UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K(Mark One)[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2013OR[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period fromtoCommission File Number: 333-185742Gulf Coast Ultra Deep Royalty Trust(Exact name of registrant as specified in its charter)


Delaware46-6448579(State or other jurisdiction ofincorporation or organization)(IRS Employer Identification No.)The Bank of New York Mellon Trust Company, N.A., as trusteeInstitutional Trust Services919 Congress Avenue, Suite 500Austin, Texas78701(Address of principal executive offices)(Zip Code)(713) 483-6792(Registrant's telephone number, including area code)Securities registered pursuant to Section 12(b) of the Act:Title of each className of each exchange on which registeredNoneNone


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





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





Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). o Yes o No





Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x





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


o Large accelerated filer o Accelerated filer x Non-accelerated filer (Do not check if a smaller reporting company) o Smaller reporting company





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





The aggregate market value of royalty trust units held by non-affiliates of the registrant was $284.4 million on June 28, 2013.





On February 28, 2014, there were outstanding 230,172,696 royalty trust units representing beneficial interests in the registrant.





DOCUMENTS INCORPORATED BY REFERENCE NONE








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Gulf Coast Ultra Deep Royalty Trust


Annual Report on Form 10-K for


the fiscal year ended December 31, 2013


TABLE OF CONTENTSPagePart IItems 1. and 2. Business and Properties3Item 1A.  Risk Factors17Item 1B.  Unresolved Staff Comments23Item 3. Legal Proceedings23Item 4. Mine Safety Disclosures23Part IIItem 5. Market for Registrant’s Royalty Trust Units, Related Royalty Trust Unitholder Matters and Issuer Purchases of Royalty Trust Units23Item 6. Selected Financial Data24Items 7. and 7A. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk24Item 8. Financial Statements and Supplementary Data29Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure39Item 9A. Controls and Procedures39Item 9B. Other Information40Part IIIItem 10. Directors, Executive Officers and Corporate Governance40Item 11. Executive Compensation41Item 12. Security Ownership of Certain Beneficial Owners and Management and Related  Royalty Trust Unitholder Matters41Item 13. Certain Relationships and Related Transactions, and Director Independence42Item 14. Principal Accounting Fees and Services43Part IVItem 15. Exhibits and Financial Statement Schedules43Glossary43SignaturesS-1Appendix A - Summary Reserve Report of Ryder Scott Company, L.P. dated February 14, 2014A-1Exhibit IndexE-1








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FORWARD-LOOKING STATEMENTS





This 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.  Forward-looking statements are all statements other than statements of historical facts, such as any statements regarding the future financial condition of Gulf Coast Ultra Deep Royalty Trust (the Royalty Trust), and all statements regarding McMoRan Oil and Gas LLC ’ s (McMoRan) plans, the potential results of any drilling on the subject interests (as defined in this Form 10-K), McMoRan ’ s and the Royalty Trust ’ s anticipated interests in any of the subject interests, McMoRan ’ s geologic model and the nature of the geologic trend discussed in this Form 10-K, 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 risk that the subject interests covered by the royalty interests will not produce 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 McMoRan not to develop the subject interests, any inability of McMoRan to develop the subject interests, damages to facilities resulting from natural disasters or accidents and other factors described in Part I, Item 1A. “ Risk Factors ” of this Form 10-K.





All forward-looking statements speak only as of the date of this Form 10-K.  Investors are cautioned 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.





PART I





Items 1. and 2. Business and Properties





Our periodic reports filed with the Securities and Exchange Commission (SEC) pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (Exchange Act), as amended, are available, free of charge, through our website, http://gultu.investorhq.businesswire.com, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and any amendments to those reports.  These reports and amendments are available through our website as soon as reasonably practicable after we electronically file or furnish such materials with the SEC.





References to “we,” “us,” and “our” refer to Gulf Coast Ultra Deep Royalty Trust (the Royalty Trust). 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.)  We have also provided a glossary of definitions for some of the oil and gas industry terms we use in this Form 10-K beginning on page 43 .





THE ROYALTY TRUST





The Royalty Trust. The Royalty Trust is a statutory trust created under the Delaware Statutory Trust Act pursuant to a trust agreement entered into on December 18, 2012 (inception), between Freeport-McMoRan Copper & Gold Inc. (FCX), as depositor, Wilmington Trust, National Association, as the 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 act of the depositor. Effective June 3, 2013, the Royalty Trust’s regular trustees were replaced by The Bank of New York Mellon Trust Company, N.A., a national banking association, as trustee (the Trustee).





