended December ~~31,~~ ~~2024. During the year ended December~~ 31, ~~2023,~~2025 ~~the Royalty Trust received royalties of $401,278 from HOGA related to 101,352 Mcf~~and ~~of natural gas production attributable to the onshore Highlander subject interest with average post-production costs of $0~~2024.67 ~~per Mcf and an average receipt price of $4.63 per Mcf.~~

REGULATION

Although the Royalty Trust is not responsible for the activities, expenses, and obligations discussed in this section, such matters relate to HOGA’s activities with respect to the subject interests.

General. HOGA’s exploration, development and production activities are subject to federal, state and local laws and regulations governing exploration, development, production, environmental matters, occupational health and safety, taxes, labor standards and other matters. HOGA has obtained or timely applied for all material licenses, permits and other authorizations currently required for operations. Compliance is often burdensome, and failure to comply carries substantial penalties. The regulatory burden on the oil and gas industry increases the cost of doing business and affects profitability.

Exploration, Production and Development. Among other things, federal and state level regulation of HOGA’s operations mandate that operators obtain permits to drill wells and to meet bonding and insurance requirements in order to drill, own or operate wells. These regulations also control the location of wells, the method of drilling and casing wells, the restoration of properties upon which wells are drilled and the plugging and abandoning of wells. HOGA’s oil and natural gas operations are also subject to various conservation laws and regulations, which regulate the size of drilling units, the number of wells that may be drilled in a given area, the levels of production, and the unitization or pooling of oil and natural gas properties.

Exploration, Production and Development. Among other things, federal and state level regulation of HOGA’s operations mandate that operators obtain permits to drill wells and to meet bonding and insurance requirements in order to drill, own or operate wells. These regulations also control the location of wells, the method of drilling and casing wells, the restoration of properties upon which wells are drilled and the plugging and abandoning of wells. HOGA’s oil and natural gas operations are also subject to various conservation laws and regulations, which regulate the size of drilling units, the number of wells that may be drilled in a given area, the levels of production, and the unitization or pooling of oil and natural gas properties.

State and Local Regulation of Drilling and Production. HOGA owns interests in properties located in state waters of Louisiana and/or onshore in South Louisiana. Louisiana regulates drilling and operating activities by requiring, among other things, drilling permits and bonds and reports concerning operations. The laws of Louisiana also govern a number of environmental and conservation matters, including the handling and disposing of waste materials, unitization and pooling of oil and natural gas properties, and the levels of production from oil and natural gas wells.

Environmental Matters. HOGA’s operations are subject to numerous laws relating to environmental protection. These laws impose substantial penalties for any pollution resulting from HOGA’s operations. The Trustee has been advised by HOGA that HOGA believes that its operations comply with applicable laws, including environmental laws, in all material respects.

Solid Waste. HOGA’s operations require the disposal of both hazardous and non-hazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. Drilling fluids, produced waters and other wastes associated with the exploration, production and/or development of oil and natural gas, including naturally occurring radioactive material, if properly handled, are currently excluded from regulation as hazardous wastes under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste requirements. While many exploration and production wastes are exempt from regulation as hazardous waste, these wastes are generally subject to non-hazardous waste regulation under RCRA and applicable state regulations. Many state governments have specific regulations and guidance for exploration and production wastes, including the wastes associated with hydraulic fracturing activities.

Hazardous Substances. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include but are not limited to the owner or operator of the site or sites where the release occurred or was threatened to occur and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. Despite the RCRA exemption that encompasses wastes directly associated with crude oil and gas production and the “petroleum exclusion” of CERCLA, HOGA may generate or arrange for the disposal of “hazardous substances” within the meaning of CERCLA or comparable state statutes in the course of its ordinary operations. Thus, HOGA may be responsible under CERCLA (or the state equivalents) for costs required to clean up sites where the release of a “hazardous substance” has occurred. Also, it is not uncommon for neighboring landowners and other third parties to file claims for cleanup costs as well as personal injury and property damage allegedly caused by the hazardous substances released into the environment. Thus, HOGA may be subject to cost recovery and other claims as a result of operations.

Air Emissions. The Clean Air Act (CAA), as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require HOGA to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, and to comply with stringent air permit or regulatory requirements or utilize specific equipment or technologies to control emissions.

The EPA has established pollution control standards for oil and gas sources under the CAA. In 2012 and 2016, the EPA adopted federal New Source Performance Standards (NSPS) that require the reduction of volatile organic compound and sulfur dioxide emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific requirements regarding emissions from production-related wet seal and reciprocating compressors, pumps, and from pneumatic controllers and storage vessels, and for equipment leaks. These NSPS apply to sources that are newly constructed or modified after the rules’ applicability dates. More recently, the EPA adopted a final rule in 2024 that will directly regulate volatile organic compound and methane emissions from oil and gas sources constructed or modified after December 2022 and will require reductions in both pollutants through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. Additionally, the EPA for the first time adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.

The EPA ishas ~~also~~established ~~charged~~pollution ~~with~~control ~~establishing~~standards ~~National~~for ~~Ambient~~oil ~~Air~~and ~~Quality~~gas sources under the CAA. In 2012 and 2016, the EPA adopted federal New Source Performance Standards (~~NAAQS~~NSPS), that require the ~~implementation~~reduction of ~~which~~volatile ~~can~~organic ~~indirectly~~compound ~~impact~~and sulfur dioxide emissions from certain ~~HOGA’s~~fractured ~~operations.~~and ~~The~~refractured ~~CAA~~natural ~~directs~~gas ~~the~~wells ~~EPA~~for towhich ~~review~~well ~~each~~completion ~~NAAQS~~operations ~~every~~are ~~five~~conducted ~~years~~and tofurther ~~ensure~~require that ~~the~~most ~~standards~~wells ~~are~~use reduced ~~protective~~emission ~~of public~~completions, ~~health~~also ~~and~~known ~~welfare~~as “green completions.” ~~This~~These ~~process~~regulations ~~routinely~~also ~~results~~establish inspecific ~~the~~requirements ~~tightening~~regarding emissions offrom ~~those~~production-related ~~standards,~~wet seal and inreciprocating ~~October~~compressors, ~~2015~~pumps, ~~the~~and ~~EPA~~from ~~lowered~~pneumatic controllers and storage vessels, ~~the~~and ~~ozone~~for ~~NAAQS~~equipment ~~from~~leaks. 75These NSPS apply to 70sources ~~parts~~that ~~per~~are ~~billion.~~newly Inconstructed ~~December~~or ~~2020~~modified after the rules’ applicability dates. More recently, the EPA ~~published~~adopted a final rule ~~that~~in ~~retained~~2024 ~~without~~that ~~revision~~will ~~the 2015~~directly ~~NAAQS~~regulate ~~ozone~~volatile ~~standard.~~organic ~~More~~compound ~~recently,~~and ~~however,~~methane inemissions ~~February~~from oil ~~2024,~~and ~~the~~gas ~~EPA~~sources ~~has~~constructed ~~announced~~or amodified ~~final~~after ~~rule~~December ~~that~~2022 and will ~~lower~~require ~~the~~reductions ~~annual~~in ~~standard for~~both ~~fine~~pollutants ~~particulate~~through ~~matter~~its ~~from~~regulation of 12flaring, ~~micrograms~~compressors, ~~per~~pumps, ~~cubic~~storage ~~meter~~vessels, toprocess 9controllers, ~~micrograms~~well ~~per~~completions ~~cubic~~and ~~meter.~~liquids ~~State~~unloading, orand ~~federal~~equipment ~~implementation~~leaks. ~~of the~~Additionally, ~~revised~~the ~~NAAQs~~EPA infor the ~~areas~~first intime ~~which~~adopted ~~HOGA~~emissions ~~operates~~guidelines ~~could~~that ~~result~~will inapply ~~result~~to inexisting ~~stricter~~oil ~~permitting~~and orgas ~~regulatory~~sources ~~requirements,~~and ~~delay~~that orrequire reductions in ~~prohibit~~volatile ~~HOGA’s~~organic ~~ability~~compound toand ~~obtain~~methane ~~such~~emissions ~~permits,~~that ~~and~~are ~~result~~largely inequivalent ~~increased~~to ~~expenditures~~the requirements for ~~pollution~~new ~~control equipment~~sources. ~~Failure~~The toexisting source ~~comply~~emissions ~~with~~guidelines ~~air~~are ~~quality~~to ~~regulations~~be ~~may~~implemented ~~also~~through ~~result~~state ~~in administrative~~plans, ~~civil,~~with ~~and/or~~expected ~~criminal~~compliance ~~penalties~~dates for ~~non-compliance~~existing sources arriving in 2029.

The results of the 2024 presidential election inand ~~the~~President ~~United~~Trump’s ~~States~~energy ~~may~~agenda prioritizing domestic oil and gas production likely will impact the air quality-related requirements that apply to HOGA. ~~The~~In ~~Trump~~March ~~Administration~~2025, the EPA announced it was reconsidering the 2024 rules ~~may~~that ~~adopt~~established anew ~~different~~volatile ~~approach~~organic tocompound ~~many~~and ~~actions~~methane ~~taken~~emissions ~~under~~standards ~~the~~for ~~prior~~both ~~presidential~~new ~~administration,~~and ~~including~~existing sources. Following that announcement, the ~~2024~~EPA ~~revisions~~adopted amendments to the ~~emissions~~ ~~standards~~NSPS and ~~guidelines~~existing source performance standards that extended the compliance deadlines for many of the new ~~and~~source ~~existing~~requirements ~~sources~~adopted in 2024 and extended the ~~oil~~state ~~and~~plan ~~gas~~submittal ~~industry~~deadlines, aswhich ~~well~~will aseffectively extend the ~~2024~~dates ~~changes~~by towhich existing sources must come into compliance with the ~~NAAQS for~~existing ~~fine~~source ~~particulate~~emissions ~~matter~~guidelines. ~~The~~It ~~outcome~~is ofcurrently ~~the~~unknown ~~Trump~~whether ~~Administration~~EPA’s reconsideration ~~evaluation~~ of the 2024 rules will result in further changes. Similar to prior ~~administration’s~~changes ~~regulatory approach~~to isthe ~~not~~air ~~certain~~pollution atcontrol ~~this~~standards ~~time~~for oil and gas sources, ~~but~~the ~~President~~most ~~Trump~~recent ~~has~~changes ~~made~~will itbe ~~clear~~subject ~~that~~to ~~his~~judicial ~~energy~~review, ~~agenda~~as ~~prioritizes~~well anas ~~increase~~the inpotential ~~domestic~~for future presidential administrations ~~oil~~to ~~and~~take ~~gas~~a ~~production~~different approach.

~~Climate~~The ~~Change.~~EPA ~~The~~is ~~threat~~also ofcharged ~~climate~~with ~~change~~establishing ~~continues~~National toAmbient ~~attract~~Air ~~considerable~~Quality ~~attention~~Standards ~~globally.~~(NAAQS), Inthe ~~response~~implementation toof ~~its~~which ~~2009~~can ~~finding~~indirectly ~~that emissions~~impact ofHOGA’s ~~carbon~~operations. ~~dioxide,~~The ~~methane~~CAA ~~and~~directs ~~other~~the ~~greenhouse~~EPA ~~gases~~to ~~(GHGs)~~review ~~may~~each ~~present~~NAAQS anevery ~~endangerment~~five years to ensure that the standards are protective of public health and welfare. This process routinely results in the ~~environment~~tightening of those standards, and in October 2015, the EPA lowered ~~has~~the ~~issued~~ozone ~~regulations~~NAAQS tofrom ~~restrict~~75 ~~emissions~~to of70 ~~greenhouse~~parts ~~gases~~per ~~under~~billion. ~~existing~~In ~~provisions~~December of2020, the ~~CAA.~~EPA ~~These~~published ~~regulations~~a ~~include~~final ~~limits on~~rule ~~tailpipe~~that ~~emissions~~retained ~~from~~without ~~motor~~revision ~~vehicles~~the 2015 NAAQS ozone standard. Likewise, ~~preconstruction~~in ~~and~~March ~~operating~~2024, ~~permit~~the ~~requirements~~EPA ~~for~~issued ~~certain~~a ~~large~~final ~~stationary~~rule ~~sources,~~that ~~and methane~~lowered ~~emissions~~the ~~standards~~annual standard for ~~certain~~fine ~~new,~~particulate matter ~~modified~~from ~~and~~12 ~~reconstructed~~to ~~oil~~9 ~~and~~micrograms ~~gas~~per ~~sources~~cubic —meter. asIn ~~well~~March as2025, however, the EPA’s ~~methane emissions~~announced ~~guidelines~~that ~~for~~it ~~existing~~would ~~oil~~reconsider ~~and~~the ~~gas~~rule ~~sources~~lowering the ~~that~~fine ~~were~~particulate ~~adopted~~matter instandard, ~~2024.~~and ~~The~~the EPA ~~also~~ has ~~adopted~~filed ~~rules~~a ~~requiring~~request that the ~~reporting of~~U.S. ~~GHG~~Court ~~emissions~~of ~~from~~Appeals ~~specified~~vacate ~~large~~the ~~greenhouse~~2024 ~~gas~~rule. ~~emission~~In ~~sources~~2026, in the EPA ~~United~~also ~~States,~~has asdelayed ~~well~~taking as certain ~~onshore~~actions ~~oil~~necessary ~~and~~to ~~natural gas~~implement ~~production~~air ~~facilities,~~quality onrequirements anunder ~~annual~~the ~~basis~~lower 2024 standard. OnNo ~~January~~regulatory action ~~20,~~or ~~2025,~~court ~~President~~decision ~~Trump~~has ~~announced~~changed the ~~withdrawal~~2024 ofrule lowering the ~~United~~fine ~~States~~particulate ~~from the~~matter ~~Paris~~standard, ~~Climate~~and ~~Agreement.~~the ~~President~~EPA’s ~~Trump~~delayed ~~also~~implementation of ~~issued~~the an2024 ~~executive~~standard ~~order~~likely ~~directing~~will ~~the~~be ~~EPA~~subject to judicial review. State or federal implementation of the ~~legality~~revised ~~and~~NAAQs ~~continuing~~in ~~applicability~~the areas in ofwhich ~~its~~HOGA ~~2009~~operates ~~GHG~~could ~~endangerment~~result ~~finding.~~in ~~The~~result ~~outcome~~in ofstricter ~~that~~permitting ~~review~~or isregulatory ~~not~~requirements, ~~currently~~delay ~~known;~~or ~~however~~prohibit HOGA’s ability to obtain such permits, itand ~~has~~result ~~the~~in ~~potential~~increased expenditures for pollution control equipment. Failure to ~~eliminate~~comply ~~the~~with air quality regulations ~~basis~~may ~~for~~also ~~the~~result ~~EPA’s~~in ~~regulation~~administrative, ofcivil, ~~GHGs~~and/or ~~under~~criminal ~~the~~penalties ~~CAA~~for non-compliance.

Climate Change. The threat of climate change continues to attract considerable attention globally. The Trump Administration’s efforts ~~EPA~~to ~~has~~roll ~~established~~back ~~GHG~~federal ~~standards~~regulation ~~for~~of ~~oil~~greenhouse ~~and~~gases ~~gas~~(GHGs) ~~sources~~represent ~~based~~a onsignificant shift in federal climate policy, though the ~~GHG~~ultimate impact ~~endangerment~~of ~~finding~~those efforts on HOGA is unclear. In ~~2024~~2009, the EPA ~~adopted~~found athat ~~final~~emissions ~~rule~~of carbon dioxide, methane and GHGs may present an ~~that~~endangerment ~~will~~to ~~directly~~public ~~regulate~~health ~~volatile~~and ~~organic~~the ~~compound~~environment and ~~methane~~subsequently issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed oil and gas sources — as well as the EPA’s methane emissions guidelines for existing oil and ~~will~~gas ~~require~~sources ~~reductions~~that were adopted in ~~GHG~~2024. ~~and~~The ~~volatile~~EPA ~~organic~~also ~~compound~~has ~~emissions~~adopted ~~through~~rules ~~its~~requiring ~~regulation~~the reporting of ~~flaring,~~GHG ~~compressors,~~emissions ~~pumps,~~from ~~storage~~specified ~~vessels,~~large ~~process~~greenhouse ~~controllers,~~gas emission sources in the United States, as well ~~completions~~as certain onshore oil and ~~liquids~~natural ~~unloading~~gas production facilities, ~~and~~on ~~equipment~~an ~~leaks~~annual basis. AtShortly ~~the~~after ~~same~~President Trump ~~time~~took office in January 2025, the ~~EPA~~federal ~~adopted~~government ~~emissions~~embarked ~~guidelines~~on ~~that~~a ~~will~~series ~~apply~~of changes relating to ~~existing~~ ~~oil~~climate policy and ~~gas~~regulation. On ~~sources~~January ~~and~~20, ~~that~~2025, ~~require~~President ~~reductions~~Trump inannounced ~~volatile~~the ~~organic~~withdrawal ~~compound~~of ~~and~~the ~~methane~~United ~~emissions~~States ~~that~~from ~~are~~the ~~largely~~Paris ~~equivalent~~Climate Agreement. In July 2025, the EPA issued a proposed rule to rescind the ~~requirements~~2009 GHG endangerment finding that provided a basis for ~~new~~GHG ~~sources~~regulation under the CAA. ~~The~~In ~~existing~~September 2025, ~~source~~the ~~emissions~~EPA ~~guidelines~~proposed ~~are~~to rescind the GHG reporting program for sectors other than the oil and gas sector, while proposing to besuspend GHG ~~implemented~~reporting ~~through~~requirements ~~state~~for ~~plans~~the oil and gas sector until 2034. In February 2026, ~~with~~the ~~expected~~EPA adopted a final rule repealing its prior ~~compliance~~endangerment ~~dates~~finding, which opens the door for ~~existing~~the ~~sources~~EPA ~~arriving~~to inrepeal ~~2029~~its GHG rules for the oil and gas sector.

The Inflation Reduction Act of 2022 (the IRA) included new Clean Air Act section 136(c) directing EPA to collect the Waste Emissions Charge (WEC) from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to methane emissions from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance with the EPA’s new or existing source methane requirements. The EPA adopted new rules to implement the WEC program in November 2024; however, the fate of the WEC and the EPA rules implementing the WEC is unclear. In February 2025, the United States House of Representatives and Senate both passed resolutions to repeal the EPA’s 2024 WEC rules under the Congressional Review Act (“CRA”), and on March 14, 2025 President Trump signed the resolution repealing those rules under the CRA. In addition, the United States House of Representatives and Senate may be considering amendment or repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.

