Gulf Coast Ultra Deep Royalty Trust

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, 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 interests. McMoRan has informed the Trustee that it has no plans to pursue, has relinquished, has allowed to expire or has sold all of its subject interests.

At December 31, 2023, 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. Since that time the well has 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 cannot be salvaged and must be plugged and abandoned. HOGA has 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. Unless another well is drilled 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. HOGA has not informed the Trustee of any definitive plans to drill a new well on the Highlander subject interest. 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:

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 FCX 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 FCX 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 FCX 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 FCX, (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 and 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, FCX 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, FCX 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. On February 1, 2024, pursuant to this provision, FCX contributed approximately $166,000 for the payment of trust expenses incurred during the year ended December 31, 2023, and contributed the maximum of $350,000 for the payment of trust expenses incurred during the year ending December 31, 2024. No such contributions were made during the year ended December 31, 2022. In addition to such annual contributions, FCX 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 FCX or from any other source, must be repaid before the Royalty Trust unitholders will receive any distributions. No loans or repayments were made during the years ended December 31, 2023 and 2022.

Pursuant to the Royalty Trust Agreement, FCX 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, FCX 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 has provided $1.0 million in the form of a reserve fund cash account to the Royalty Trust. As of December 31, 2023, the Royalty Trust had not drawn any funds from the reserve account, and FCX had not requested a reduction of such 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:

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 FCX or McMoRan or any officer or other employee of FCX or McMoRan. 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 HOGA or FCX or their respective affiliates.

FCX 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:

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 its affiliates, and Royalty Trust unitholders other than FCX or its 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 FCX 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).

*FCX Call Rights.*FCX 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, FCX 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 FCX 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 FCX 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 FCX 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 FCX’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 FCX) 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) FCX 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 McMoRan’s or HOGA’s respective 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 none of McMoRan, FCX or HOGA has any 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 had no indebtedness outstanding as of December 31, 2023. As of December 31, 2022, 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 were available for distribution in the second, third or fourth quarters of 2023, the Royalty Trust did not withhold any funds for the cash reserve with respect to those periods. Unless another well is drilled on the onshore Highlander subject interest 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.

Distributable income totaled $197,331 and $1,842,816 for the years ended December 31, 2023 and 2022, respectively. 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. Since that time the well has 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 cannot be salvaged and must 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, 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 not informed the Trustee of any definitive plans to drill a new well on the Highlander subject interest. 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 FCX. As a result, any material adverse change in FCX’s or 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 FCX or McMoRan to provide to the Royalty Trust such other information available to FCX or McMoRan 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 FCX or McMoRan 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. 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.

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 FCX, McMoRan, HOGA or their respective 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 interests. McMoRan has informed the Trustee that it has no plans to pursue, has relinquished, has allowed to expire or has sold all of its 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. Since that time the well has 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 cannot be salvaged and must 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, 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 not informed the Trustee of any definitive plans to drill a new well on the Highlander subject interest. Neither the Trustee nor the Royalty Trust unitholders has any right to control or influence operations of the subject interest.

Exploratory and Development Drilling. McMoRan and HOGA did not drill any exploration or development wells on the subject interests during the years ended December 31, 2023 and 2022. Additionally, there were no in-progress or suspended wells associated with the subject interests during the years ended December 31, 2023 and 2022.

**Acreage.**At December 31, 2023, HOGA owned interests in approximately 131 oil and gas leases onshore in South Louisiana, covering approximately 9,000 gross acres (6,476 acres net to HOGA’s interests) associated with the onshore Highlander subject interest. McMoRan has informed the Trustee that it has no plans to pursue, has relinquished, has allowed to expire or has sold all of its 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, 2023. 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, 2023. 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, 2023, 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, 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 not informed the Trustee of any definitive plans to drill a new well on the Highlander subject interest. Neither the Trustee nor the Royalty Trust unitholders has any right to control or influence operations of the subject interest. 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. During the year ended December 31, 2022, the Royalty Trust received royalties of $2,472,908 from HOGA and McMoRan related to 429,000 Mcf of natural gas production attributable to the onshore Highlander subject interest with average post-production costs of $0.43 per Mcf and an average receipt price of $6.19 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.

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.

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 interests. McMoRan has informed the Trustee that it has no plans to pursue, has relinquished, has allowed to expire or has sold all of its subject interests. To the extent that HOGA does not fund the exploration and development of the onshore Highlander subject interest, Royalty Trust unitholders will not realize any additional value from their investment in the Royalty Trust units.

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, in December 2023 the EPA adopted a final rule 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 is also charged with establishing National Ambient Air Quality Standards (NAAQS), the implementation of which can indirectly impact HOGA’s operations. The CAA directs the EPA to review each NAAQS every five years to ensure that the standards are protective of public health and welfare. This process routinely results in the tightening of those standards, and in October 2015, the EPA lowered the ozone NAAQS from 75 to 70 parts per billion. In December 2020, the EPA published a final rule that retained without revision the 2015 NAAQS ozone standard. More recently, however, in February 2024, the EPA has announced a final rule that will lower the annual standard for fine particulate matter from 12 micrograms per cubic meter to 9 micrograms per cubic meter. State or federal implementation of the revised NAAQs in the areas in which HOGA operates could result in increased costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. Failure to comply with air quality regulations may also result in administrative, civil, and/or criminal penalties for non-compliance.

Climate Change. The threat of climate change continues to attract considerable attention globally. In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (GHGs) may present an endangerment to public health and the environment, the EPA has 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 recently adopted methane emissions guidelines for existing oil and gas sources. 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, 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.

The Inflation Reduction Act of 2022 included new Clean Air Act section 136(c) directing EPA to collect the Waste Emissions Charge 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 proposed new rules to implement the Waste Emissions Charge program in January 2024.

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. 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.

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. The Trump Administration significantly revised the regulations implementing NEPA in 2020 in an effort to make the review process more efficient and more narrowly tailored to the agency’s specific action. The Biden Administration undertook an initial revision to the NEPA regulations which were finalized in 2022, essentially reverting to the pre-2020 rule language for a few elements of the rules. In 2023, the Biden Administration issued a second proposed rule that would make significant changes to the Trump Administration regulations. The proposed rule is expected to be finalized in April of 2024. In addition, in early 2023 White House Council on Environmental Quality issued guidance to the federal agencies on how agencies should consider greenhouse gas emissions and climate impacts in the course of their reviews under NEPA. Although the Trump Administration regulations were never fully implemented, the Biden Administration changes may have a meaningful impact on federal reviews related to HOGA especially as those reviews relate to climate and environmental justice.

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.

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 would be treated as a grantor trust and not as an unincorporated business entity. No ruling has been or will be requested from the IRS or another taxing authority.

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.

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, 2023, the highest marginal rates for the payment of Louisiana income taxes are 4.25% for individuals, trusts and estates, and 7.5% 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.