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The Royalty Trust was created in connection with FCX's June 2013 acquisition of McMoRan Exploration Co. (MMR) (the merger). Immediately prior to the effective time of the merger, McMoRan Oil & Gas LLC (McMoRan) conveyed to the Royalty Trust a 5% gross overriding royalty interest (collectively, the royalty interests) in future production from each of McMoRan's shallow water Inboard Lower Tertiary/Cretaceous (ILTC, previously referred to as ultra-deep) exploration prospects located on the Shelf of the Gulf of Mexico and onshore South Louisiana that existed as of December 5, 2012, the date FCX agreed to acquire MMR (collectively, the subject interests). The subject interests were "carved out" of the mineral interests that were acquired by FCX pursuant to the merger and were not considered part of FCX's purchase consideration of MMR. McMoRan owns less than 100% of the working interest in each of the subject interests. FCX's portfolio of oil and gas assets is held through its wholly owned subsidiary, Freeport-McMoRan Oil & Gas LLC (FM O&G). MMR and McMoRan are wholly owned subsidiaries of FMO&G.





As described below, none of the subject interests have any reserves classified as proved, probable or possible (other than the onshore Lineham Creek subject interest) and none of the subject interests have any associated production.





The 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 natural gas properties or mineral interests or otherwise engage in activities beyond those necessary for the conservation and protection of the royalty interests.


As of December 31, 2013, FCX beneficially owned 27.1% of the outstanding royalty trust units. All information in this Form 10-K regarding the subject interests and related matters has been furnished to the Trustee by McMoRan.  The reserve estimates have been prepared by independent petroleum engineers as described herein, based on information furnished by FM O&G.





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, McMoRan, 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 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:





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|• | collecting income attributable to the royalty interests;




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




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|• | distributing distributable income to the Royalty Trust unitholders; and




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|• | prosecuting, defending or settling any claim of or against the Trustee, the Royalty Trust or the royalty interests, including the authority to dispose of or relinquish title to any of the 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 FCX or itself. The Trustee may also encumber the assets of the Royalty Trust (i.e., the royalty interests) to secure payment of the indebtedness. If the Trustee borrows funds 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.


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The only assets of the Royalty Trust are the royalty interests and the only investment activity the Trustee may engage in is the investment of cash on hand.





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 royalty interests to the Royalty Trust or to settle disputes involving such conveyances, so long as such modifications or settlements do not alter the nature of the royalty interests as rights to receive a share of the oil and gas, or proceeds thereof, from the underlying properties free of any obligation for drilling, development or operating expenses or rights that do not possess any operating rights or are obligations.





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:





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|• | charge for its services as trustee;




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|• | 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);




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|• | 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




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




In discharging its duty 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 shall look only to the Royalty Trust’s property for payment or satisfaction thereof.


Amendment of Trust Agreement. Any amendment of the royalty trust agreement requires a vote of holders of 662⁄3% or more of the outstanding royalty trust units, except that any amendment that would permit the holders of fewer than 80% of the outstanding royalty trust units to approve a sale of all or substantially all of the royalty interests, whether in a single transaction or series of transactions, or to terminate the Royalty Trust requires a vote of holders of 80% (which, after June 3, 2018, shall be reduced to 662⁄3%) or more of the outstanding royalty trust units held by persons other than FCX or its subsidiaries. However, 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, provided that such supplement or amendment does not adversely affect the interests of the Royalty Trust unitholders. In addition, no amendment may:


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|• | 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;




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|• | alter the rights of the Royalty Trust unitholders as among themselves;




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|• | permit the Trustee to distribute the royalty interests in kind; or




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




Compensation of the Trustee. The Trustee will be paid the sum of $150,000 per year until the first year in which the Royalty Trust receives any payment pursuant to the conveyances of the royalty interests, at which time such sum shall be increased to $200,000 per year, and will receive 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 Royalty Trust personnel on such matters. The Trustee’s compensation is paid out of the Royalty Trust assets.





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 of the Royalty Trust unitholders of record as of a record date set by the Trustee at least 20 days and 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 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, other than with respect to matters where a conflict of interest between FCX and unaffiliated Royalty Trust unitholders is present). The affirmative vote of the holders of 662⁄3% of the outstanding royalty trust units will be required to (1) amend the royalty trust agreement (excluding the requirements for 80% Royalty Trust unitholder approval of dissolution of the Royalty Trust or a sale of all or substantially all of the royalty interests, which requires approval of holders of 80% of the outstanding royalty trust units as further discussed above), (2) approve other sales of the assets of the Royalty Trust or (3) approve any amendment, modification, termination or waiver of any rights under the master conveyance (or any other instrument of conveyance).