The EPA has established methane standards for oil and gas sources based on the now-repealed GHG endangerment finding. In 2024, the EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from new oil and gas sources and will require reductions in methane and volatile organic compound emissions through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates arriving in 2029. In 2025, however, the EPA extended certain compliance deadlines for both new and existing sources, and the 2026 endangerment finding repeal provides a basis for undoing the oil and gas methane standards – though the fact that the oil and gas standards address both methane and volatile organic compounds, which are regulated independently of the EPA’s authority to regulate GHGs, may limit the impact of future changes to the methane standards that currently apply to oil and gas sources.

The Inflation Reduction Act of 2022 (the IRA) included new Clean Air Act section 136(c) directing EPA to collect the Waste Emissions Charge (WEC) from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to methane emissions from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance with the EPA’s new or existing source methane requirements. The EPA adopted new rules to implement the WEC program in November 2024; however, the fate of the WEC and the EPA rules implementing the WEC is unclear. In March 2025, President Trump signed legislation repealing the EPA’s 2024 WEC rules under the Congressional Review Act. The repeal of EPA’s WEC rules did not eliminate the statutory requirement to pay the WEC, but it eliminated the rules established by the EPA to determine the WEC due, the payment mechanism, and any payment deadlines. The U.S. Congress may be considering amendment or repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.

Additional climate-related regulations have been passed by several states, and additional laws may be implemented at the federal, state, or local levels. Please see Part I, Item 1A. “Risk Factors” of this Form 10-K for further discussion of risks related to climate change and the regulation of methane emissions and GHGs.

Water. The Federal Clean Water Act (CWA) and analogous state laws impose restrictions and strict controls on the discharge of pollutants into “waters of the United States” and waters within the scope of state law, respectively. Pursuant to the CWA and applicable state laws, the discharge of pollutants to regulated waters is prohibited unless it is permitted by the EPA, an analogous state or tribal agency, or both. HOGA does not presently discharge pollutants associated with the exploration, development and production of oil and natural gas on the onshore Highlander subject interest into federal or state waters. HOGA operates under the Louisiana Pollutant Discharge Elimination System (LPDES) General Permit for Discharges from Oil & Gas Exploration, Development, and Production facilities Located within Coastal Waters of Louisiana (LAG330000) issued by the Louisiana Department of Environmental Quality in accordance with the National Pollutant Discharge Elimination System (NPDES) provisions of the CWA.

The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued under CWA Section 404 by the U.S. Army Corps of Engineers (USACE). CWA Section 401 provides that the applicant for a National Pollutant Discharge Elimination System permit to be issued by the EPA or a Section 404 permit to be issued by the USACE must seek a Section 401 water quality certification by applying to the state in which the discharge will occur for the state to determine if the discharge will comply with the state’s approved water quality program. In some instances, this process could result in delay in issuance of the permit, more stringent permit requirements, or denial of the permit.

How the EPA and the USACE define “waters of the United States” (WOTUS), which defines the extent of geographic jurisdiction under the CWA, can impact HOGA’s regulatory and permitting obligations under the CWA. In 2023, the EPA and the USACE issued a final rule (2023 rule) that was described by the EPA and the USACE as following the 1986 regulations as modified by subsequent U.S. Supreme Court decisions and guidance issued by the EPA and USACE interpreting the decisions. Shortly thereafter, the Supreme Court issued its decision in Sackett II which overturned a substantial portion of the basis for the 2023 rule. The USACE and the EPA subsequently amended the 2023 rule, and excluded a number of types of wetlands and streams from CWA jurisdiction, but the rule is subject to litigation regarding the sufficiency of the agencies’ interpretation of the Sackett II decision. The 2023 rule is presently in effect in about half of the states while it is enjoined in the other half. In those states where the rule is enjoined, the EPA and the USACE define WOTUS in accordance with an earlier regulatory definition adjusted in light of the Supreme Court’s Sackett II decision. HOGA’s regulatory obligations and permitting costs will continue to be subject to remaining uncertainty around the definition of WOTUS and the scope of CWA regulation, given the ongoing litigation. To the extent that HOGA must obtain permits for the discharge of pollutants or for dredge and fill activities in wetland areas or other waters of the United States, HOGA could face increased costs and delays associated with obtaining such permits under the broader definition of WOTUS that expands the scope of CWA jurisdiction.

USACE Nationwide Permits (NWPs) are a streamlined form of permitting used to authorize activities related to development activities with minimal individual or cumulative adverse effects in wetlands or other waters of the United States under the CWA. Some NWPs are also used to authorize activities that impact traditional navigable waters under the Rivers and Harbors Act. NWP 12 will expire in March 2026 and be replaced with a new version. In addition, a federal court in Washington, D.C. is currently hearing a challenge to NWP 12. An adverse decision in the litigation may restrict or remove the ability to use NWP 12 to permit regulated impacts, resulting in the need to apply for a more time-consuming individual permit. This could result in additional cost and time for permitting projects.

In February 2025, the USACE began implementing emergency permitting procedures as directed by President Trump’s Executive Order Declaring a National Energy Emergency. This may result in substantially decreased timeframes for receiving Section 404 permits in the case of energy projects subject to the Executive Order.

How the EPA and the USACE define “waters of the United States” (WOTUS), which defines the extent of geographic jurisdiction under the CWA, has been the subject of controversy and litigation for decades and can impact HOGA’s regulatory and permitting obligations under the CWA. In 2023, in Sackett v. EPA, the Supreme Court issued a landmark decision interpreting WOTUS more narrowly than the then-current definition contemplated, resulting in diminished jurisdiction over wetlands and streams that lacked certain connections to other waters or consistent water flow. Following Sackett, because of ongoing litigation, the regulatory landscape currently remains unsettled. The regulations currently in effect in 24 states define WOTUS using a 2023 regulation modified after the Sackett decision. In the rest of the country, the agencies base jurisdiction on an earlier WOTUS definition as implemented in light of a number of Supreme Court decisions, including Sackett. Despite the two approaches, jurisdiction over WOTUS is essentially consistent across the United States.

In November 2025, the USACE released a proposed rule revising the regulatory definition of WOTUS. That new definition is expected to go into effect in early 2026 without substantial changes from the proposed definition. Regardless of the ultimate details, the revised definition likely will further reduce CWA jurisdiction, especially over wetlands and streams, leading to fewer permitting requirements. Once the new WOTUS definition is final, litigation will likely continue challenging the legality of the definition. This litigation could have the effect of delaying or precluding implementation of the new rule. HOGA’s regulatory obligations and permitting costs will continue to be subject to remaining uncertainty around the definition of WOTUS and the scope of CWA regulation, given the ongoing litigation. To the extent that HOGA must obtain permits for the discharge of pollutants or for dredge and fill activities in wetland areas or other waters of the United States, HOGA could face increased costs and delays associated with obtaining such permits under the broader definition of WOTUS that expands the scope of CWA jurisdiction.

USACE Nationwide Permits (NWPs) are a streamlined form of permitting used to authorize activities related to development activities with minimal individual or cumulative adverse effects in wetlands or other waters of the United States under the CWA. Some NWPs are also used to authorize activities that impact traditional navigable waters under the Rivers and Harbors Act. The NWPs expire in March 2026 and will be replaced, simultaneously, with new versions that are largely unchanged from the previous set. Litigation challenging the NWPs, if filed, could result in additional cost and time for permitting projects.

In February 2025, the USACE began implementing emergency permitting procedures as directed by President Trump’s Executive Order Declaring a National Energy Emergency. This has resulted, in many instances, in substantially decreased timeframes for receiving Section 404 permits in the case of energy projects subject to the Executive Order.

Similarly, the Oil Pollution Act of 1990 (Oil Pollution Act) imposes liability on “responsible parties” for the discharge or substantial threat of discharge of oil into navigable waters or adjoining shorelines. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which a facility is located. The Oil Pollution Act assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct, or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the Oil Pollution Act. The Oil Pollution Act also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

Endangered Species. The federal Endangered Species Act and similar state statutes impose regulations designed to ensure that endangered or threatened plant and animal species are not jeopardized, and their critical habitats are neither destroyed nor modified by federal action. These laws may restrict HOGA’s exploration, development, and production operations and impose civil or criminal penalties for noncompliance.

National Environmental Policy Act. The National Environmental Policy Act (NEPA) requires the federal government to undertake an environmental review prior to making a decision on most proposed federal actions – such as permits, leases, and rights-of-way. ~~Until~~Driven ~~2025, agencies undertook NEPA reviews pursuant to binding regulations issued~~ by ~~the White House Council on Environmental Quality (CEQ) as well as pursuant~~court todecisions ~~the~~and ~~federal~~Administration ~~agency’s~~policy, ~~own~~ NEPA ~~procedures.~~implementation ~~CEQ~~and ~~issued~~resulting ~~its~~litigation ~~rules~~changed ~~after~~dramatically ~~being directed to do so by an Executive Order issued~~ in ~~the~~ ~~Carter Administration~~2025. ~~After~~Key ~~two~~changes ~~federal~~are ~~courts held that CEQ did not have authority to issue binding regulations, the Trump Administration~~driving ~~revoked~~agencies ~~the~~narrow ~~Carter~~their ~~Administration~~NEPA ~~Executive~~reviews ~~Order~~ and ~~directed~~complete ~~CEQ~~them tofaster ~~withdraw~~and ~~the~~are ~~regulations.~~driving Incourts ~~their place, agencies are directed~~ to ~~develop~~show ~~procedures~~more ~~that~~deference ~~hew~~ to ~~the~~agencies ~~statutory~~when ~~text over~~ reviewing the ~~course~~adequacy of ~~2025~~an ~~with~~agency’s ~~the~~analysis ~~goal~~under ~~of having them finalized in early 2026. In the meantime, agencies will continue to use their own~~ NEPA ~~procedures and may continue to follow the CEQ regulations~~, ~~using~~benefitting ~~them~~private asprojects ~~guidance. This~~that may ~~result~~require infederal ~~delays~~permits and ~~uncertainty in permitting~~ reviews ~~as agencies adjust to a new NEPA approach~~.

In particular, until 2025, agencies undertook NEPA reviews pursuant to binding regulations issued by the White House Council on Environmental Quality (CEQ) as well as pursuant to the federal agency’s own NEPA procedures. After two federal courts found that CEQ did not have authority to issue binding regulations, CEQ withdrew their regulations. In their place, agencies each issued their own NEPA procedures and, for the most part, put those procedures in agency guidance rather than binding regulations, although the USACE (which issues permits that can be critical to construction) regulatory program is a notable exception, keeping its NEPA procedures in regulations. While the agency procedures were based on a CEQ template, there are inconsistencies among the agencies on various topics, including the requirement for public comment and consideration of various types of impacts. These procedures make changes that are intended to streamline reviews.

Also, on May 29, 2025, the Supreme Court decided Seven County Infrastructure Coalition v. Eagle County, Colorado, in which the Court expressed clear intention that NEPA should be brought “back in line with the statutory text and common sense.” Significantly for permits that may be needed for private projects, the Court clarified that agencies need only evaluate the effects of the specific “proposed action” before them, not the impacts of “other future or geographically separate projects that may be built (or extended) as a result of or in the wake of the immediate project under consideration.” The Court also emphasized that courts must afford agencies substantial deference in reviewing agency actions under NEPA and that agencies “must have broad latitude to draw a ‘manageable line’” when determining the appropriate scope of analysis. The Court’s decision may reduce litigation risk and help streamline federal reviews.

EMPLOYEES

The Royalty Trust is a passive entity and has no employees. All administrative functions of the Royalty Trust are performed by the Trustee and HOGA.

COMPETITION

The production and sale of oil and natural gas onshore in South Louisiana is highly competitive, particularly with respect to hiring and retention of technical personnel, the acquisition of leases, interests and other properties, and access to drilling rigs and other services in such areas. HOGA’s competitors in these areas include major integrated oil and gas companies and numerous independent oil and gas companies, individual producers and operators.

Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Additionally, future price fluctuations for natural gas will directly affect the amount of distributions to Royalty Trust unitholders and will also affect estimates of reserves attributable to the overriding royalty interests and estimated and actual future net revenues of the Royalty Trust. Neither HOGA nor the Royalty Trust can make reliable predictions of future natural gas supply and demand or future product prices. For more information regarding risks associated with natural gas production and commodity price fluctuations, see Part I, Item 1A. “Risk Factors” of this Form 10-K.

SEASONALITY

All of the Royalty Trust’s assets are located in the U.S., where demand for natural gas is typically lower in summer than in winter. Tropical storms and hurricanes, which are particularly common in South Louisiana during the summer and early fall of each year, can damage or completely destroy drilling, production and treatment facilities, which can result in the interruption or permanent cessation of production from associated wells. The Royalty Trust is not otherwise materially affected by seasonal factors.

TAX CONSIDERATIONS

The following is a summary of certain U.S. federal income tax matters that may be relevant to the Royalty Trust unitholders. This summary is based upon current provisions of the Internal Revenue Code of 1986, as amended (the Code), existing and proposed Treasury regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. No attempt has been made in the following summary to comment on all U.S. federal income tax matters affecting the Royalty Trust or the Royalty Trust unitholders.

The summary has limited application to non-U.S. persons and persons subject to special tax treatment such as, without limitation: banks, insurance companies or other financial institutions; Royalty Trust unitholders subject to the alternative minimum tax; tax-exempt organizations; dealers in securities or commodities; regulated investment companies; real estate investment trusts; traders in securities that elect to use a mark-to-market method of accounting for their securities holdings; non-U.S. Royalty Trust unitholders that are “controlled foreign corporations” or “passive foreign investment companies”; persons that are S-corporations, partnerships or other pass-through entities; persons that own their interest in the Royalty Trust Units through S-corporations, partnerships or other pass-through entities; persons that at any time own more than 5% of the aggregate fair market value of the Royalty Trust Units; expatriates and certain former citizens or long-term residents of the U.S.; U.S. Royalty Trust unitholders whose functional currency is not the U.S. dollar; persons who hold the Royalty Trust Units as a position in a hedging transaction, “straddle”, “conversion transaction” or other risk reduction transaction; or persons deemed to sell the Royalty Trust Units under the constructive sale provisions of the Code. Each Royalty Trust unitholder should consult his own tax advisor with respect to his particular circumstances.

Royalty Trust unitholders should consult their own tax advisors regarding the treatment of the income, gain, loss or deduction derived by the unitholder for the Royalty Trust.

The income of the Royalty Trust consists primarily of royalties equal to a specified share of the proceeds of oil and gas produced from exploration prospects. The deductions of the Royalty Trust consist of administrative expenses. Each Royalty Trust unitholder is entitled to depletion deductions because the royalties are expected to constitute “economic interests” in oil and gas properties for U.S. federal income tax purposes. The rules with respect to the depletion allowance are complex and must be computed separately by each Royalty Trust unitholder and not by the Royalty Trust. Royalty Trust unitholders should consult their own tax advisors regarding the availability of depletion deductions.

If a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property), and if the adjusted basis of such property includes adjustments for deductions for depletion under Section 611 of the Code, the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on such disposition).

The classification of the Trust’s income for purposes of the passive loss rules may be important to a Royalty Trust unitholder. Royalty income generally is treated as portfolio income and does not offset passive losses. Therefore, in general, Royalty Trust unitholders should not consider the taxable income from the Royalty Trust to be passive income in determining net passive income or loss.

The highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. The highest marginal U.S. federal income tax rate applicable to corporations is 21%, and such rate applies to both ordinary income and capital gains.

Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts. For these purposes, investment income generally will include a Royalty Trust unitholder’s allocable share of the Royalty Trust’s interest and royalty income plus the gain recognized from a sale of Royalty Trust units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s U.S. federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins. The tax consequences to a Royalty Trust unitholder of the acquisition, ownership or disposition of units will depend in part on the Royalty Trust unitholder’s tax circumstances. Royalty Trust unitholders should consult their tax advisors regarding the U.S. federal income tax consequences relating to acquiring, owning or disposing the Royalty Trust units.

As a grantor trust, the Royalty Trust is not subject to tax at the Royalty Trust level. Rather, the Royalty Trust unitholders are considered to own and receive the Royalty Trust’s assets and income and are directly taxable thereon as though no trust were in existence. Under Treasury Regulations, the Royalty Trust is classified as a widely held fixed investment trust. Pursuant to a de minimis test provided for in the Treasury Regulations, the Royalty Trust is only required to report the amount of sales proceeds distributed to a Royalty Trust unitholder during the year with respect to a sale or disposition of a trust asset. In addition, the Treasury Regulations require the sharing of tax information among trustees and intermediaries that hold a trust interest on behalf of or for the account of a beneficial owner or any representative or agent of a trust interest holder of fixed investment trusts that are classified as widely held fixed investment trusts.

The widely held fixed investment trust reporting requirements provide for the dissemination of trust tax information by the trustee to intermediaries who are ultimately responsible for reporting the investor-specific information through Form 1099 to the investors and the IRS. Every trustee or intermediary that is required to file a Form 1099 for a Royalty Trust unitholder must furnish a written tax information statement that is in support of the amounts as reported on the applicable Form 1099 to the Royalty Trust unitholder. In compliance with the reporting requirements of the Treasury Regulations for non-mortgage widely held fixed investment trusts and the dissemination of Royalty Trust tax reporting information, the Trustee provides a generic tax information reporting booklet which is intended to be used only to assist Royalty Trust unitholders in the preparation of their 2023 U.S. federal and state income tax returns. This tax information booklet can be obtained at https://gultu.q4web.com/tax-information/default.aspx. Any generic tax information provided by the Trustee is intended to be used only to assist Royalty Trust unitholders in the preparation of their U.S. federal and state income tax returns.17

The widely held fixed investment trust reporting requirements provide for the dissemination of trust tax information by the trustee to intermediaries who are ultimately responsible for reporting the investor-specific information through Form 1099 to the investors and the IRS. Every trustee or intermediary that is required to file a Form 1099 for a Royalty Trust unitholder must furnish a written tax information statement that is in support of the amounts as reported on the applicable Form 1099 to the Royalty Trust unitholder. In compliance with the reporting requirements of the Treasury Regulations for non-mortgage widely held fixed investment trusts and the dissemination of Royalty Trust tax reporting information, the Trustee provides a generic tax information reporting booklet which is intended to be used only to assist Royalty Trust unitholders in the preparation of their 2025 U.S. federal and state income tax returns. This tax information booklet can be obtained at https://gultu.q4web.com/tax-information/default.aspx. Any generic tax information provided by the Trustee is intended to be used only to assist Royalty Trust unitholders in the preparation of their U.S. federal and state income tax returns.

If the Royalty Trust were classified as a business entity, it would be taxable as a partnership unless it failed to meet certain qualifying income tests applicable to “publicly traded partnerships.” The income of the Royalty Trust is expected to meet such qualifying income tests. As a result, even if the Royalty Trust were considered to be a publicly traded partnership it should not be taxable as a corporation. The principal tax consequence of the Royalty Trust’s possible categorization as a partnership rather than a grantor trust is that all Royalty Trust unitholders would be required to report their share of taxable income from the Royalty Trust on the accrual method of accounting regardless of their own method of accounting. As a result, the Royalty Trust’s tax reporting requirements would be more complex and costlier to implement and maintain, and any distributions to Royalty Trust unitholders could be reduced as a result.

The Royalty Trust owns an overriding royalty interest burdening the subject interests, which are located in Louisiana and in U.S. federal waters offshore Louisiana. Tax counsel to the special committee of the board of directors of MMR advised the Royalty Trust at its formation that the Royalty Trust will be treated as a grantor trust and not as an unincorporated business entity for U.S. federal income tax purposes. If the Royalty Trust is treated as a grantor trust for U.S. federal income tax purposes, it would also be treated as a grantor trust for Louisiana income tax purposes. As a grantor trust, the Royalty Trust would not be subject to Louisiana income tax at the Royalty Trust level. Rather, for Louisiana individual income tax purposes, the Royalty Trust unitholders would be considered to own and receive the Royalty Trust’s assets and income and will be directly taxable thereon as though no trust were in existence. Consequently, individual Royalty Trust unitholders may be subject to Louisiana individual income tax on all or a portion of their shares of any Royalty Trust income. Individual Royalty Trust unitholders who are legal residents of Louisiana will be subject to Louisiana individual income tax on all of their shares of any Royalty Trust income. Individual Royalty Trust unitholders who are not legal residents of Louisiana generally will be subject to Louisiana individual income tax only on the portion of their shares of any Royalty Trust income that is sourced to Louisiana. For Louisiana individual income tax purposes, royalties from mineral properties are specifically sourced to the state where such property is located at the time the income is derived.

Individual Royalty Trust unitholders who are required to file Louisiana individual income tax returns and pay Louisiana individual income tax on all or a portion of their proportionate shares of any Royalty Trust income may be subject to penalties for failure to comply with such requirements. For the year ended December 31, ~~2024~~2025, the ~~highest marginal~~ rates for the payment of Louisiana income taxes are 43.250% for individuals, trusts and estates, and 75.5% for corporations. Individual taxpayers are allowed a deduction for depletion in Louisiana. The depletion allowance available under Louisiana law is 22% of the gross income from an applicable mineral property during the tax year. Louisiana currently does not require the Royalty Trust to withhold Louisiana individual income taxes from distributions made to non-resident Royalty Trust unitholders if the Royalty Trust is treated as a grantor trust for U.S. federal income tax purposes. Individual Royalty Trust unitholders who are legal residents of a state other than Louisiana may be subject to state and local individual income taxes, if any, in their states of residence on their receipt of any income from the Royalty Trust.

Royalty Trust unitholders should consult their tax advisors as to the specific tax consequences of the ownership and disposition of the Royalty Trust units, including the applicability and effect of U.S. federal, state, local and foreign income and other tax laws in light of their particular circumstances.

WHERE YOU CAN FIND OTHER INFORMATION

The Royalty Trust maintains a website at http://gultu.q4web.com/home/default.aspx. The Royalty Trust’s filings under the Exchange Act are available through its website and are also available electronically from the website maintained by the SEC at http://www.sec.gov. In addition, the Royalty Trust will provide electronic and paper copies of its recent filings free of charge upon request to the Trustee.

Item 1A. Risk Factors

This Form 10-K contains “forward-looking statements.” Please refer to the section above entitled “Forward-Looking Statements” for more information.

Risks Related to Operations

Production risks can adversely affect distributions from the Royalty Trust.

The occurrence of drilling, production or transportation accidents at any of the subject interests could reduce or eliminate Royalty Trust distributions, if any. Although the Royalty Trust, as the owner of the overriding royalty interests, should not be responsible for the costs associated with any such accidents, any such accidents may result in the loss of a productive well and associated reserves or interruption of production. The Royalty Trust does not maintain any type of insurance against any of the risks of conducting oil and gas exploration and production or related activities.

The value of the Royalty Trust units is uncertain.

The Royalty Trust’s only assets and sources of income are the overriding royalty interests burdening the onshore Highlander subject interest. The onshore Highlander subject interest is the only subject interest in which HOGA has an interest, as McMoRan previously had relinquished, allowed to expire or sold all of the other subject interests. The overriding royalty interests entitle the Royalty Trust to receive a portion of the proceeds derived from the sale of hydrocarbons associated with the subject interests, if any.

The Royalty Trust has no ability to direct or influence the exploration or development of the subject interests. In addition, HOGA is not under any obligation to fund or to commit any resources to the exploration or development of the subject interests.

To the extent that HOGA does not fund the exploration and development of the onshore Highlander subject interest, or if for any other reason sufficient production from the onshore Highlander subject interest is not achieved and maintained in commercial quantities, Royalty Trust unitholders will not realize any additional value from their investment in the Royalty Trust units.

Future Royalty Trust distributions are uncertain because the Royalty Trust does not control the operations of the subject interests and any royalties received must exceed administrative expenses, any indebtedness and a minimum cash requirement.

The Royalty Trust has no control over the operations of the subject interests, which are necessary to generate any royalties to be distributed to the Royalty Trust unitholders. In addition, any royalties received by the Royalty Trust must first be used to (i) satisfy Royalty Trust administrative expenses and (ii) reduce Royalty Trust indebtedness. Lastly, the Trustee has established a minimum cash reserve of $302,500 as of December 31, ~~2024~~2025. As a result, distributions will be made to Royalty Trust unitholders only when royalties received less administrative expenses incurred and repayment of all indebtedness exceeds the minimum cash reserve.

Although distributions were paid to Royalty Trust unitholders in 2021, 2022 and the first quarter of 2023, distributions may not necessarily be made in the future. As a result of the abandonment of the sole well producing on the onshore Highlander subject interest, the Royalty Trust does not expect to receive any income attributable to its overriding royalty interests and accordingly, does not expect to have any cash available to distribute to Royalty Trust unitholders in future periods, unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities. HOGA previously informed the Trustee that a new well on the onshore ~~Highlander~~ Highlander subject interest was spudded on January 30, 2025 and recently reported that the well had reached total depth of 30,862 feet on February 17, 2025; however, the future production status of this well remains unknown. The Royalty Trust’s only other sources of liquidity are mandatory annual contributions, any loans and the required standby reserve account or letter of credit from HOGA. As a result, any material adverse change in HOGA’s financial condition or results of operations could materially and adversely affect the Royalty Trust and the Royalty Trust units.

Natural gas prices fluctuate due to a number of factors that are beyond the control of the Royalty Trust and HOGA, and lower prices could reduce proceeds to the Royalty Trust and cash distributions to Royalty Trust unitholders.

~~Natural~~The Royalty Trust’s quarterly distributions are highly dependent on the prices realized from the sale of natural gas, and a material decrease in such prices ~~fluctuate~~could reduce the amount of cash distributions paid to Royalty Trust unitholders. Natural gas prices fluctuate widely in response to relatively minor changes in supply, market uncertainty and a variety of additional factors that are beyond the control of HOGA and the Royalty Trust. These factors include, among others:

● regional, domestic and foreign supply of, and demand for, natural gas, as well as perceptions of supply of, and demand for, natural gas; ● U.S. and worldwide political and economic conditions; ● tax, trade ~~barriers~~ and ~~tariffs;~~tariff ●policies of the ~~armed~~United ~~conflicts~~States ~~between~~and ~~Russia~~other ~~and~~countries ~~Ukraine~~involved ~~and~~in ~~between~~global ~~Israel~~energy ~~and~~markets; ~~Iran~~● the wars in Ukraine and ~~its~~the ~~proxies~~Persian Gulf and the potential destabilizing effects such conflicts may pose for the global natural gas markets; ● the occurrence or threat of epidemic or pandemic diseases or other public health event, or any government response to such occurrence or threat; ● weather conditions and seasonal trends; ● anticipated future prices of natural gas, alternative fuels and other commodities; ● technological advances affecting energy consumption and energy supply; ● the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity; ● natural disasters and other acts of force majeure; ● domestic and foreign governmental regulations and taxation; ● energy conservation and environmental measures; and ● the ~~price~~development, exploitation and ~~availability~~market acceptance of alternative ~~fuels~~energy sources as part of a transition to a lower-carbon economy.

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These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas price movements with any certainty. During ~~2024~~2025, the New York Mercantile Exchange (NYMEX) natural gas price fluctuated from a low of $12.2165 per MMBtu to a high of $139.~~20 per~~86 per MMBtu. On March 242, ~~2025~~2026, the NYMEX natural gas price was $42.0399 per MMBtu. Royalties that the Royalty Trust receives from its share of of production will be reduced as a result of lower natural gas prices. As a result, future distributions from the Royalty Trust to its ~~unitholders~~ unitholders could be reduced or discontinued. In addition, lower oil and natural gas prices reduce the likelihood that the onshore Highlander ~~subject~~ subject interest will be developed or that any oil or natural gas discovered will be economic to produce. The volatility of energy prices ~~reduces~~ reduces the accuracy of estimates of future cash distributions to the Royalty Trust unitholders and could affect the value of the Royalty ~~Trust~~ Trust units.

The onshore Highlander subject interest targets Inboard Lower Tertiary/Cretaceous formations onshore in South Louisiana, which has greater risks and costs associated with its exploration and development than conventional prospects.

To date, only the onshore Highlander subject interest has achieved commercial production of hydrocarbons from Inboard Lower Tertiary/Cretaceous reservoirs in these areas. Moreover, the onshore Highlander subject interest is the only subject interest in which HOGA has an interest, as McMoRan previously has relinquished, allowed to expire or sold all of the other subject interests. The lack of comparative data and the limitations of diagnostic tools operating in the extreme temperatures and pressures encountered at these depths make it difficult to predict reservoir quality and well performance of these formations. It is also significantly more expensive and risky to drill and complete wells in these formations than at more conventional depths. Major contributors to such increased costs and risks include far higher temperatures and pressures encountered down hole, longer drilling times and the cost and extended procurement time related to the specialized equipment required to drill and complete these types of wells.

The Royalty Trust is vulnerable to risks associated with operations onshore in South Louisiana because the onshore Highlander subject interest is located in this area.

These risks include:

	●	tropical storms and hurricanes, which are particularly common in South Louisiana during the summer and early fall of each year, and which can damage or completely destroy drilling, production and treatment facilities, which can result in the interruption or permanent cessation of production from associated wells;

	●	flooding caused by heavy rain, which can result in the interruption or permanent cessation of production from associated wells;

	●	extensive governmental regulation (including regulations that may, in certain circumstances, impose strict liability for pollution damage); and

	●	interruption or termination of operations by governmental authorities based on environmental, safety or other considerations, including those relating to other operators and/or other geographical areas.

These exposures onshore in South Louisiana could have a material adverse effect on the onshore Highlander subject interest, on the Royalty Trust’s results of operations and financial condition, and on the market price of the Royalty Trust units.

Risks Related to Environmental Conditions

Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas that HOGA produces while the physical effects of climate change could disrupt their production and cause it to incur significant costs in preparing for or responding to those effects.

The threat of climate change continues to attract considerable attention globally. InThe ~~response~~Trump Administration’s efforts to ~~its~~roll back federal regulation of greenhouse gases (GHGs) represent a significant shift in federal climate policy, though the ultimate impact of those efforts on HOGA is unclear. In 2009, ~~finding~~the EPA found that emissions of carbon dioxide, methane and other ~~greenhouse gases (“~~GHGs”) may present an endangerment to public health and the environment, ~~the EPA~~and ~~has~~subsequently issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed oil and gas sources — as well as the EPA’s methane emissions guidelines for existing oil and gas sources that were adopted in 2024. The EPA also has adopted rules requiring the reporting of GHG emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. In addition to this direct regulation of oil and gas sources, the EPA has recently proposed rules to implement the mandatory Waste Emissions Charge under the Inflation Reduction Act of 2022, which will charge a fee based on the methane emissions from applicable facilities in the oil and gas sector starting in 2024.

On January 20, 2025, President Trump announced the withdrawal of the United States from the Paris Climate Agreement. President Trump also issued an executive order directing the EPA to review the legality and continuing applicability of its 2009 GHG endangerment finding. The outcome of that review is not currently known; however, it has the potential to eliminate the basis for the EPA’s regulation of GHGs under the CAA.

The EPA has established GHG standards for oil and gas sources under the CAA based on its endangerment finding. In 2024, the EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from new oil and gas sources and will require further emissions reductions through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.

The Inflation Reduction Act of 2022 (the IRA) included new CAA section 136(c) directing the EPA to collect the Waste Emissions Charge (WEC) from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to methane emissions from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance with the EPA’s new or existing source methane requirements. The EPA adopted new rules to implement the WEC program in November 2024. The EPA adopted new rules to implement the WEC program in November 2024. The fate of the WEC and the EPA rules implementing the WEC is unclear. In February 2025, the United States House of Representatives and Senate both passed resolutions to repeal the EPA’s 2024 WEC rules under the Congressional Review Act (CRA), and on March 14, 2025 President Trump signed the resolution repealing those rules under the CRA. In addition, the United States House of Representatives and Senate may be considering amendment or repeal of certain portions of the IRA, including the statutory provisions establishing the WEC. As a result, the legislative face of the WEC is unclear.

Additionally, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. In addition, Congress may consider adopting legislation to reduce emissions of greenhouse gases. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on HOGA’s business, capital expenditures, financial condition and results of operations.

Shortly after President Trump took office in January 2025, the federal government embarked on a series of changes relating to climate policy and regulation. On January 20, 2025, President Trump announced the withdrawal of the United States from the Paris Climate Agreement. In July 2025, the EPA issued a proposed rule to rescind the 2009 GHG endangerment finding that provided a basis for GHG regulation under the CAA. In September 2025, the EPA proposed to rescind the GHG reporting program for sectors other than the oil and gas sector, while proposing to suspend GHG reporting requirements for the oil and gas sector until 2034. In February 2026, the EPA adopted a final rule repealing its prior endangerment finding, which opens the door for the EPA to repeal its GHG rules for the oil and gas sector.

The EPA has established methane standards for oil and gas sources under the CAA based on the now-repealed GHG endangerment finding. In 2024, the EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from new oil and gas sources and will require further emissions reductions through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029. In 2025, however, the EPA extended certain compliance deadlines for both new and existing sources, and the 2026 endangerment finding repeal provides a basis for undoing the oil and gas methane standards, though the fact that the oil and gas standards address both methane and volatile organic compounds, which are regulated independently of EPA’s authority to regulate GHGs, may limit the impact of future changes to the methane standards that currently apply to oil and gas sources.

The Inflation Reduction Act of 2022 (the IRA) included new CAA section 136(c) directing the EPA to collect the Waste Emissions Charge (WEC) from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to methane emissions from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance with the EPA’s new or existing source methane requirements. The EPA adopted new rules to implement the WEC program in November 2024. The EPA adopted new rules to implement the WEC program in November 2024. The fate of the WEC and the EPA rules implementing the WEC is unclear. In March 2025, President Trump signed legislation repealing the EPA’s 2024 WEC rules under the Congressional Review Act. The repeal of the EPA’s WEC rules did not eliminate the statutory requirement to pay the WEC, but it eliminated the rules established by the EPA to determine the WEC due, the payment mechanism, and any payment deadlines. The U.S. Congress may be considering amendment or repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.

Meanwhile, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. In addition, Congress may consider adopting legislation to reduce emissions of greenhouse gases. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on HOGA’s business, capital expenditures, financial condition and results of operations.

The adoption and implementation of regulations imposing reporting obligations on, or limiting emissions of GHGs from, HOGA’s equipment and operations could require HOGA to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas it produces. Legislation or regulations that may be adopted to address climate change could also affect the markets for HOGA’s products by making its products more or less desirable than competing sources of energy. To the extent that its products are competing with higher GHG-emitting energy sources, HOGA’s products may become more desirable in the market with more stringent limitations on GHG emissions. To the extent that its products are competing with lower GHG-emitting energy, HOGA’s products may become less desirable in the market with more stringent limitations on greenhouse gas emissions. HOGA cannot predict with any certainty at this time how these possibilities may affect its operations.

In addition, new and emerging regulatory initiatives in the U.S. related to climate change could adversely affect the Royalty Trust. On March 6, 2024, the SEC issued a final rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The final rule mandates extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy and greenhouse gas emissions, for certain public companies. Compliance with the final rule may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on the personnel, systems and resources of HOGA or the Royalty Trust or both.22

In addition, future regulatory initiatives in the U.S. related to climate change disclosure or reporting could adversely affect the Royalty Trust. On March 6, 2024, the SEC issued a final rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The final rule mandates extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy and greenhouse gas emissions, for certain public companies. The SEC’s climate disclosure rule was challenged in court, and in March 2025 the SEC announced that it had voted to end its defense of the 2024 rule. The outcome of that litigation or separate rule changes made by the SEC may result in changes to climate-related disclosure requirements. Even in the absence of federal requirements, however, some states have adopted climate disclosure laws or rules that are not affected by the SEC’s review. Compliance with the federal or state disclosure rules may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on the personnel, systems and resources of HOGA or the Royalty Trust or both.

Finally, some scientists have theorized that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such significant physical effects were to occur, they could have an adverse effect on HOGA’s assets and operations and cause HOGA to incur costs in preparing for and responding to them. Additionally, energy needs could increase or decrease as a result of extreme weather conditions, depending on the duration and magnitude of those conditions.

Risks Related to Ownership of the Royalty Trust Units

There is a limited public market for the Royalty Trust units, which could affect the market price, trading volume, liquidity and resale price of the Royalty Trust units.

The Royalty Trust units are quoted on the ~~OTC~~OTCID ~~Pink~~Basic ~~tier~~Market of(OTCID), ~~the~~operated ~~over-the-counter~~by (OTC) ~~markets~~Markets Group, Inc. The ~~OTC~~OTCID ~~Pink~~ is a significantly more ~~limited~~ limited market than the national securities exchanges, which could adversely affect the market price, trading volume, liquidity and resale ~~price~~ price of the Royalty Trust units.

Meanwhile, an active market in the Royalty Trust units may not continue at present levels or increase in the future. In addition, securities that trade on the ~~OTC~~OTCID ~~Pink~~may experience more volatility compared to securities that trade on a national securities exchange. This volatility may be caused by a variety of factors, including the lack of readily available price quotations, the absence of consistent administrative supervision of bid and ask quotations, lower trading volumes, and market conditions.