The Trustee may be removed, with or without cause, by a vote of the 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 not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all royalty trust units entitled to vote thereon were present and voted.


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.





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Duration of the Royalty Trust. The Royalty Trust will dissolve on the earlier of (1)  June 3, 2033, (2)  the sale of all of the royalty interests, (3)  the election of the Trustee following its resignation for cause (as more fully described in the  royalty trust agreement), (4) a vote of the holders of 80% (which after June 3, 2018, shall be reduced to 66 2⁄3 %) or more of the outstanding royalty trust units held by persons other than FCX or any of its affiliates, at a duly called meeting of the Royalty Trust unitholders at which a quorum is present, or (5) the exercise by FCX of the right to call all of the royalty trust units described in the next paragraph.  The 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 royalty interests to a third party pursuant to the terms of the royalty trust agreement (in which case the royalty interests may extend through June 3, 2033).





FCX Call Rights. FCX will maintain a call right with respect to the outstanding royalty trust units at $10 per royalty trust unit, provided that the call right may not be exercised prior to June 3, 2018.  In addition, at any time after June  3,  2018, 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 of such nine-month period.





Resignation of Trustee. The Trustee may resign, with or without cause, at any time by 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 the receipt by FCX of such notice, the annual fee payable to the Trustee will be increased as of the end of such 90-day period by 5%, 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) at any time that 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 royalty interests and to dissolve, windup and terminate the Royalty Trust.





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 under the lease. In contrast, 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 applicable operating agreements, 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. Generally, an owner of an overriding royalty interest 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 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


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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 neither McMoRan nor FCX 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 other like 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. Each quarter, the Trustee determines the amount of funds available for distribution to the Royalty Trust unitholders. Available funds will equal the excess cash received by the Royalty Trust from the royalty interests and other sources during that quarter over the Royalty Trust’s liabilities for that quarter. In any event, no distributions will be made until such time as the Trustee receives cash proceeds from the royalty interests. Available funds will be reduced by any cash the Trustee determines to hold as a reserve against future liabilities. The Trustee shall establish a cash reserve equal to such amount. 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 made 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 will 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 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 on 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 royalty trust agreement also requires FCX or McMoRan to provide to the Royalty Trust such other information available to FCX or McMoRan concerning the royalty interests and the subject interests burdened by the 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 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 by FCX or McMoRan without investigation and are fully protected and shall incur no liability in doing so. However, neither FCX nor McMoRan nor their affiliates may be required to disclose, produce or prepare any information, documents or other materials which were generated for analysis or discussion purposes or 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.





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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 corporations for profit under the Delaware General Corporation Law. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.





Uncertificated Interests; Transfer Agent .  The royalty trust units are uncertificated, and ownership 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 American Stock Transfer & 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” consist of 20 specified shallow water ILTC (target depths generally greater than 18,000 total vertical depth) exploration prospects located on the Shelf of the Gulf of Mexico and onshore South Louisiana. The offshore “subject interests” consist 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” consist of the following exploration prospects: (1) Highlander; (2) Lineham Creek; and (3) Tortuga. McMoRan does not own 100% of the working interest of any of the subject interests.  The royalty interests in future production from the subject interests burden all of McMoRan's initial leasehold interests associated with such prospects, and will burden any leasehold interests associated with such prospects which are acquired by McMoRan on or before December 5, 2017 up to the working interests in the table below (subject to McMoRan's right to dispose of a portion of the working interest to a percentage not less than the estimated working interests reflected in the table below).  Each of the royalty interests has been, or will be, proportionately reduced based on McMoRan's working interest to equal the product of 5% multiplied by a fraction, the numerator of which is the working interest held by McMoRan and its affiliates in the applicable subject interest (subject to a cap equal to McMoRan's estimated working interest (equal to the working interest McMoRan owns or expects to acquire and as estimated in the table below) in each subject interest, on a prospect by prospect basis) and the denominator of which is 100%.  As of December 5, 2012, the date FCX agreed to acquire MMR, the subject interests comprised all of McMoRan's ILTC prospects.





Currently, none of the subject interests have any reserves classified as proved, probable or possible (other than the onshore Lineham Creek subject interest) and none of the subject interests have any associated production. Additional ILTC prospects developed by McMoRan hereafter (other than those reflected below) will not be included in the subject interests.  Approximately 0.7 Bcfe of estimated proved reserves in sands encountered above 24,000 feet are currently deemed attributable to the Royalty Trust's 1.8% overriding royalty interest (the applicable royalty interest proportionately reduced to reflect McMoRan's estimated working interest) in the onshore Lineham Creek subject interest.