Because there is a limited public market for the Royalty Trust units, the market price and trading volume of the Royalty Trust units may be volatile.

The Royalty Trust unitholders may experience fluctuations in the market price and volume of the trading market for the Royalty Trust units for many reasons, including, without limitation:

	●	as a result of other risk factors discussed in this Form 10-K;

	●	the failure of the onshore Highlander subject interest to produce hydrocarbons;

	●	decisions by HOGA to delay or not to pursue the exploration or development of the onshore Highlander subject interest;

	●	reasons unrelated to operational performance, such as reports by industry analysts, investor perceptions, or announcements by competitors regarding their own performance;

	●	legal or regulatory changes that could impact the business of HOGA; and

	●	general economic, securities markets and industry conditions.

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Fluctuations in the volume of the trading market may have a negative effect on the market price for the Royalty Trust units. Accordingly, Royalty Trust unitholders may not be able to realize a fair price when they determine to sell their Royalty Trust units or may have to hold them for a substantial period of time until the market for the Royalty Trust units improves, if it does at all. HOGA has a call right with respect to the outstanding Royalty Trust units at $10 per Royalty Trust unit. This call right could impose a ceiling on the price of the Royalty Trust units. In addition, if the Royalty Trust units are then listed for trading or admitted for quotation on a national securities exchange or any quotation system and the volume-weighted average price per Royalty Trust unit is equal to $0.25 or less for the immediately preceding consecutive nine-month period, HOGA may purchase all, but not less than all, of the outstanding Royalty Trust units at a price of $0.25 per Royalty Trust unit so long as HOGA tenders payment within 30 days following the end of such nine-month period. See Part I, Items 1. and 2. “Business and Properties – The Royalty Trust – The Royalty Trust Agreement – HOGA Call Rights” of this Form 10-K. In addition, Royalty Trust unitholders may incur brokerage charges in connection with the resale of the Royalty Trust units, which in some cases could exceed the proceeds realized by a holder from the resale of its Royalty Trust units.

“Penny Stock” rules may make buying or selling the Royalty Trust units difficult.

Trading in the Royalty Trust units is subject to material limitations as a consequence of regulations that limit the activities of broker-dealers effecting transactions in “penny stocks.” Pursuant to Rule 3a51-1 under the Exchange Act, the Royalty Trust units are a “penny stock” because (i) they are not listed on any national securities exchange, (ii) they have a market price of less than $5.00 per unit, and (iii) their issuer (the Trust) has net tangible assets less than $2,000,000 (if the issuer has been in business for at least three years) or $5,000,000 (if the issuer has been in business for less than three years). Rule 15g-9 promulgated under the Exchange Act imposes limitations upon trading activities on “penny stocks,” which makes selling the Royalty Trust units more difficult compared to selling securities that are not “penny stocks.” Rule 15a-9 restricts the solicitation of sales of “penny stocks” by broker-dealers unless the broker first (i) obtains from the purchaser information concerning his or her financial situation, investment experience, and investment objectives, (ii) reasonably determines that the purchaser has sufficient knowledge and experience in financial matters that the person is capable of evaluating the risks of investing in “penny stocks,” and (iii) delivers and receives back from the purchaser a manually signed written statement acknowledging the purchaser’s investment experience and financial sophistication.

Rules 15g-2 through 15g-6 promulgated under the Exchange Act require broker-dealers who engage in transactions in “penny stocks” first to provide their customers with a series of disclosures and documents, including (i) a standardized risk disclosure document identifying the risks inherent in investing in “penny stocks,” (ii) all compensation received by the broker-dealer in connection with the transaction, (iii) current quotation prices and other relevant market data, and (iv) monthly account statements reflecting the fair market value of the securities.

Any broker-dealer that initiates quotations for the Royalty Trust units might not continue to do so, and the loss of any such broker-dealer likely would have a material adverse effect on the market price of the Royalty Trust units.

FINRA sales practice requirements may also limit a Royalty Trust unitholder’s ability to buy and sell royalty trust units.

In addition to the “penny stock” rules described below, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives, and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low-priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy royalty trust units, which may limit Royalty Trust unitholders’ ability to buy and sell Royalty Trust units and have an adverse effect on the market for Royalty Trust units.

Because the Royalty Trust units are deemed a low-priced “penny stock,” it will be cumbersome for brokers and dealers to trade in the Royalty Trust units, making the market for the Royalty Trust units less liquid and negatively affecting the price of the Royalty Trust units. The Royalty Trust will be subject to certain provisions of the Exchange Act, commonly referred to as the “penny stock” rules as defined in Rule 3a51-1. A penny stock is generally defined to be any equity security that has a market price less than $5.00 per share, subject to certain exceptions. Since the Royalty Trust units are deemed to be a penny stock, trading is subject to additional sales practice requirements of broker-dealers. These require a broker-dealer to:

● Deliver to the customer, and obtain a written receipt for, a disclosure document; ~~● Disclose certain price information about the stock;~~

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● Disclose certain price information about the stock; ● Disclose the amount of compensation received by the broker-dealer or any associated person of the broker-dealer; ● Send monthly statements to customers with market and price information about the penny stock; and ● In some circumstances, approve the purchaser’s account under certain standards and deliver written statements to the customer with the information specified in the rules.

Consequently, penny stock rules and FINRA rules may restrict the ability or willingness of broker-dealers to trade and/or maintain a market in the Royalty Trust units. Also, prospective investors may not want to get involved with the additional administrative requirements, which may have a material adverse effect on the trading of the Royalty Trust units.

Risks Related to the Royalty Trust Structure

The Royalty Trust is dependent on HOGA for funding unless royalty income from production on the onshore Highlander subject interest is sufficient to cover the Royalty Trust’s administrative expenses.

Pursuant to the Royalty Trust Agreement, the Depositor has agreed to pay annual trust expenses up to a maximum amount of $350,000, with no right of repayment or interest due, to the extent the Royalty Trust lacks sufficient funds to pay administrative expenses. OnPursuant ~~February~~to 1this provision, ~~2024~~HOGA contributed $200, ~~pursuant~~750 toon ~~this~~April ~~provision~~4, ~~FCX~~2025 ~~contributed~~and ~~approximately~~$149,250 on May 16, 2025, together representing the maximum contribution of $~~166~~350,000 for the payment of trust expenses incurred during the year ended December 31, ~~2023~~2025. On February 1, ~~and~~2024, FCX contributed the maximum of $350,000 for the payment of trust expenses incurred during the year ended December 31, 2024. In addition to such annual contributions, the Depositor has agreed to lend money, on an unsecured, interest-free basis, to the Royalty Trust to fund the Royalty Trust’s ordinary administrative expenses as set forth in the Royalty Trust Agreement. All funds the Trustee borrows to cover expenses or liabilities, whether from the Depositor or from any other source, must be repaid before the Royalty Trust unitholders will receive any distributions. HOGA ~~FCX~~ loaned the Royalty Trust $~~200~~216,~~000~~489 during the year ended December 31, ~~2024~~2025. NoFCX ~~loans~~loaned ~~or repayments~~the ~~were~~Royalty ~~made~~Trust $200,000 during the year ended December 31, ~~2023~~2024. Pursuant to the Assignment, as of December 31, 2024, FCX assigned to HOGA the promissory note relating to the outstanding loan to the Royalty Trust. As of December 31, 2025, the outstanding note payable to HOGA was $416,489. To the extent annual trust expenses exceed $350,000, the Royalty Trust may be required to borrow funds from HOGA in the future.

Pursuant to the Royalty Trust Agreement, the Depositor also agreed to provide and maintain a $1.0 million stand-by reserve account or an equivalent letter of credit for the benefit of the Royalty Trust to enable the Trustee to draw on such reserve account or letter of credit to pay obligations of the Royalty Trust if its funds are inadequate to pay its obligations at any time. Currently, with the consent of the Trustee, HOGA may reduce the reserve account or substitute a letter of credit with a different face amount for the original letter of credit or any substitute letter of credit. In connection with this arrangement, FCX provided $1.0 million in the form of a reserve fund cash account to the Royalty Trust. As of December 31, ~~2024~~2025, the Royalty Trust had used $151,632 from the reserve account, and the Depositor had not requested a reduction of such reserve account. Effective December 31, 2024, pursuant to the Assignment, FCX assigned its right, title and interest in the stand-by reserve account to HOGA, and HOGA assumed the responsibility to maintain the stand-by reserve account from FCX.

HOGA is a substantially smaller entity than FCX and does not have the same financial resources as FCX. Additionally, if any material adverse change in HOGA’s financial condition or results of operations causes HOGA to be unable to fund the exploration and development of the onshore Highlander subject interest, or if for any other reason sufficient production from the onshore Highlander subject interest is not reestablished and maintained in commercial quantities, Royalty Trust unitholders will not realize any additional value from their investment in the Royalty Trust units.

HOGA’s interests and the interests of the Royalty Trust unitholders may not always be aligned.

HOGA’s interests and the interests of the Royalty Trust unitholders are not completely aligned. For example, in setting budgets for development and production expenditures for HOGA’s properties, including the onshore Highlander subject interest, HOGA may make decisions that could adversely affect future production from the onshore Highlander subject interest, including a decision not to drill another well on the onshore Highlander subject interest.

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HOGA may at any time transfer all or part of the onshore Highlander subject interest and will not have control or influence over the activities related to the subject interests it does not operate.

On February 5, 2019, McMoRan completed the sale of all of its rights, title and interest in and to the onshore Highlander subject interest pursuant to a purchase and sale agreement with HOGA. The onshore Highlander subject interest was sold subject to the overriding royalty interest in future production held by the Royalty Trust. As a result of the Highlander Sale, HOGA has a 72 percent working interest and an approximate 48 percent net revenue interest in the onshore Highlander subject interest. The Royalty Trust continues to hold a 3.6 percent overriding royalty interest in the onshore Highlander subject interest. HOGA is the operator of the Highlander subject interest. The onshore Highlander subject interest is the only subject interest in which HOGA has an interest, as McMoRan previously had relinquished, allowed to expire or sold all of the other subject interests.

HOGA may at any time transfer all or part of the onshore Highlander subject interest. The Royalty Trust unitholders are not entitled to vote on any transfer, and the Royalty Trust will not receive any proceeds from the transfer of the subject interest. Following any such transfer, the onshore Highlander subject interest would continue to be subject to the overriding royalty interests, but the net proceeds from the transferred subject interests would be calculated separately and paid by the transferee. Unless HOGA and the transferee agree otherwise, the transferee would be responsible for all of HOGA’s obligations relating to the overriding royalty interests on the subject interest transferred, and HOGA would have no continuing obligation to the Royalty Trust for the subject interest. Any purchaser could have a weaker financial position and/or be less experienced in natural gas development and production than HOGA.

The Royalty Trust is limited in duration, may be dissolved upon certain events and the Royalty Trust units are subject to call features.

The Royalty Trust will dissolve on the earliest to occur of (i) June 3, 2033, (ii) the sale of all of the overriding royalty interests, (iii) the election of the Trustee following its resignation for cause (as more fully described in the Royalty Trust Agreement), (iv) a vote of the holders of 66⅔% or more of the outstanding Royalty Trust units held by persons other than FCX, any of its affiliates, or HOGA, at a duly called meeting of the Royalty Trust unitholders at which a quorum is present, or (v) the exercise by HOGA of the right to call all of the Royalty Trust units as described in the next paragraph. The overriding royalty interests terminate upon the termination of the Royalty Trust, other than in certain limited circumstances where the Royalty Trust has been permitted to transfer the overriding royalty interests to a third party pursuant to the terms of the Royalty Trust Agreement (in which case the overriding royalty interests may extend through June 3, 2033).

HOGA has a call right with respect to the outstanding Royalty Trust units at $10 per Royalty Trust unit. In addition, if the Royalty Trust units are then listed for trading or admitted for quotation on a national securities exchange or any quotation system and the volume-weighted average price per Royalty Trust unit is equal to $0.25 or less for the immediately preceding consecutive nine-month period, HOGA may purchase all, but not less than all, of the outstanding Royalty Trust units at a price of $0.25 per Royalty Trust unit so long as HOGA tenders payment within 30 days following the end of such nine-month period.

The Royalty Trust is passive in nature and neither the Royalty Trust nor the Royalty Trust unitholders have any ability to influence HOGA or to control the development or operation of the onshore Highlander subject interest.

The Royalty Trust units are a passive investment that entitle the Royalty Trust unitholders only to receive cash distributions, if any, from the overriding royalty interests. Royalty Trust unitholders have no voting rights with respect to HOGA and, therefore, have no managerial, contractual or other ability to influence HOGA’s activities or the development or operations of the onshore Highlander subject interest. Additionally, HOGA is not under any obligation to fund or to commit any resources to the exploration or development of the onshore Highlander subject interest.

HOGA or FCX may sell Royalty Trust units in the public or private markets, and any such sales may have a material adverse effect on the trading price of the Royalty Trust units.

At December 31, ~~2024~~2025, the Royalty Trust had 230,172,696 Royalty Trust units outstanding. In connection with the Highlander Sale on February 5, 2019, McMoRan assigned 31,143,150 Royalty Trust units to HOGA and retained 31,143,149 Royalty Trust units. HOGA and FCX each hold 13.5% of the outstanding Royalty Trust units. HOGA or FCX may sell Royalty Trust units in the public or private markets. Any such sales may have a material adverse effect on the trading price of the Royalty Trust units. A small number of other Royalty Trust unitholders also hold significant percentages of the outstanding Royalty Trust units, and sales by such holders also may have a material adverse effect on the trading price of the Royalty Trust units. See Part III, Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Royalty Trust Unitholder Matters” of this Form 10-K.

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The Royalty Trust is managed by a Trustee who cannot be replaced except by a majority vote of the Royalty Trust unitholders, which may make it difficult for Royalty Trust unitholders to remove or replace the Trustee.

The affairs of the Royalty Trust are managed by the Trustee. The voting rights of Royalty Trust unitholders are more limited than those of stockholders of most public corporations. For example, there is no requirement for the Royalty Trust to hold annual meetings of Royalty Trust unitholders or for an annual or other periodic re-election of the Trustee. The Royalty Trust does not intend to hold annual meetings of Royalty Trust unitholders. The Royalty Trust Agreement provides that the Trustee may only be removed by the affirmative vote of holders of a majority of the Royalty Trust units outstanding. As a result, it would be difficult for public Royalty Trust unitholders to remove or replace the Trustee without the cooperation of FCX and HOGA so long as each holds a significant percentage of the total Royalty Trust units.

Financial information of the Royalty Trust is not prepared in accordance with GAAP.

The financial statements of the Royalty Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Royalty Trust differ from GAAP financial statements because revenues are not accrued in the month of production and cash reserves may be established for specified contingencies and deducted which could not be accrued in GAAP financial statements.

The Royalty Trust is a smaller reporting company and benefits from certain reduced governance and disclosure requirements, including that the Royalty Trust’s independent registered public accounting firm is not required to, nor were they engaged to, attest to the effectiveness of the Royalty Trust’s internal control over financial reporting. The Royalty Trust cannot be certain if the omission of reduced disclosure requirements applicable to smaller reporting companies will make the Royalty Trust units less attractive to investors.

Currently, the Royalty Trust is a “smaller reporting company,” meaning that the outstanding Royalty Trust units held by nonaffiliates had a value of less than $250 million at the end of the Royalty Trust’s most recently completed second fiscal quarter. As a smaller reporting company, the Royalty Trust is not required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, meaning the Royalty Trust’s auditors are not required to attest to the effectiveness of the Trust’s internal control over financial reporting. As a result, investors and others may be less comfortable with the effectiveness of the Royalty Trust’s internal controls and the risk that material weaknesses or other deficiencies in internal controls go undetected may increase. In addition, as a smaller reporting company, the Royalty Trust takes advantage of its ability to provide certain other less comprehensive disclosures in its SEC filings, including, among other things, providing only two years of audited financial statements in annual reports. Consequently, it may be more challenging for investors to analyze the Royalty Trust’s results of operations and financial prospects, as the information the Royalty Trust provides to Royalty Trust unitholders may be different from what one might receive from other public companies in which one holds shares. As a smaller reporting company, the Royalty Trust is not required to provide this information.

Risks Related to Cybersecurity

Cybersecurity incidents or other failures in telecommunications or information technology systems could result in information theft, data corruption and significant disruption of the respective operations of the Trustee and HOGA as they relate to the Royalty Trust.

Each of the Trustee and HOGA depend heavily upon information technology systems and networks in connection with their respective business activities as they relate to the Royalty Trust. Despite any security measures implemented, events such as the loss or theft of back-up tapes or other data storage media could occur, and computer systems could be subject to physical and electronic break-ins, cyber-attacks and similar disruptions from unauthorized tampering, including threats that may come from external factors, such as governments, organized crime, hackers and third parties to whom certain functions are outsourced, or may originate internally from within the respective companies. This risk is exacerbated with the advancement of technologies like artificial intelligence, which malicious third parties are using to create new, sophisticated and more frequent attacks. Furthermore, geopolitical tensions or conflicts, such as the ongoing wars in Ukraine and the Persian Gulf, may further heighten the risk of cybersecurity attacks.

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If a cybersecurity incident were to occur, it could potentially jeopardize the confidential, proprietary and other information processed and stored in, and transmitted through, the computer systems and networks of the respective companies, or otherwise cause interruptions or malfunctions in the operations of the Royalty Trust, which could result in litigation, increased costs and regulatory penalties. Despite any steps taken by the respective companies to prevent and detect such attacks, it is possible that a cyber incident will not be discovered for some time after it occurs, which could increase exposure to these consequences.

Risks Related to Taxes

The tax treatment of the Royalty Trust units is uncertain.

Although the tax treatment of overriding royalty interests in specified developed wells that have been drilled is well developed, the law is less developed in the area of overriding royalty interests on exploration prospects that are not classified as having proved, probable or possible reserves and have potential well locations that may be drilled in the future. As a result, there is uncertainty as to the proper tax treatment of the overriding royalty interests held by the Royalty Trust, and counsel is unable to express any opinion as to the proper tax treatment as either a mineral royalty interest or a production payment. Based on the state of facts on the date on which this Form 10-K was filed, the Royalty Trust continues to treat the Royalty Trust units as mineral royalty interests for U.S. federal income tax purposes. However, no ruling has been requested from the IRS regarding the proper treatment of the Royalty Trust units; therefore, the IRS may assert, or a court may sustain the IRS in asserting, that the Royalty Trust units should be treated as “production payments” that are debt instruments for U.S. federal income tax purposes subject to the Treasury Regulations applicable to contingent payment debt instruments.

The Royalty Trust has not requested a ruling from the IRS regarding the tax treatment of ownership of the Royalty Trust units. If the IRS were to determine (and be sustained in that determination) that the Royalty Trust is not a “grantor trust” for federal income tax purposes, or that the overriding royalty interests are not properly treated as mineral royalty interests for U.S. federal income tax purposes, the Royalty Trust unitholders may receive different and potentially less advantageous tax treatment.

If the Royalty Trust were not treated as a grantor trust for U.S. federal income tax purposes, the Royalty Trust should be treated as a partnership for such purposes. Although the Royalty Trust would not become subject to U.S. federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Royalty Trust unitholders, the Royalty Trust’s tax reporting requirements would be more complex and costlier to implement and maintain, and any distributions to Royalty Trust unitholders could be reduced as a result.

If the Royalty Trust were treated for U.S. federal income tax purposes as a partnership, it likely would be subject to the procedures for auditing large partnerships as well as the procedures for assessing and collecting income taxes due (including applicable penalties and interest) as a result of an audit. These rules effectively would impose an entity level tax on the Royalty Trust, and Royalty Trust unitholders may have to bear the expense of the adjustment even if they were not Royalty Trust unitholders during the audited taxable year.

If the overriding royalty interests were not treated as a mineral royalty interest, the amount, timing and character of income, gain, or loss in respect of an investment in the Royalty Trust could be affected.

The Royalty Trust has not requested a ruling from the IRS regarding these tax questions. The IRS could challenge these positions on audit, and such challenges could be sustained by a court.

The availability and extent of percentage depletion deductions to the Royalty Trust unitholders for any taxable year is uncertain.

Payments out of production that are received by a Royalty Trust unitholder in respect of a mineral royalty interest for U.S. federal income tax purposes are taxable under current law as ordinary income subject to an allowance for cost or percentage depletion in respect of such income. The rules with respect to this depletion allowance are complex and must be computed separately by each Royalty Trust unitholder and not by the Royalty Trust for each natural gas property. As a result, the availability or extent of percentage depletion deductions to the Royalty Trust unitholders for any taxable year is uncertain.

The Royalty Trust encourages Royalty Trust unitholders to consult their own tax advisors to determine whether and to what extent percentage depletion would be available to them for both U.S. federal income tax and state income tax purposes.

Royalty Trust unitholders will be required to pay taxes on their pro-rata share of the taxable income attributable to the assets of the Royalty Trust even if they do not receive any cash distributions from the Royalty Trust.

Because the holders of Royalty Trust units will be taxed directly on their pro-rata share of the taxable income attributable to the assets of the Royalty Trust and such taxable income could be different in amount than the cash the Royalty Trust distributes, Royalty Trust unitholders will be required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on such taxable income even if they receive no cash distributions from the Royalty Trust. Royalty Trust unitholders may not receive cash distributions from the Royalty Trust equal to their pro-rata share of the taxable income attributable to the assets of the Royalty Trust or even equal to the actual tax liability that results from that income.

As a consequence of special reporting rules, Royalty Trust unitholders may not be able to recognize income/claim losses realized by the Royalty Trust until the unitholders dispose of Royalty Trust units.

If the Royalty Trust satisfies the general de minimis test prescribed by the IRS and elects to report using the de minimis test, the Royalty Trust will only be required to report, with respect to sales or dispositions of trust assets, the amount of sales proceeds distributed to a Royalty Trust unitholder during the year. Reporting under the de minimis exception will leave unitholders with inadequate information to be able to fully report the result of the sales and dispositions falling under the de minimis threshold in a given year. The reason for the de minimis exception is that the IRS and the Treasury Department believe that if a widely held fixed investment trust such as the Royalty Trust sells or disposes of assets infrequently, although there may be some deferral of gains and losses if sales and dispositions are not fully reported, the deferral is acceptable, in light of the burden of fully and accurately reporting the sales and dispositions.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

The Royalty Trust has no directors or executive officers. The affairs of the Royalty Trust are managed by the Trustee. The Royalty Trust falls under the cybersecurity program of The Bank of New York Mellon Corporation (BNY Mellon), the parent corporation of The Bank of New York Mellon Trust Company, N.A. As further described in its ~~2024~~2025 Annual Report, BNY Mellon maintains a broad range of defenses aimed at remaining abreast of and responding to evolving cybersecurity threats impacting it, its operations, its clients, its third-party service providers and the broader financial services sector.

Risk Management Strategy and Procedures

BNY Mellon has implemented policies and procedures designed to detect, prevent and respond to malicious and accidental disruptions to the delivery of critical technology services. BNY Mellon’s cybersecurity risk management program is embedded in its three lines of defense model.

As part of its first line of defense, BNY Mellon maintains a dedicated ~~Information~~Cybersecurity ~~Security Division (ISD)~~organization, led by the Chief Information ~~Security~~ Security Officer (the CISO), that is responsible for the day-to-day management of risks from cybersecurity threats. ~~ISD~~Cybersecurity’s responsibilities include cybersecurity threat intelligence, incident response and other cybersecurity operations aimed at enabling BNY Mellon to identify, assess and manage existing and emerging cybersecurity threats. ~~ISD~~Cybersecurity monitors for potential threats and communicates relevant risks to the CISO and other members of executive management. Additionally, ~~ISD~~Cybersecurity maintains a cybersecurity incident response and reporting process pursuant to which cybersecurity incidents are classified according to their severity based upon an assessment of multiple factors. Certain cybersecurity incidents may activate enterprise-wide resiliency processes, which include, among other things, escalation through the management and Board committee structures described below. In addition, BNY Mellon maintains a preparedness program designed to reinforce cybersecurity risk management practices and compliance with BNY Mellon’s policies and procedures. The preparedness program includes mandatory training for all employees, contractors and consultants, enhanced training for those in roles presenting higher risk, calibrated phishing email simulations, distribution of information security awareness materials and cybersecurity event simulation exercises. In addition, BNY Mellon leverages both internal and external assessments and engages with third-party assessors, consultants and auditors to evaluate and test its cybersecurity controls and provide guidance on potential improvements, including design and operating effectiveness. BNY Mellon’s ~~has~~information ~~standing~~security ~~arrangements~~management ~~with~~system ~~third~~is ~~parties~~certified to ~~assist~~the ~~BNY~~ISO ~~Mellon~~27001 instandard ~~identifying,~~by ~~assessing~~an ~~and managing cybersecurity threats~~independent, accredited ~~including~~certification ~~in connection with risk assessments~~body, ~~penetration~~and ~~testing,~~BNY ~~legal~~Mellon ~~advice~~maintains ~~and~~this ~~other~~certification ~~aspects~~through ofperiodic ~~BNY~~external ~~Mellon’s~~audits ~~cybersecurity risk management~~ and ~~incident~~ongoing ~~response processes~~monitoring.

BNY Mellon has a defined third-party governance framework to help manage the risk posed to it by the use of third-party service providers. BNY Mellon evaluates the risk posed by third-party service engagements based on multiple factors. BNY Mellon has protocols that seek to mitigate cybersecurity risks associated with third-party service providers based on the risk level assigned to such third party, which may include mandatory contractual obligations or the implementation of additional controls by BNY Mellon and/or the applicable service provider.

~~ISD~~Cybersecurity is subject to ongoing review and challenge from Technology Risk Management, which is a part of the independent second line of defense risk function. Technology Risk Management, together with the broader Risk & Compliance group, is responsible for and manages BNY Mellon’s risk management framework and establishes guidance for ~~ISD~~Cybersecurity and management designed to help identify, assess and manage cybersecurity risk.

BNY Mellon’s Internal Audit function serves as the third line of defense and provides an independent view on how effectively the organization as a whole manages cybersecurity risk.

Risk Management Oversight and Governance

BNY Mellon’s management is responsible for assessing and managing BNY Mellon’s material risks from cybersecurity threats with oversight provided by its Board of Directors (the “Board”) and the Board committees. The Risk Committee of the Board has primary responsibility for oversight of the overall operation of BNY Mellon’s risk management framework, including policies and practices addressing cybersecurity risk, and is responsible for the oversight of the second line of defense with respect to its cybersecurity risk management responsibilities. The Technology Committee of the Board and the full Board regularly receive reports and briefings from management concerning cybersecurity matters, including any significant changes to BNY Mellon’s cybersecurity program. BNY Mellon also has protocols for escalating cybersecurity threats and incidents to the Technology Committee of the Board and the full Board. In addition, the Audit Committee of the Board monitors and oversees the performance of Internal Audit, including with respect to its cybersecurity risk management responsibilities.

29At the management level, BNY Mellon’s Technology Oversight Committee, which is the senior management committee responsible for the governance and oversight of BNY Mellon’s significant technology projects and initiatives, reviews reports from management concerning Cybersecurity and is responsible for, among other things, escalating issues, including significant cybersecurity threats and incidents, to the Technology Committee of the Board and the full Board of Directors. The Technology Oversight Committee is chaired by the Chief Information Officer and Global Head of Engineering (the CIO).

~~At the management level,~~ BNY Mellon’s Technology ~~Oversight~~Risk Committee, ~~which~~ is the most senior ~~management~~governance committee ~~responsible~~primarily ~~for~~focused ~~the governance~~on cybersecurity and ~~oversight~~technology ofrisk issues ~~BNY~~and ~~Mellon’s~~is ~~significant~~a ~~technology~~part ~~projects~~of ~~and~~the ~~initiatives,~~second ~~reviews~~line ~~reports~~of ~~from~~defense ~~management~~risk ~~concerning ISD~~function. ~~and~~It is responsible for, among other things, ~~escalating~~overseeing ~~issues,~~and ~~including~~reviewing emerging cybersecurity risks, significant cybersecurity ~~threats~~incidents and ~~incidents,~~remediation plans. The Technology Risk Committee receives reports from management and has protocols for escalating certain issues and risks to the ~~Technology~~ Enterprise Risk Committee ofand the Risk Committee of the Board. The Technology ~~Oversight~~Risk Committee is chaired by the Chief ~~Information~~Technology Risk Officer. ~~(the~~Members ~~CIO)~~include ~~and~~key ~~its~~leaders ~~members~~from the first ~~include~~line of defense, including the CISO.

BNY Mellon’s CIO, CISO and Chief Technology Risk ~~Committee~~Officer iseach ~~the~~have ~~most~~extensive ~~senior~~experience ~~governance~~in ~~committee~~assessing ~~primarily~~and ~~focused~~managing onrisks from cybersecurity threats. ~~and~~BNY ~~technology~~Mellon’s ~~risk issues~~CIO ~~and~~joined isBNY Mellon in 2024 from a ~~part~~large ofmultinational ~~the~~company, ~~second~~where ~~line~~she ofwas ~~defense~~responsible ~~risk~~for ~~function~~overseeing information technology and cybersecurity operations. ItBNY isMellon’s ~~responsible~~CISO ~~for,~~joined ~~among~~BNY ~~other~~Mellon ~~things,~~in ~~overseeing~~2025 and ~~reviewing~~previously led the global ~~emerging~~assurance function for cybersecurity ~~risks,~~and ~~significant~~technology ~~cybersecurity~~controls ~~incidents~~at ~~and~~a ~~remediation~~global ~~plans~~systemically important financial institution. ~~The~~BNY Mellon’s Chief Technology Risk ~~Committee~~Officer ~~receives~~joined ~~reports from~~BNY ~~management~~Mellon in 2024 and has ~~protocols~~previous ~~for~~experience ~~escalating~~as ~~certain~~Global ~~issues~~Head ~~and~~of ~~risks~~Cyber, toTechnology ~~the~~and ~~Senior~~Information Security Risk ~~and~~Management ~~Control~~at ~~Committee~~a global systemically important financial institution and over a decade of experience serving the ~~Risk~~U.S. ~~Committee~~Intelligence community in a variety of ~~the~~cybersecurity-related ~~Board~~positions. ~~The~~BNY ~~Technology~~Mellon ~~Risk~~believes ~~Committee~~that isrefreshing ~~chaired~~leadership byin the ~~interim~~CIO, ~~Chief~~CISO and Chief Technology Risk Officer. ~~Members~~roles ~~include~~brings ~~key~~new ~~leaders~~perspectives ~~from the~~and ~~first~~specialized ~~line~~expertise ofto ~~defense~~enhance cybersecurity practices, ~~including~~while ~~the~~continuity is ~~CISO~~safeguarded through disciplined succession and transition planning.

BNY Mellon’s CIO, CISO and interim Chief Technology Risk Officer each have extensive experience in assessing and managing risks from cybersecurity threats. BNY Mellon’s CISO joined BNY Mellon in 2022 and previously served as head of information security at a Fortune 500 biopharmaceutical company and an information technology company, as well as the Global Chief Technology Officer at a large cybersecurity company. BNY Mellon’s CIO joined BNY Mellon in September 2024 from a large multinational company, where she was responsible for overseeing information technology and cybersecurity operations. BNY Mellon’s interim Chief Technology Risk Officer joined BNY Mellon in November 2024 and has previous experience as Global Head of Cyber, Technology and Information Security Risk Management at a global systemically important financial institution and over a decade of experience serving the U.S. intelligence community in a variety of cybersecurity-related positions.

Item 3. Legal Proceedings

There are currently no pending legal proceedings to which the Royalty Trust is a party.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Royalty Trust Units, Related Royalty Trust Unitholder Matters and Issuer Purchases of Royalty Trust Units

The Royalty Trust units ~~are~~have been quoted on the OTCID Basic Market (OTCID), operated by OTC ~~Pink~~Markets ~~tier~~Group ofInc., ~~the~~since ~~over-the-counter~~July 1, or2025, having previously been quoted on the OTC Pink Market (OTC Pink), ~~markets~~in each case under the symbol “GULTU.” For information regarding the ~~OTC~~OTCID ~~Pink~~ and fluctuations in the market price and trading volume of the Royalty Trust units, see Part I, Item 1A. “Risk Factors – There is a limited public market for the Royalty Trust units, which could affect the market price, trading volume, liquidity and resale price of the Royalty Trust units” of this Form 10-K.

The following table shows the high and low sales/bid prices, as applicable, per Royalty Trust unit as reported on the OTC Pink for ~~the~~2024 ~~periods~~and ~~indicated~~the first two quarters of 2025, and as reported on the OTCID for the final two quarters of 2025. Quotations on the OTC Pink and the OTCID reflect bid and ask quotations, may reflect inter-dealer prices, without retail markup, markdown or commission, and may not represent actual transactions.

	2024				2023
	2025				2024
	High		Low		High		Low
First Quarter	$	0.0103	$	0.0102	$	0.0501	$	0.01
Second Quarter		0.0203		0.0102		0.02		0.01
Third Quarter		0.0204		0.0103		0.02		0.01
Fourth Quarter	$	0.04	$	0.0103	$	0.0204	$	0.01

As of March 2520, ~~2025~~2026, ~~there~~the ~~were~~ 230,172,696 Royalty Trust units outstanding ~~and~~were 4held by 3,~~260~~873 Royalty Trust unitholders of record.

Recent Sales of Unregistered Securities and Royalty Trust Unitholder Matters

There were no equity securities sold by the Royalty Trust during the year ended December 31, ~~2024~~2025. At December 31, ~~2024~~2025, the Royalty Trust had 230,172,696 Royalty Trust units outstanding.

Securities Authorized for Issuance Under Equity Compensation Plans

None.

Purchases of Royalty Trust Units by the Issuer and Affiliated Purchasers

None.

Item 6. [Reserved]

Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

You should read the following discussion in conjunction with Part II, Item 8. “Financial Statements and Supplementary Data” and Part I, Items 1. and 2. “Business and Properties” of this Form 10-K. The results of operations reported and summarized below are not necessarily indicative of future operating results. Unless otherwise specified, all references to “Notes” refer to Notes to Financial Statements located in Part II, Item 8. “Financial Statements and Supplementary Data” of this Form 10-K. A glossary of definitions for some of the oil and gas industry terms used in this Form 10-K is provided beginning on page 2. Additionally, please refer to the section above entitled “Forward-Looking Statements” in this Form 10-K. The information below has been furnished to the Trustee by Highlander Oil & Gas Assets LLC (HOGA). In this Form 10-K, the “Depositor” refers to Freeport-McMoRan Inc. (FCX), for all periods ending prior to the Effective Date (defined below), and to HOGA, for all periods beginning on and after the Effective Date; and the “Grantor” refers to McMoRan Oil & Gas LLC (McMoRan), for all periods ending prior to the Effective Date, and to HOGA, for all periods beginning on and after the Effective Date.

Business Overview

On June 3, 2013, FCX and McMoRan Exploration Co. (MMR) completed the transactions contemplated by the Agreement and Plan of Merger, dated as of December 5, 2012 (the merger agreement), by and among MMR, FCX, and INAVN Corp., a Delaware corporation and indirect wholly owned subsidiary of FCX (Merger Sub). Pursuant to the merger agreement, Merger Sub merged with and into MMR, with MMR surviving the merger as an indirect wholly owned subsidiary of FCX (the merger).

FCX’s oil and gas assets are held through its wholly owned subsidiary, FCX Oil & Gas LLC (FM O&G). As a result of the merger, MMR and McMoRan are both indirect wholly owned subsidiaries of FM O&G.

In connection with the merger, on June 3, 2013, (1) FCX, as depositor, McMoRan, as grantor, the Trustee and the Delaware Trustee entered into the amended and restated royalty trust agreement to govern the Royalty Trust and the respective rights and obligations of FCX, the Trustee, the Delaware Trustee, and the Royalty Trust unitholders with respect to the Royalty Trust (the Royalty Trust Agreement); and (2) McMoRan, as grantor, and the Royalty Trust, as grantee, entered into the master conveyance of overriding royalty interests (the master conveyance) pursuant to which McMoRan conveyed to the Royalty Trust the overriding royalty interests in future production from the subject interests. Other than (a) its formation, (b) its receipt of contributions and loans from the Depositor for administrative and other expenses as provided for in the Royalty Trust Agreement, (c) its payment of such administrative and other expenses, (d) its repayment of loans from the Depositor, (e) its receipt of the conveyance of the overriding royalty interests from McMoRan pursuant to the master conveyance, (f) its receipt of royalties from McMoRan or HOGA, and (g) its cash distributions to Royalty Trust unitholders, if any, the Royalty Trust has not conducted any activities. The Trustee has no involvement with, control over, or responsibility for, any aspect of any operations on or relating to the subject interests.