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Information concerning McMoRan's estimated working interests and the Royalty Trust's estimated overriding royalty interests for each of the subject interests as of December 31, 2013 is set forth below.


Subject Interest NameMcMoRan's EstimatedWorkingInterest Related to theSubjectInterestsOperatorRoyalty Trust's EstimatedOverridingRoyalty Interests(5% proportionatelyreduced to reflectthe EstimatedWorking Interest)Davy Jones63.4%McMoRan3.17%Blackbeard East72%McMoRan3.6%Lafitte(a)—McMoRan—Blackbeard West69.4%McMoRan3.47%England(b)36%Chevron1.8%Barbosa72%McMoRan3.6%Morgan(c)—McMoRan—Barataria72%McMoRan3.6%Blackbeard West #369.4%McMoRan3.47%Drake72%McMoRan3.6%Davy Jones West36%McMoRan1.8%Hurricane72%McMoRan3.6%Hook72%McMoRan3.6%Captain Blood72%McMoRan3.6%Bonnet72%McMoRan3.6%Queen Anne's Revenge72%McMoRan3.6%Calico Jack36%McMoRan1.8%Highlander72%McMoRan3.6%Lineham Creek36%Chevron1.8%Tortuga72%McMoRan3.6%





(a)     In June 2013 McMoRan requested from the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE) that its then pending request for the issuance of a Suspension of Production (SOP) lease extension for the Lafitte unit properties be returned without action, which effectively relinquished McMoRan's lease rights to the Lafitte unit. In the event on or before December 5, 2017, McMoRan acquires one or more leasehold interests covering the same area and blocks covered by the terminated leases, such newly acquired leasehold interests shall become subject interests, and if this were to occur, it is expected that McMoRan would hold an approximate 72% working interest in such reacquired leases, equating to an estimated overriding royalty interest of 3.6% to be held by the Royalty Trust.  On March 19, 2014, McMoRan was published as the apparent high bidder in the Central Gulf of Mexico Oil and Gas Lease Sale 231 for the lease rights to Eugene Island 223 (associated with the offshore Lafitte subject interest). The bid is subject to approval by the Bureau of Ocean Energy Management (BOEM) (see Note 7).





(b)    On March 19, 2014, McMoRan was published as the apparent high bidder in the Central Gulf of Mexico Oil and Gas Lease Sale 231 for the lease rights to Vermillion 17, 38 and 39 (associated with the offshore England subject interest). The bids are subject to approval by the BOEM (see Note 7).





(c)     McMoRan's rights to the Morgan lease expired on May 31, 2013. In the event on or before December 5, 2017, McMoRan acquires a leasehold interest covering the same area and block covered by the terminated lease, such newly acquired leasehold interest shall become a subject interest, and if this were to occur, it is expected that McMoRan would hold an approximate 72% working interest in such reacquired lease, equating to an estimated overriding royalty interest of 3.6% to be held by the Royalty Trust.








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The Royalty Trust has no ability to influence the exploration or development of the subject interests. In addition, neither FCX nor McMoRan are under any obligation to fund or to commit any other resources to the exploration or development of any of the subject interests. In addition, FCX has the right to elect not to participate in drilling or other operations conducted by other working interest owners with respect to the subject interests.





Exploratory and Development Drilling.  There were no net productive or dry exploratory or development wells associated with the subject interests drilled during 2013. There were seven gross (four net) in-progress and/or suspended wells associated with the subject interests at December 31, 2013.





McMoRan has an industry leading position in the emerging shallow-water ILTC natural gas trend, located on the Shelf of the Gulf of Mexico and onshore South Louisiana. McMoRan has a significant onshore and offshore lease acreage position with high-quality prospects and the potential to develop a significant long-term, low-cost source of natural gas. Data from eight wells drilled to date indicate the presence of geologic formations that are analogous to productive formations in the Deepwater Gulf of Mexico and onshore in the Gulf Coast region. McMoRan’s near-term focus is on defining the trend onshore.  For information regarding the re-acquisition of the lease rights associated with the offshore Lafitte subject interest, see Note 7.





As described below, McMoRan is currently completing two ILTC exploration prospects, including one onshore well, and plans to perform production tests on these two wells and a third well in 2014.





The Lomond North exploratory well within the Highlander area located in St. Martin Parish, Louisiana, has encountered gas pay in several Wilcox and Cretaceous aged sands between 24,000 feet and 29,000 feet. Wireline log and core data obtained from the Wilcox and Cretaceous sand packages evaluated indicate favorable reservoir characteristics with approximately 150 feet of net pay. The Lomond North discovery well is currently in completion operations to test lower Wilcox and Cretaceous objectives found below the salt weld. McMoRan has identified multiple exploratory prospects in the Highlander area, where it controls rights to approximately 56,000 gross acres.