On February 5, 2019, McMoRan completed the sale of all of its rights, title and interest in and to the onshore Highlander subject interest pursuant to a purchase and sale agreement with HOGA (the Highlander Sale). The onshore Highlander subject interest was sold subject to the overriding royalty interest in future production held by the Royalty Trust. As a result of the Highlander Sale, HOGA has a 72 percent working interest and an approximate 48 percent net revenue interest in the onshore Highlander subject interest. The Royalty Trust continues to hold a 3.6 percent overriding royalty interest in the onshore Highlander subject interest. HOGA is the operator of the Highlander subject interest. The onshore Highlander subject interest is the only subject interest in which HOGA has an interest, as McMoRan previously had relinquished, allowed to expire or sold all of the other subject interests.

The Royalty Trust has no ability to direct or influence the exploration or development of the onshore Highlander subject interest. In addition, HOGA is under no obligation to fund or to commit any other resources to the exploration or development of the onshore Highlander subject interest. To the extent that HOGA does not fund further exploration and development of the onshore Highlander subject interest, or if for any other reason sufficient production from the onshore Highlander subject interest is not maintained in commercial quantities, Royalty Trust unitholders will not realize any additional value from their investment in the Royalty Trust units.

The Royalty Trust units are quoted on the ~~OTC~~OTCID ~~Pink~~Basic ~~tier of the OTC markets~~Market. The ~~OTC~~OTCID ~~Pink~~Basic Market is a significantly more limited market than the ~~national~~ national securities exchanges, which could adversely affect the market price, trading volume, liquidity and resale price of the Royalty ~~Trust~~ Trust units.

For information regarding the ~~OTC~~OTCID ~~Pink~~Basic Market, see Part I, Item IA. “Risk Factors – There is a limited public market for the ~~Royalty~~ Royalty Trust units, which could affect the market price, trading volume and resale price of the Royalty Trust units” of this Form 10-K.

OPERATIONAL ACTIVITIES

Status of the Onshore Highlander Subject Interest

The onshore Highlander subject interest is the only subject interest that has established commercial production. Abandoning the well eliminated any production from the onshore Highlander subject interest, which also eliminated any proceeds to which the Royalty Trust would be entitled pursuant to its overriding royalty interests during the same period. Unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities, the Royalty Trust does not expect to receive any income attributable to its overriding royalty interests and accordingly, does not expect to have any cash available to distribute to Royalty Trust unitholders in future periods. HOGA previously informed the Trustee that a new well on the onshore Highlander subject interest was spudded on January 30, 2025 and recently reported that the well had reached total depth of 30,862 feet on February 17, 2026; however, the future production status of this well remains unknown. Neither the Trustee nor the Royalty Trust unitholders has any right to control or influence operations of the subject interest.

Oil and Gas Activities

For additional information regarding HOGA’s current oil and gas activities in relation to the onshore Highlander subject interest, see Part I, Items 1. and 2. “Business and Properties – The Subject Interests – Exploratory and Development Drilling” and Part I, Item 1A. “Risk Factors” of this Form 10-K.

Production

For information regarding HOGA’s production, see “Results of Operations” in this section of this Form 10-K.

Acreage Position

For information regarding HOGA’s acreage position, see Part I, Items 1. and 2. “Business and Properties – The Subject Interests – Acreage” of this Form 10-K.

RESULTS OF OPERATIONS

Royalty Income. The onshore Highlander subject interest began commercial production on February 25, 2015. Prior to this date there had been no commercial production of hydrocarbons from any of the subject interests. As there was no production in 2025 or 2024, the Royalty Trust ~~did~~ did not receive any royalties for the ~~year~~years ended December 31, ~~2024.~~2025 During the year ended December 31, 2023, the Royalty Trust received royalties of $401,278 from HOGA related to 101,352 Mcf of natural gas production attributable to the onshore Highlander subject interest with average post-production costs of $0.67 per Mcf and ~~an average receipt price of $4.63 per Mcf. Royalty income was lower during the year ended December 31,~~ 2024~~, as compared to the year ended December 31, 2023 due to the well being shut-in~~.

Administrative Expenses. For the years ended December 31, ~~2024~~2025 and ~~2023~~2024, the Royalty Trust paid administrative expenses of $~~899~~562,~~455~~618 and $~~469~~899,~~821~~455, respectively. Administrative expenses, which consisted primarily of audit, legal and trustee expenses incurred in connection with the administration of the Royalty Trust, were higher in 2024 compared to ~~2023~~2025 because ~~no administrative fees were paid in the~~ fourth quarter of 2023. ~~Fourth quarter 2023~~ administrative expenses were paid in the first quarter of 2024, when the Royalty Trust borrowed funds from FCX.

LIQUIDITY AND CAPITAL RESOURCES

Pursuant to the Royalty Trust Agreement, the Depositor also agreed to provide and maintain a $1.0 million stand-by reserve account or an equivalent letter of credit for the benefit of the Royalty Trust to enable the Trustee to draw on such reserve account or letter of credit to pay obligations of the Royalty Trust if its funds are inadequate to pay its obligations at any time. Currently, with the consent of the Trustee, HOGA may reduce the reserve account or substitute a letter of credit with a different face amount for the original letter of credit or any substitute letter of credit. In connection with this arrangement, FCX provided $1.0 million in the form of a reserve fund cash account to the Royalty Trust. As of December 31, ~~2024~~2025, the Royalty Trust had used $151,632 from the reserve account, and the Depositor had not requested a reduction of such reserve account. Effective December 31, 2024, pursuant to the Assignment, FCX assigned its right, title and interest in the stand-by reserve account to HOGA, and HOGA assumed the responsibility to maintain the stand-by reserve account from FCX.

In connection with the completion of the Highlander Sale, HOGA assumed all administrative and reporting responsibilities with respect to the Royalty Trust, including those described in Article III of the Royalty Trust Agreement.

Royalties are paid to the Royalty Trust on the last day of the month following the month in which production payments are received by the Grantor in accordance with the terms of the master conveyance. In accordance with the master conveyance. The Royalty Trust did not receive any royalties in 2025 and 2024, as the well was shut-in. ~~The Royalty Trust received royalties from HOGA of $401,278 during the year ended December 31, 2023 due to production from the onshore Highlander subject interest.~~

Royalties received by the Royalty Trust must first be used to (i) satisfy Royalty Trust administrative expenses and (ii) reduce Royalty Trust indebtedness. The Royalty Trust has an outstanding note payable to HOGA of $~~200~~416,~~000~~489 outstanding as of December 31, ~~2024~~2025. ~~The Royalty Trust had no indebtedness outstanding as of December 31, 2023.~~ As of December 31, ~~2024~~2025, the Trustee has established a minimum cash reserve of $302,500. As a result, distributions will be made to Royalty Trust unitholders only when royalties received less administrative expenses incurred and repayment of any indebtedness exceeds the minimum cash reserve.

Commencing with the distribution to Royalty Trust unitholders in the first quarter of 2022, the Royalty Trust withheld $8,750 from the funds otherwise available for distribution each quarter through the first quarter of 2023, with the intent of gradually building a cash reserve of approximately $350,000. As no proceeds have been available for distribution since the first quarter of 2023, the Royalty Trust has not withheld any funds for the cash reserve with respect to those periods. Unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities as discussed in “Operational Activities – Status of the Onshore Highlander Subject Interest” above, the Royalty Trust does not intend to withhold funds for the cash reserve as the Royalty Trust does not expect to have any cash available to distribute to Royalty Trust unitholders in future periods. This cash is reserved for the payment of future known, anticipated or contingent expenses or liabilities of the Royalty Trust. The Trustee may increase or decrease the targeted cash reserve amount at any time, and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the Royalty Trust unitholders. Cash held in reserve will be invested as required by the Royalty Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to Royalty Trust unitholders, together with interest earned on the funds.

There was no distributable income in ~~2024.~~2025 ~~Distributable~~and ~~income totaled $197,331 for the year ended December 31, 2023~~2024. ~~These distributions are not necessarily indicative of future distributions.~~ The Royalty Trust’s only other sources of liquidity are mandatory annual contributions, any loans and the required standby reserve account or letter of credit from HOGA. As a result, any material adverse change in HOGA’s financial condition or results of operations could materially and adversely affect the Royalty Trust and the underlying Royalty Trust units. See Part I, Item 1A. “Risk Factors” of this Form 10-K for more information.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The financial statements of the Royalty Trust are prepared on the modified cash basis of accounting and are not intended to present the Royalty Trust’s financial position and results of operations in conformity with GAAP. This other comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the SEC.

The carrying value of the Royalty Trust’s overriding royalty interests in the subject interests (defined in Note 2 in the Notes to Financial Statements located in Part II, Item 8. “Financial Statements and Supplementary Data” of this Form 10-K) is amortized using the units of production method based on estimated proved reserves, on an individual subject interest basis, once production has been achieved for the respective subject interests. Such non-cash amortization is charged directly to the Trust Corpus as royalties are received, and does not affect distributable cash or the determination of distributable cash per Royalty Trust unit.

The Royalty Trust evaluates the carrying values of the overriding royalty interests in the subject interests for impairment if conditions indicate that potential uncertainty exists regarding the Royalty Trust’s ability to recover its recorded amounts related to the overriding royalty interests. Indications of potential impairment with respect to the overriding royalty interests can include, among other things, subject interest lease expirations, reductions in estimated reserve quantities or resource potential, changes in estimated future oil and gas prices, exploration costs, and/or drilling plans, and other matters that arise that could negatively impact the carrying values of the overriding royalty interests. If an impairment event occurs and it is determined that the carrying value of the Royalty Trust’s overriding royalty interests in the subject interests may not be recoverable, an impairment will be recognized as measured by the amount by which the carrying amount of the overriding royalty interests in the subject interests exceeds the fair value of these assets, which would be measured by discounting projected cash flows. The related impairment amounts are recorded as a reduction to the overriding royalty interests with an offsetting reduction to the Trust Corpus in the period such impairment is determined, see Note 3 in the Notes to Financial Statements located in Part II, Item 8. “Financial Statements and Supplementary Data” of this Form 10-K. The Royalty Trust fully impaired the carrying value of the onshore Highlander subject interest by $308,071 during the year ended December 31, 2023. Unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities, the Royalty Trust does not expect to receive any income attributable to its overriding royalty interests. Therefore, the Royalty Trust recognized the remaining carrying value of the onshore Highlander subject interest as of March 31, 2023 as an impairment loss.

NEW ACCOUNTING STANDARDS

The Royalty Trust does not expect recently issued accounting standards to have a significant impact on its future financial statements and disclosures.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

As a smaller reporting company as defined in Item 10(f) of Regulation S-K, the Royalty Trust is not required to provide the information required by this Item.

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TOTo ~~THE~~the ~~TRUSTEE~~Trustee ~~AND~~and ~~HOLDERS~~Unitholders ~~OF ROYALTY TRUST UNITS~~of

OFGulf ~~GULF~~Coast ~~COAST~~Ultra ~~ULTRA~~Deep ~~DEEP~~Royalty ~~ROYALTY TRUST:~~Trust

Opinion on the Financial Statements

We have audited the accompanying statement of assets, liabilities and trust corpus of Gulf Coast Ultra Deep Royalty Trust (the Trust) as of December 31, 2025 and 2024, and the related statements of distributable income and changes in trust corpus for the ~~year~~years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements ~~present~~ present fairly, in all material respects, the financial position of the Trust as of December 31, 2025 and 2024, and its distributable income and changes in trust corpus for the ~~year~~years then ended, in conformity with the modified cash basis of accounting, as described in Note 1, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

Basis of Accounting

As described in Note 1 of the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of The Bank of New York Mellon Trust Company, N.A., as the Trust’s trustee (the Trustee). Our responsibility is to express an opinion on the Trust’s financial statements based on our ~~audit~~audits. We are a public ~~accounting~~ accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our ~~audit~~audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our ~~audit~~audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion.

Our ~~audit~~audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our ~~audit~~audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

Critical Audit Matters

Critical audit matters are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the Trustee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.

/s/ ~~Weaver~~WEAVER ~~and~~AND ~~Tidwell~~TIDWELL, L.L.P.

Houston, Texas

March 2825, ~~2025~~2026

We have served as the Trust’s auditor since 2024.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE TRUSTEE AND HOLDERS OF ROYALTY TRUST UNITS

OF GULF COAST ULTRA DEEP ROYALTY TRUST:

Opinion on the Financial Statements

We have audited the accompanying statement of assets, liabilities and trust corpus of Gulf Coast Ultra Deep Royalty Trust (the Royalty Trust) as of December 31, 2023, the related statements of distributable income and changes in trust corpus for the year ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Royalty Trust at December 31, 2023, and the distributable income for the year ended December 31, 2023, in conformity with modified cash basis of accounting described in Note 1.

Basis of Accounting

As described in Note 1, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles.

Basis for Opinion

These financial statements are the responsibility of The Bank of New York Mellon Trust Company, N.A., as the Royalty Trust’s trustee (the Trustee). Our responsibility is to express an opinion on the Royalty Trust’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Royalty Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Royalty Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Royalty Trust’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audit provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We served as the Royalty Trust’s auditor from 2013 to 2024.

Fort Worth, Texas

March 28, 2024

GULF COAST ULTRA DEEP ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	December 31,			December 31,
	2024			2023
	2025			2024
ASSETS
Operating cash	$	1520,~~571~~419		$	4315,~~741~~571
Reserve fund cash and short-term investments		1,~~020~~063,~~456~~137			1,~~116~~020,~~460~~456
Total assets	$	1,~~036~~083,~~027~~556		$	1,~~160~~036,~~201~~027
LIABILITIES AND TRUST CORPUS
Reserve fund liability	$	1,~~172~~214,~~088~~769		$	1,~~116~~172,~~460~~088
Note Payable to HOGA		~~200~~416,~~000~~489			—200,000
Trust corpus (230,172,696 royalty trust units authorized, issued and
Trust corpus (230,172,696 royalty trust units authorized, issued and outstanding as of December 31, 2025 and 2024)		(547,702	)		(336,061	)
outstanding as of December 31, 2024 and 2023)		(336,061	)		43,741
Total liabilities and trust corpus	$	1,083,556		$	1,036,027
Total liabilities and trust corpus	$	1,036,027		$	1,160,201

The accompanying notes are an integral part of these financial statements.

3837

GULF COAST ULTRA DEEP ROYALTY TRUST

STATEMENTS OF DISTRIBUTABLE INCOME

	Years Ended December 31,
	2024			2023
	2025			2024
Royalty income	$	-		$	401,278
Interest income and other	$	978		$	3,737
Interest income and other		3,737			15,866
Administrative expenses		(562,619	)		(899,455	)
Administrative expenses		(899,455	)		(469,821	)
Administrative expenses in excess of income	$	(561,641	)	$	(895,718	)
Administrative expenses in excess of income	$	(895,718	)	$	(52,677	)
Distributable income (Note 4)	$	—		$	—
Distributable income	$	-		$	197,331
Distributable income per royalty trust unit	$	-		$	0.000857
Royalty trust units outstanding at end of period		230,172,696			230,172,696

The accompanying notes are an integral part of these financial statements.

3938

GULF COAST ULTRA DEEP ROYALTY TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS

	Years Ended December 31,
	2024			2023
	2025			2024
Trust corpus, beginning of period	$	43(336,~~741~~061	)	$	143,~~245,494~~741
Trust Contributions		~~515~~350,~~916~~000			-515,916
Amortization of overriding royalty interests in subject interests		-			(21,780	)
Administrative expenses in excess of income		(561,641	)		(895,718	)
Impairment of subject interests		-			(308,071	)
Trust corpus, end of period	$	(547,702	)	$	(336,061	)
Administrative expenses in excess of income		(895,718	)		(52,677	)
Distributions paid		-			(819,225	)
Trust corpus, end of period	$	(336,061	)	$	43,741

The accompanying notes are an integral part of these financial statements.

4039

GULF COAST ULTRA DEEP ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

1 . SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The financial statements of Gulf Coast Ultra Deep Royalty Trust (the Royalty Trust) are prepared on the modified cash basis of accounting and are not intended to present the Royalty Trust’s financial position and results of operations in conformity with United States (U.S.) generally accepted accounting principles (GAAP). This other comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission (SEC), as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

The Royalty Trust’s operating cash and reserve fund cash amounts represent deposits in highly liquid short-term U.S. Treasury money market funds. The Royalty Trust’s reserve fund short-term investments include U.S. treasury securities with maturities of three months to one year and are recorded at cost in accordance with the modified cash basis of accounting.

The carrying value of the Royalty Trust’s overriding royalty interests in the subject interests (each defined in Note 2) is amortized using the units of production method based on estimated proved reserves, on an individual subject interest basis, once production has been achieved for the respective subject interests. Such non-cash amortization is charged directly to the Trust Corpus as royalties are received, and will not affect distributable cash or the determination of distributable cash per Royalty Trust unit, see Note 3.

The Royalty Trust evaluates the carrying values of the overriding royalty interests in the subject interests for impairment if conditions indicate that potential uncertainty exists regarding the Royalty Trust’s ability to recover its recorded amounts related to the overriding royalty interests. Indications of potential impairment with respect to the overriding royalty interests can include, among other things, subject interest lease expirations, reductions in estimated reserve quantities or resource potential, changes in estimated future oil and natural gas prices, exploration costs, and/or drilling plans, and other matters that arise that could negatively impact the carrying values of the overriding royalty interests. If an impairment event occurs and it is determined that the carrying value of the Royalty Trust’s overriding royalty interests in the subject interests may not be recoverable, an impairment will be recognized as measured by the amount by which the carrying amount of the overriding royalty interests in the subject interests exceeds the fair value of these assets, which would be measured by discounting projected cash flows. The related impairment amounts are recorded as a reduction to the overriding royalty interest with an offsetting reduction to the Trust Corpus in the period such impairment is determined. Fair value accounting guidance includes a hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3). When indicators of impairment are present and it is determined that the carrying value of the Royalty Trust’s overriding royalty interests in the subject interests exceeds the estimated undiscounted cash flows of the subject interest, fair value estimates utilized in the impairment assessment are generally determined based on inputs not observable in the market and thus represent Level 3 measurements.

2. FORMATION OF THE ROYALTY TRUST

On June 3, 2013, Freeport-McMoRan Inc. (FCX) and McMoRan Exploration Co. (MMR) completed the transactions contemplated by the Agreement and Plan of Merger, dated as of December 5, 2012 (the merger agreement), by and among MMR, FCX, and INAVN Corp., a Delaware corporation and indirect wholly owned subsidiary of FCX (Merger Sub). Pursuant to the merger agreement, Merger Sub merged with and into MMR, with MMR surviving the merger as an indirect wholly owned subsidiary of FCX (the merger).

FCX’s oil and gas assets are held through its wholly owned subsidiary, FCX Oil & Gas LLC (FM O&G). As a result of the merger, MMR and McMoRan Oil & Gas LLC (McMoRan), MMR’s wholly owned operating subsidiary, are both indirect wholly owned subsidiaries of FM O&G.

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In connection with the merger, on June 3, 2013, (1) FCX, as depositor, McMoRan, as grantor, the Trustee and the Delaware Trustee entered into the amended and restated royalty trust agreement to govern the Royalty Trust and the respective rights and obligations of FCX, the Trustee, the Delaware Trustee, and the Royalty Trust unitholders with respect to the Royalty Trust (the Royalty Trust Agreement); and (2) McMoRan, as grantor, and the Royalty Trust, as grantee, entered into the master conveyance of overriding royalty interests (the master conveyance) pursuant to which McMoRan conveyed to the Royalty Trust the overriding royalty interests in future production from the subject interests. Other than (a) its formation, (b) its receipt of contributions and loans from the Depositor (defined below) for administrative and other expenses as provided for in the Royalty Trust Agreement, (c) its payment of such administrative and other expenses, (d) its repayment of loans from the Depositor, (e) its receipt of the conveyance of the overriding royalty interests from McMoRan pursuant to the master conveyance, (f) its receipt of royalties from McMoRan or HOGA, and (g) its cash dividends to Royalty Trust unitholders, if any, the Royalty Trust has not conducted any activities.

On February 5, 2019, McMoRan completed the sale of all of its rights, title and interest in and to the onshore Highlander subject interest pursuant to a purchase and sale agreement with Highlander Oil & Gas Assets LLC (HOGA) (the Highlander Sale). The onshore Highlander subject interest was sold subject to the overriding royalty interest in future production held by the Royalty Trust. As a result of the Highlander Sale, HOGA has a 72 percent working interest and an approximate 48 percent net revenue interest in the onshore Highlander subject interest. The Royalty Trust continues to hold a 3.6 percent overriding royalty interest in the onshore Highlander subject interest. HOGA is the operator of the Highlander subject interest. The onshore Highlander subject interest is the only subject interest in which HOGA has an interest, as McMoRan previously had relinquished, allowed to expire or sold all of the other subject interests.

Effective December 31, 2024 (the Effective Date), FCX, McMoRan and HOGA entered into an Assignment and Assumption Agreement and Bill of Sale, pursuant to which (1) FCX assigned to HOGA, and HOGA assumed, all of the financial and other obligations of FCX as depositor under the Royalty Trust Agreement, and (2) McMoRan assigned to HOGA, and HOGA assumed, all of the rights and obligations of McMoRan as grantor under the Royalty Trust Agreement and the master conveyance that were not previously assumed by HOGA at the time of the Highlander Sale (collectively, the Assignment). Notwithstanding the Assignment, FCX remains obligated to perform the financial and other obligations owed to the Royalty Trust by the depositor under the Royalty Trust Agreement, if HOGA were to be unable to fully perform such obligations in the future. In this Form 10-K, the “Depositor” refers to FCX, for all periods ending prior to the Effective Date, and to HOGA, for all periods beginning on and after the Effective Date; and the “Grantor” refers to McMoRan, for all periods ending prior to the Effective Date, and to HOGA, for all periods beginning on and after the Effective Date.

3. OVERRIDING ROYALTY INTERESTS

The Royalty Trust units represent beneficial interests in the Royalty Trust, which holds a 5% gross overriding royalty interest in future production from each of the subject interests during the life of the Royalty Trust. An “overriding” royalty interest in general represents a non-operating interest in an oil and gas property that provides the owner a specified share of production without any related operating expenses or development costs and is carved out of an oil and gas lessee’s working or cost-bearing interest in the lease. In contrast, a “working” or “cost-bearing” interest in general represents an operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expenses and development costs. An owner of a working or cost-bearing interest, subject to the terms of an applicable operating agreement, generally has the right to participate in the selection of a prospect, drilling location or drilling contractor; to propose the drilling of a well; to determine the timing and sequence of drilling operations; to commence or shut down production; to take over operations; or to share in any operating decision. An owner of an overriding royalty interest generally has none of the rights described in the preceding sentence, and neither the Royalty Trust nor the Royalty Trust unitholders have any such rights. The Royalty Trust’s 5% gross overriding royalty interest in future production from each subject interest is proportionately reduced based on HOGA’s respective working interest in the subject interest.

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The onshore Highlander subject interest began commercial production on February 25, 2015. Prior to this date there had been no commercial production of hydrocarbons from any of the subject interests. On January 19, 2023, the sole well producing from the onshore Highlander subject interest experienced an operational issue, resulting in substantial amounts of water entering the well, which caused a shut in of the well before production resumed at significantly reduced levels. Following an evaluation by HOGA’s field operations team, HOGA determined that it would be necessary to commence operations to control the water production, in expectation of eventually initiating “kill” operations on the well. HOGA informed the Trustee that the well was shut in effective March 31, 2023 and production from the well has ceased. After that time the well flowed intermittently but not on a continuous basis. In October 2023, HOGA informed the Trustee that due to the underground flow of fluids into the wellbore, the well could not be salvaged and would be required to be plugged and abandoned. HOGA subsequently informed the Trustee that operations to permanently plug and abandon the well commenced in early March 2024. In February 2025, HOGA notified the Trustee that a new well on the onshore Highlander subject interest was spudded on January 30, 2025. See Note 8 for information regarding the status of the drilling of the new well.

The Royalty Trust fully impaired the carrying value of the onshore Highlander subject interest by $308,071 during the year ended December 31, 2023. Unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities, the Royalty Trust does not expect to receive any income attributable to its overriding royalty interests. Therefore, the Royalty Trust recognized the remaining carrying value of the onshore Highlander subject interest as of March 31, 2023 as an impairment loss.

The Royalty Trust has no ability to direct or influence the exploration or development of the onshore Highlander subject interest. In addition, HOGA is not under any obligation to fund or to commit any other resources to the exploration or development of the onshore Highlander subject interest. Further, HOGA has the right to elect not to participate in drilling or other operations conducted by other working interest owners with respect to the onshore Highlander subject interest.

The Royalty Trust will dissolve on the earliest to occur of (i) June 3, 2033, (ii) the sale of all of the overriding royalty interests, (iii) the election by the Trustee following its resignation for cause (as more fully described in the Royalty Trust Agreement), (iv) a vote of the holders of 66⅔% or more of the outstanding Royalty Trust units held by persons other than FCX, any of its affiliates, or HOGA at a duly called meeting of the Royalty Trust unitholders at which a quorum is present, or (v) the exercise by HOGA of the right to call all of the Royalty Trust units as described in the next paragraph. The overriding royalty interests terminate upon the termination of the Royalty Trust, other than in certain limited circumstances where the Royalty Trust has been permitted to transfer the overriding royalty interests to a third party pursuant to the terms of the Royalty Trust Agreement (in which case the overriding royalty interests may extend through June 3, 2033).

4. INCOME TAXES

Tax counsel to the special committee of the board of directors of MMR advised the Royalty Trust at the time of formation that, for U.S. federal income tax purposes, in its opinion, the Royalty Trust will be treated as a grantor trust and not as an unincorporated business entity. No ruling has been or will be requested from the Internal Revenue Service (IRS) or another taxing authority. As a grantor trust, the Royalty Trust will not be subject to tax at the Royalty Trust level. Rather, the Royalty Trust unitholders will be considered to own and receive the Royalty Trust’s assets and income and will be directly taxable thereon as though no trust were in existence. Under Treasury Regulations, the Royalty Trust is classified as a widely held fixed investment trust. Those Treasury Regulations require the sharing of tax information among trustees and intermediaries that hold a trust interest on behalf of or for the account of a beneficial owner or any representative or agent of a trust interest holder of fixed investment trusts that are classified as widely held fixed investment trusts. These reporting requirements provide for the dissemination of trust tax information by the trustee to intermediaries who are ultimately responsible for reporting the investor-specific information through Form 1099 to the investors and the IRS. Every trustee or intermediary that is required to file a Form 1099 for a trust unitholder must furnish a written tax information statement that is in support of the amounts as reported on the applicable Form 1099 to the trust unitholder. Any generic tax information provided by the Trustee of the Royalty Trust is intended to be used only to assist Royalty Trust unitholders in the preparation of their U.S. federal and state income tax returns.

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Royalty Trust unitholders should consult their own tax advisors regarding the treatment of the income, gain, loss or deduction derived by the unitholder for the Royalty Trust.

5. RELATED PARTY TRANSACTIONS

Royalties. In accordance with the master conveyance, the Royalty Trust did not receive any royalties during the ~~year~~years ended December 31, ~~2024. The~~2025 ~~Royalty Trust received royalties from HOGA of $401,278 during the year ended December 31, 2023, resulting from production from the~~and ~~onshore Highlander subject interest~~2024. Royalties received by the Royalty Trust must first be used to (i) satisfy Royalty Trust administrative expenses and (ii) reduce Royalty Trust indebtedness. The Royalty Trust ~~has~~had an outstanding note payable to HOGA of $416,489 and $200,000 outstanding as of December 31, ~~2024.~~2025 ~~The~~and ~~Royalty Trust had no indebtedness outstanding as of December 31~~2024, ~~2023~~respectively. As of December 31, ~~2024~~2025, the Trustee has established a minimum cash reserve of $302,500. As a result, distributions are made to Royalty Trust unitholders only when royalties received less administrative expenses incurred and repayment of any indebtedness exceeds the minimum cash reserve.

Commencing with the distribution to Royalty Trust unitholders in the first quarter of 2022, the Royalty Trust withheld $8,750 from the funds otherwise available for distribution each quarter through the first quarter of 2023, with the intent of gradually building a cash reserve of approximately $350,000. As no proceeds have been available for distribution since the first quarter of 2023, the Royalty Trust has not withheld any funds for the cash reserve with respect to those periods. Unless another well is drilled on the onshore Highlander subject interest and produces hydrocarbons in commercial quantities as discussed in Note 3 above, the Royalty Trust does not intend to withhold funds for the cash reserve as the Royalty Trust does not expect to have any cash available to distribute to Royalty Trust unitholders in future periods. This cash is reserved for the payment of future known, anticipated or contingent expenses or liabilities of the Royalty Trust. The Trustee may increase or decrease the targeted cash reserve amount at any time, and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the Royalty Trust unitholders. Cash held in reserve will be invested as required by the Royalty Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities eventually will be distributed to Royalty Trust unitholders, together with interest earned on the funds. For additional information regarding distributions to Royalty Trust unitholders, see Note 6.

Funding of Administrative Expenses. Pursuant to the Royalty Trust Agreement, the Depositor has agreed to pay annual trust expenses up to $350,000, with no right of repayment or interest due, to the extent the Royalty Trust lacks sufficient funds to pay administrative expenses. OnPursuant ~~February~~to 1this provision, ~~2024~~HOGA contributed $200,750 ~~pursuant~~on toApril ~~this~~4, ~~provision~~2025 and $149,250 ~~FCX~~on ~~contributed~~May ~~approximately~~16, 2025, together representing the maximum contribution of $~~166~~350,000 for the payment of trust expenses incurred during the year ended December 31, ~~2023~~2025. On February 1, ~~and~~2024, FCX contributed the maximum of $350,000 for the payment of trust expenses incurred during the year ended December 31, 2024. In addition to such annual contributions, the Depositor has agreed to lend money, on an unsecured, interest-free basis, to the Royalty Trust to fund the Royalty Trust’s ordinary administrative expenses as set forth in the Royalty Trust Agreement. All funds the Trustee borrows to cover expenses or liabilities, whether from the Depositor or from any other source, must be repaid before the Royalty Trust unitholders will receive any distributions. ~~FCX~~HOGA loaned the Royalty Trust $~~200~~216,~~000~~489 during the year ended December 31, ~~2024~~ 2025. NoFCX ~~loans~~loaned orthe ~~repayments~~Royalty Trust ~~were~~$200,000 ~~made~~ during the year ended December 31, ~~2023~~2024. Pursuant to the Assignment, as of December 31, 2024, FCX assigned to HOGA the promissory note relating to the outstanding loan to the Royalty Trust. As of December 31, 2025 and 2024, the outstanding note payable to HOGA was $416,489 and $200,000, respectively. To the extent annual trust expenses exceed $350,000, the Royalty Trust may be required to borrow funds from HOGA in the future.

Pursuant to the Royalty Trust Agreement, the Depositor also agreed to provide and maintain a $1.0 million stand-by reserve account or an equivalent letter of credit for the benefit of the Royalty Trust to enable the Trustee to draw on such reserve account or letter of credit to pay obligations of the Royalty Trust if its funds are inadequate to pay its obligations at any time. Currently, with the consent of the Trustee, HOGA may reduce the reserve account or substitute a letter of credit with a different face amount for the original letter of credit or any substitute letter of credit. In connection with this arrangement, the Depositor provided $1.0 million in the form of a reserve fund cash account to the Royalty Trust, which amount is reflected as reserve fund cash (and short-term investments) with a corresponding reserve fund liability in the accompanying Statements of Assets, Liabilities and Trust Corpus. As of December 31, 2024, the Royalty Trust had used $151,632 from the reserve account. During the year ended December 31, 2025, the Royalty Trust did not use any funds from the reserve account in 2025 and the Depositor ~~had~~did not ~~requested~~request a reduction of such reserve account. Effective December 31, 2024, FCX assigned its right, title and interest in the stand-by reserve account to HOGA, and HOGA assumed the responsibility to maintain the stand-by reserve account from FCX.

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6. DISTRIBUTIONS

There was not any distributable income for the ~~year ended December 31, 2024. Distributable income totaled $197,331 for the year ended December 31, 2023. A summary of quarterly per unit distributions for the~~ years ended December 31, ~~2024~~2025 and ~~2023 is set forth in the table below~~2024.

Three-month period ended:	2024						2023
	Amount		Per Unit Amount		Record Date	Payment Date	Amount		Per Unit Amount		Record Date	Payment Date
March 31,	$	0	$	0.000000	4/30/2024	N/A	$	197,331	$	0.000857	4/28/2023	5/12/2023
June 30,	$	0	$	0.000000	7/31/2024	N/A	$	0	$	0.000000	7/28/2023	N/A
September 30,	$	0	$	0.000000	10/31/2024	N/A	$	0	$	0.000000	10/30/2023	N/A
December 31,	$	0	$	0.000000	1/31/2025	N/A	$	0	$	0.000000	1/31/2024	N/A

These distributions are not necessarily indicative of future distributions.

Natural gas sales volumes (in thousands of cubic feet, or Mcf), average sales price (per Mcf) and net cash proceeds available for distribution for the years ended December 31, 2024 and 2023, are set forth in the table below.

	2024			2023
Natural gas sales volumes (Mcf)		-			101,352
Natural gas average sales price (per Mcf)	$	-		$	4.63
Gross proceeds		-			468,887
Post-production costs and specified taxes		-			(67,609	)
Royalty income		-			401,278
Interest and dividend income		3,737			15,866
Administrative expenses		(899,455	)		(469,821	)
Administrative expenses in excess of income		(895,718	)		(52,677	)
Income available for distribution		-			-
Adjustment to minimum cash reserve		-			(8,750	)
Net cash proceeds available for distribution	$	(895,718	)	$	(61,427	)

7. CONTINGENCIES

Litigation. There are currently no pending legal proceedings to which the Royalty Trust is a party.

8. SUBSEQUENT EVENTS

On February 1325, ~~2025~~2026, HOGA notified the Trustee that athe ~~new~~ well on the onshore Highlander subject interest, ~~was~~which had spudded on January 30, 2025, reached total depth of 30,862 feet on February 17, 2026. The future production status of this well remains unknown.

9. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)

Proved Natural Gas Reserve Information. ~~The~~There ~~following~~are ~~information~~no ~~summarizes the net~~ proved reserves offor ~~natural~~the ~~gas~~years ~~and~~ended ~~the~~December ~~standardized measure~~31, as2025 ~~described~~and ~~below~~2024.

The Royalty Trust believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production, including many factors beyond the Royalty Trust’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all natural gas reserve estimates are to some degree subjective, the quantities of natural gas that are ultimately recovered, production and specified post-production costs and taxes allowable under the Royalty Trust Agreement and future natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted future net cash flows (Standardized Measure) shown below represents estimates only and should not be construed as the current market value of the estimated reserves attributable to the overriding royalty interest associated with the subject interests. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties and any adjustments in the projected economic life of such properties resulting from changes in product prices.44

	Natural Gas
	(MMcf) (a)
	2024		2023
Proved reserves:
Balance at beginning of year		-		1,346
Revisions of previous estimates(b)		-		(1,245	)
Extensions and discoveries		-		-
Acquisition of reserves in-place		-		-
Sale of reserves in-place		-		-
Purchase of reserves in-place		-		-
Production		-		(101	)
Balance at end of year		-		-
Proved developed reserves at end of year		-		-
Proved undeveloped reserves at end of year		-		-

(a)	MMcf = millions of cubic feet.
(b)	For the year ended December 31, 2023, negative revisions associated with the onshore Highlander subject interest were due to shutting in the well and subsequently beginning operations to plug and abandon the well.

Standardized Measure. The Standardized Measure related to proved reserves is zero for 2024 and 2023 due to shutting in the well and subsequently beginning operations to plug and abandon the well. Estimates of future net revenues from the Royalty Trust’s proved natural gas properties and the present value thereof were made using the twelve-month average of the first-day-of-the-month historical reference prices as adjusted for location and quality differentials, which are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Future gross revenues were reduced by estimated specified post-production costs and taxes in accordance with the Royalty Trust Agreement. Future income taxes are not presented given the Royalty Trust’s status as a non-taxable “pass through” entity. See Note 4.

The Standardized Measure related to proved reserves as of December 31 is presented below:

	2024		2023
Future cash inflows	$	0	$	0
Future costs applicable to future cash flows:
Production costs (primarily production and ad valorem taxes)		-		-
Development and abandonment costs		-		-
Future income taxes (a)		-		-
Future net cash flows		-		-
Discount for estimated timing of net cash flows (10% discount rate) (b)		-		-
Standardized measure	$	0	$	0

(a)	No taxes are presented given the Royalty Trust’s status as a non-taxable “pass-through” entity. See Note 4.
(b)	Amounts reflect application of the required 10% discount rate to the estimated future net cash flows associated with production of estimated proved reserves.

A summary of the principal sources of changes in the Standardized Measure for the years ended December 31 is presented below:

	2024		2023
Balance at beginning of year	$	0	$	6,055,300
Sales, net of production expenses		-		(401,278	)
Revisions of quantity estimates		-		(5,654,022	)
Balance at end of year	$	0	$	0

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not Applicable.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Evaluation of ~~disclosure~~Disclosure ~~controls~~Controls and ~~procedures~~Procedures. The Royalty Trust has no employees, and, therefore, does not have a principal executive officer or principal financial officer. Accordingly, the Trustee is responsible for making the evaluations, assessments and conclusions required pursuant to this Item 9A. The Trustee has evaluated the effectiveness of the Royalty Trust’s “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Based on this evaluation, the Trustee has concluded that the Royalty Trust’s disclosure controls and procedures are effective as of the end of the period covered by this Form 10-K.

Due to the nature of the Royalty Trust as a passive entity and in light of the contractual arrangements pursuant to which the Royalty Trust was created, including the provisions of (i) the Royalty Trust Agreement and (ii) the master conveyance, the Royalty Trust’s disclosure controls and procedures necessarily rely on (A) information provided by HOGA, including information relating to results of operations, the costs and revenues attributable to the subject interests and other operating and historical data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the subject interests and the overriding royalty interests, and (B) conclusions and reports regarding reserves by the Royalty Trust’s independent reserve engineers.

Internal Control Over Financial Reporting

(a) Trustee’s Annual Report on Internal Control over Financial Reporting. The Bank of New York Mellon Trust Company, N.A., as Trustee of the Royalty Trust, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Exchange Act. The Trustee conducted an evaluation of the effectiveness of the Royalty Trust’s internal control over financial reporting based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework) (the “COSO criteria”). Based on the Trustee’s evaluation under the COSO criteria, the Trustee concluded that the Royalty Trust’s internal control over financial reporting was effective as of December 31, ~~2024~~2025.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

(b) Changes in Internal Control over Financial Reporting. During the quarter ended December 31, ~~2024~~2025, there has been no change in the Royalty Trust’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Royalty Trust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of HOGA.

Item 9B. Other Information

Rule 10b5-1 Trading Plans. During the three months ended December 31, ~~2024~~2025, no officer or employee of the Trustee who performs policy-making functions for the Royalty Trust adopted, modified, or terminated any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement, as such terms are defined in Item 408(a) of Regulation S-K, with respect to the Royalty Trust units.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not Applicable.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Code of Ethics; Audit Committee; Nominating Committee

The Royalty Trust has no directors, officers or employees, and, therefore, the Royalty Trust has not adopted a Code of Ethics and the Royalty Trust does not have an audit committee or nominating committee. The Royalty Trust is administered by the Trustee pursuant to the Royalty Trust Agreement. The Royalty Trust Agreement grants the Trustee only the rights and powers necessary to achieve the purposes of the Royalty Trust. For more information on the rights and duties of the Trustee, see Part I, Items 1. and 2. “Business and Properties – The Royalty Trust – The Royalty Trust Agreement – Duties and Limited Powers of the Trustee” of this Form 10-K.

Insider Trading Policy

Because the Royalty Trust has no directors, officers or employees, and because the Trustee does not have the authority under the terms of the Royalty Trust Agreement to engage in transactions in the Royalty Trust units on behalf of the Royalty Trust, the Royalty Trust has not adopted an insider trading policy applicable to such persons or to the Trust itself. It is the policy of the Trustee that any transaction in Royalty Trust units by any officer or employee of the Trustee who performs policy-making functions for the Royalty Trust must comply with the insider trading policies of The Bank of New York Mellon Corporation, the parent corporation of The Bank of New York Mellon Trust Company, N.A.

Item 11. Executive Compensation

The Royalty Trust has no directors, officers or employees. For information regarding the compensation paid to the Trustee, see Part I, Items 1. and 2. “Business and Properties – The Royalty Trust – The Royalty Trust Agreement – Compensation of the Trustee” of this Form 10-K. The Royalty Trust does not have a board of directors, and it does not have a compensation committee.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Royalty Trust Unitholder Matters

Securities Authorized for Issuance Under Equity Compensation Plans

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

Security Ownership of Certain Beneficial Owners

Based on filings with the SEC and any information that HOGA has provided to the Trustee, the table below shows the beneficial owners of more than 5% of the outstanding Royalty Trust units. Unless otherwise indicated, all information is presented as of December 31, ~~2024~~2025, and all Royalty Trust units beneficially owned are held with sole voting and investment power.

Name and Address of Beneficial Owner	Total Number of Royalty Trust Units Beneficially Owned			Percent of Outstanding Royalty Trust Units ^(a)

Highlander Oil & Gas Assets LLC
Montex Highlander LLC
420 Throckmorton Street, Suite 550
Fort Worth, TX 76102		31,143,150	^(b)		13.53	%

Freeport-McMoRan Inc.
McMoRan Oil & Gas LLC
333 North Central Avenue
Phoenix, AZ 85004		31,143,149	^(c)		13.53	%

Leon G. Cooperman
11431 W. Palmetto Park Road
Boca Raton, FL 33428		21,651,695	^(d)		9.41	%

Akanthos Capital Management, LLC
21700 Oxnard Street, Suite 1730
Woodland Hills, CA 91367		16,135,696	^(e)		7.01	%

(a) Based on 230,172,696 Royalty Trust units outstanding as of December 31, ~~2024~~2025. (b) Based on a Schedule 13G filed with the SEC on June 9, 2023 that constitutes an initial Schedule 13G on behalf of Montex Highlander, LLC (“Montex Highlander”) and Amendment No. 2 to the Schedule 13G filed by HOGA and Magnolia Oil & Gas Corporation (“Magnolia”) on March 15, 2019. On May 30, 2023, Montex Highlander purchased all of the interest in Highlander Oil & Gas Holdings LLC (“Highlander Holdings”) owned by MGY Louisiana, LLC (“MGY Louisiana”). Highlander Holdings wholly owns HOGA, which owns the Royalty Trust units reported on the Schedule 13G. MGY Louisiana is a wholly owned subsidiary of Magnolia Oil & Gas Operating LLC, which is a wholly owned subsidiary of Magnolia Oil & Gas Intermediate LLC, which is a wholly owned subsidiary of Magnolia Oil & Gas Parent LLC, whose managing member is Magnolia. (c) Based on an amended Schedule 13G/A filed with the SEC on February 12, 2020 by FCX and McMoRan. (d) Based on an amended Schedule 13G filed with the SEC on November 13, 2015, by Leon G. Cooperman, on his own behalf and on behalf of affiliated investment firms and managed accounts identified therein. Mr. Cooperman represents that he has sole voting and investment power over 5,000,000 Royalty Trust units. Mr. Cooperman subsequently filed an amended Form 4 on December 4, 2015, reporting 21,651,695 Royalty Trust units held in managed accounts and private investment entities over which he has investment discretion but disclaims beneficial ownership except to the extent of his pecuniary interest therein. (e) Based on a Schedule 13G filed with the SEC on February 14, 2018, by Akanthos Capital Management, LLC. According to the filing, the Akanthos Capital Management, LLC has sole voting and investment power with respect to 16,135,696 Royalty Trust units and no shared voting or investment power with respect to Royalty Trust units; all securities reported are owned by the reporting person’s advisory clients, none of which to the reporting person’s knowledge owns more than 5% of the total outstanding Royalty Trust units.

The Royalty Trust has no directors, executive officers or employees, and therefore, has no equity compensation plans and no ownership of management to report. The Trustee knows of no arrangement, including the pledge of Royalty Trust units, the operation of which may at a subsequent date result in a change in control of the Royalty Trust.47

(d)	Based on an amended Schedule 13G filed with the SEC on November 13, 2015, by Leon G. Cooperman, on his own behalf and on behalf of affiliated investment firms and managed accounts identified therein. Mr. Cooperman represents that he has sole voting and investment power over 5,000,000 Royalty Trust units. Mr. Cooperman subsequently filed an amended Form 4 on December 4, 2015, reporting 21,651,695 Royalty Trust units held in managed accounts and private investment entities over which he has investment discretion but disclaims beneficial ownership except to the extent of his pecuniary interest therein.

(e)	Based on a Schedule 13G filed with the SEC on February 14, 2018, by Akanthos Capital Management, LLC. According to the filing, the Akanthos Capital Management, LLC has sole voting and investment power with respect to 16,135,696 Royalty Trust units and no shared voting or investment power with respect to Royalty Trust units; all securities reported are owned by the reporting person’s advisory clients, none of which to the reporting person’s knowledge owns more than 5% of the total outstanding Royalty Trust units.

Security Ownership of Management

Not applicable.

Changes in Control

The Trustee knows of no arrangement, including the pledge of Royalty Trust units, the operation of which may at a subsequent date result in a change in control of the Royalty Trust.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Other than (a) its formation, (b) its receipt of contributions and loans the Depositor for administrative and other expenses as provided for in the Royalty Trust Agreement, (c) its payment of such administrative and other expenses, (d) its repayment of loans from the Depositor, (e) its receipt of the conveyance of the overriding royalty interests from the Grantor pursuant to the master conveyance, (f) its receipt of royalties from McMoRan or HOGA, and (g) its cash distributions to Royalty Trust unitholders, if any, the Royalty Trust has not conducted any activities.

Funding of Administrative Expenses. Pursuant to the Royalty Trust Agreement, the Depositor has agreed to pay annual trust expenses up to $350,000, with no right of repayment or interest due, to the extent the Royalty Trust lacks sufficient funds to pay administrative expenses. OnPursuant ~~February 1, 2024, pursuant~~ to this provision, ~~FCX~~HOGA contributed ~~approximately~~ $~~166~~200,~~000~~750 ~~for~~on ~~the~~April ~~payment~~4, of2025 ~~trust~~and ~~expenses~~$149,250 ~~incurred~~on ~~during the~~May ~~year ended December 31~~16, ~~2023~~2025, ~~and~~together ~~contributed~~representing the maximum contribution of $350,000 for the payment of trust expenses incurred during the year ended December 31, ~~2024~~2025. NoOn ~~such~~February ~~contributions~~1, ~~were~~2024, ~~made~~FCX contributed $350,000 for the payment of trust expenses incurred during the year ended December 31, ~~2022~~2024. In addition to such annual contributions, the Depositor has agreed to lend money, on an unsecured, interest-free basis, to the Royalty Trust to fund the Royalty Trust’s ordinary administrative expenses as set forth in the Royalty Trust Agreement. All funds the Trustee borrows to cover expenses or liabilities, whether from the Depositor or from any other source, must be repaid before the Royalty Trust unitholders will receive any distributions. ~~FCX~~HOGA loaned the Royalty Trust $~~200~~216,~~000~~489 during the year ended December 31, ~~2024~~2025. NoFCX ~~loans~~loaned orthe ~~repayments~~Royalty ~~were~~Trust ~~made~~$200,000 during the year ~~ended~~ ended December 31, ~~2023~~2024. Pursuant to the Assignment, as of December 31, 2024, FCX assigned to HOGA the promissory note relating to the ~~outstanding~~ outstanding loan to the Royalty Trust. As of December 31, 2025, the outstanding note payable to HOGA was $416,489. To the extent annual trust expenses exceed $350,000, the Royalty Trust may be required to borrow funds from HOGA in the future.

Pursuant to the Royalty Trust Agreement, the Depositor also agreed to provide and maintain a $1.0 million stand-by reserve account or an equivalent letter of credit for the benefit of the Royalty Trust to enable the Trustee to draw on such reserve account or letter of credit to pay obligations of the Royalty Trust if its funds are inadequate to pay its obligations at any time. Currently, with the consent of the Trustee, HOGA may reduce the reserve account or substitute a letter of credit with a different face amount for the original letter of credit or any substitute letter of credit. In connection with this arrangement, FCX provided $1.0 million in the form of a reserve fund cash account to the Royalty Trust, which amount is reflected as reserve fund cash (and short-term investments) with a corresponding reserve fund liability in the accompanying Statements of Assets, Liabilities and Trust Corpus. The Royalty Trust has not drawn any funds from the reserve account, and the Depositor has not requested a reduction of such reserve account. Effective December 31, 2024, pursuant to the Assignment, FCX assigned its right, title and interest in the stand-by reserve account to HOGA, and HOGA assumed from FCX the responsibility to maintain the stand-by reserve account. For additional information regarding the Royalty Trust Agreement, see Note 2 in the Notes to Financial Statements located in Part II, Item 8. “Financial Statements and Supplementary Data” of this Form 10-K.

Compensation of the Trustee. The Trustee’s annual compensation is $200,000. Additionally, the Trustee receives reimbursement for its reasonable out-of-pocket expenses incurred in connection with the administration of the Royalty Trust. In the event of litigation involving the Royalty Trust, audits or inspection of the records of the Royalty Trust pertaining to the transactions affecting the Royalty Trust or any other unusual or extraordinary services rendered in connection with the administration of the Royalty Trust, the Trustee would be entitled to receive additional reasonable compensation for the services rendered, including the payment of the Trustee’s standard rates for all time spent by personnel of the Trustee on such matters. The Trustee’s compensation is paid out of the Royalty Trust’s assets. The Trustee has a lien on the Royalty Trust’s assets to secure payment of its compensation and any indemnification expenses and other amounts to which it is entitled under the Royalty Trust Agreement.

Royalty Trust Units Held by FCX and HOGA. At December 31, ~~2024~~2025, the Royalty Trust had 230,172,696 Royalty Trust units outstanding. At December 31, ~~2024~~2025, HOGA held 31,143,150 Royalty Trust units and FCX, through its wholly owned subsidiary McMoRan, held 31,143,149 Royalty Trust units. FCX and HOGA each hold 13.5% of the outstanding Royalty Trust units.

~~The~~Director Independence. The Royalty Trust has no directors.

Item 14. Principal Accountant Fees and Services

Fees and Related Disclosures for Accounting Services

On August 2, 2024, the Trustee dismissed Ernst & Young, LLP ~~(“E&Y”)~~ as the Royalty Trust’s independent registered public accounting firm. On August 2, 2024, the Trustee appointed Weaver and Tidwell, L.L.P. (“Weaver”) as the Royalty Trust’s independent registered public accounting firm.

The following table discloses the fees for professional services billed to the Royalty Trust by Weaver ~~and E&Y~~ for the years ended December 31, ~~2024~~ 2025 and ~~2023~~2024:

	2024		2023
	2025		2024
Audit Fees(1)	$	55120,750	$	~~170~~15,~~000~~750
Audit-Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

(1) Fees billed for professional services rendered for the audit of the Royalty Trust’s financial statements and reviews of the financial statements included in the Royalty Trust’s quarterly reports and annual financial statements. ~~In 2024, E&Y and Weaver billed $40,000 and $15,750, respectively, in audit fees. In 2023, all of the audit fees were billed by E&Y.~~

The Royalty Trust has no audit committee, and as a result, has no audit committee pre-approval policies and procedures with respect to fees paid to Weaver. Any pre-approval or approval of any services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1)

Financial Statements. The following financial statements are set forth under Part II, Item 8 of this Form 10-K on the pages indicated:

	Page in this Form 10-K
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 410)	36
Statements of Assets, Liabilities and Trust Corpus	3837
Statements of Distributable Income	3938
Statements of Changes in Trust Corpus	4039
Notes to Financial Statements	4140

(a)(2)	Financial Statement Schedules. All financial statement schedules are either not required under the related instructions or are not applicable because the information has been included elsewhere herein.
(a)(3)	Exhibits.

(a)(2)

Financial Statement Schedules. All financial statement schedules are either not required under the related instructions or are not applicable because the information has been included elsewhere herein.

		Filed or Furnished
Exhibit		with this	Incorporated by Reference
Number	Exhibit Title	Form 10-K	Form	File No.	Date Filed
3.1	Composite Certificate of Trust of Gulf Coast Ultra Deep Royalty Trust		10-Q	333-185742	August 14, 2013
4.1	Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934		10-K	001-36386	March 20, 2020
10.1	Master Conveyance of Overriding Royalty Interest by and between McMoRan Oil & Gas LLC and Gulf Coast Ultra Deep Royalty Trust, dated as of June 3, 2013		8-K	333-185742	June 4, 2013
10.2	Amended and Restated Royalty Trust Agreement of Gulf Coast Ultra Deep Royalty Trust, dated as of June 3, 2013		8-K	333-185742	June 4, 2013
16.1	Letter of Ernst & Young LLP dated August 8, 2024 to the SEC		8-K	333-185742	August 8, 2024
23	Consent of Netherland, Sewell & Associates, Inc.	X
31	Certification pursuant to Rule 13a-14(a)/15d-14(a)	X
32	Certification pursuant to 18 U.S.C. Section 1350	X
99.1	Report of Netherland, Sewell & Associates, Inc. dated January 26, 2023		10-K	001-36386	March 15, 2023
99.2	Letter from Netherland, Sewell & Associates, Inc. dated March 21, 2025	X

(a)(3)

Exhibits. The exhibits below are filed or furnished herewith or incorporated herein by reference.

		Filed or
		Furnished
Exhibit		with this	Incorporated by Reference
Number	Exhibit Title	Form 10-K	Form	File No.	Date Filed
3.1	Composite Certificate of Trust of Gulf Coast Ultra Deep Royalty Trust		10-Q	333-185742	August 14, 2013
4.1	Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934		10-K	001-36386	March 20, 2020
10.1	Master Conveyance of Overriding Royalty Interest by and between McMoRan Oil & Gas LLC and Gulf Coast Ultra Deep Royalty Trust, dated as of June 3, 2013		8-K	333-185742	June 4, 2013
10.2	Amended and Restated Royalty Trust Agreement of Gulf Coast Ultra Deep Royalty Trust, dated as of June 3, 2013		8-K	333-185742	June 4, 2013
16.1	Letter of Ernst & Young LLP dated August 8, 2024 to the SEC		8-K	333-185742	August 8, 2024
23	Consent of Netherland, Sewell & Associates, Inc.	X
31	Certification pursuant to Rule 13a-14(a)/15d-14(a)	X
32	Certification pursuant to 18 U.S.C. Section 1350	X
99.1	Report of Netherland, Sewell & Associates, Inc. dated January 26, 2023		10-K	001-36386	March 15, 2023
99.2	Letter from Netherland, Sewell & Associates, Inc. dated March 13, 2026	X

Item 16. Form 10-K Summary

Not applicable.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Gulf Coast Ultra Deep Royalty Trust
	By:	The Bank of New York Mellon Trust Company, N.A.,
		Trust Company, N.A., as Trustee
		as Trustee
	By:	/s/ Sarah C. Newell
		Sarah C. Newell
		Vice President
Date: March 28, 2025
Date: March 25, 2026

The Registrant, Gulf Coast Ultra Deep Royalty Trust, has no principal executive officer, principal financial officer, controller or principal accounting officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that any such function exists pursuant to the terms of the amended and restated royalty trust agreement, dated June 3, 2013, under which it serves.

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