During 2013, McMoRan commenced completion operations at Davy Jones No. 2, located on South Marsh Island Block 234. Flow testing is anticipated in the first half of 2014. During 2014, McMoRan also plans to complete the Blackbeard West No. 2 well located on Ship Shoal Block 188. The Lineham Creek exploration well located in Cameron Parish has been suspended while future plans are developed.





Acreage . At December 31, 2013, McMoRan owned or controlled (through options to lease) interests in approximately 1,498 oil and gas leases in the Gulf of Mexico and onshore Louisiana, covering approximately 338,000 gross acres (212,000 acres net to McMoRan's interests), associated with McMoRan's ILTC prospects, all of which are part of the subject interests. Approximately 40,000 net acres associated with the subject interests are scheduled to expire in 2014, a portion of which McMoRan expects to retain by drilling operations or other means.





The following table reflects the oil and gas acreage associated with the subject interests for which McMoRan owned rights to the related leases as of December 31, 2013. (a)


DevelopedUndevelopedGrossNetGrossNetAcresAcresAcresAcresOffshore (federal waters)——228,739144,284Onshore Louisiana——57,19429,890Total at December 31, 2013——285,933174,174


(a)  In addition, McMoRan controls approximately 52,400 gross acres (37,300 net acres).





Oil and Gas Reserves .  Proved reserves represent quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate.  Estimated proved oil and natural gas reserves attributable to the Royalty Trust’s 1.8% overriding royalty interest (the applicable royalty interest proportionately reduced to reflect McMoRan’s estimated working interest) in the onshore Lineham Creek subject interest totaled 0.7 Bcfe at December 31, 2013, 94% of which was represented by natural gas reserves.


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The proved reserve estimates associated with the subject interests were prepared by Ryder Scott Company, L.P. (Ryder Scott), an independent petroleum engineering firm, in accordance with the current regulations and guidelines established by the SEC.  To achieve reasonable certainty, Ryder Scott employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of the proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests.  Among other things, the accuracy of the estimates of the reserves is a function of:





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|• | the quality and quantity of available data and the engineering and geological interpretation of that data;




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|• | estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results;




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|• | the accuracy of various mandated economic assumptions such as future prices of oil and natural gas; and




• the judgment of the persons preparing the estimates.





The scope and results of the procedures employed by Ryder Scott are summarized in a letter that is filed as an exhibit to this Form 10-K.  Ryder Scott employs a primary technical person who is responsible for overseeing the preparation of the reserve estimates referred to above. This individual has a Bachelor of Science degree in Chemical Engineering and is a Licensed Professional Engineer in the State of Texas. Additionally, this individual has over nine years of experience in the estimation and evaluation of petroleum reserves and has attained the professional qualifications as a Reserve Estimator set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The technical personnel responsible for preparing the reserve estimates at Ryder Scott meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists that owns no interest in the subject interests, and is not employed on a contingent fee basis.





The internal controls applicable to the foregoing estimates of proved reserves attributable to the subject interests are those employed by McMoRan, which provides reserve related data and other information to Ryder Scott. The Trustee has been advised by McMoRan that it maintains an internal staff of reservoir engineers and geoscientists who work closely with Ryder Scott in connection with their preparation of reserve estimates attributable to the subject interests, including assessing the integrity, accuracy and timeliness of the methods and assumptions used in this process. The activities of McMoRan’s internal staff are led and overseen by the Vice President of Engineering of FM O&G, who has over 37 years of technical experience in petroleum engineering and reservoir evaluation and analysis.  This individual directs the activities of McMoRan’s internal reservoir staff to provide the appropriate data to Ryder Scott in support of the reserve estimation process.





Because oil and gas reserve estimates depend on many assumptions, any or all of which may differ substantially from actual results, such reserve estimates may be different from the quantities of oil and natural gas that is ultimately recovered.





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The following table discloses estimated proved reserves attributable to the Royalty Trust’s 1.8% overriding royalty interest (the applicable royalty interest proportionately reduced to reflect McMoRan’s estimated working interest) in the onshore Lineham Creek subject interest as of December 31, 2013. The reserve volumes were determined using the methods prescribed by the SEC, which require the use of an average price, calculated as the twelve-month average of the first-day-of-the-month historical reference prices as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based on future conditions (twelve-month average price).


GasOilTotal(MMcf)(MBbls)(Bcfe)Proved developed———Proved undeveloped68770.7Total proved reserves68770.7





All of the proved reserves associated with Lineham Creek are proved undeveloped reserves. None of the proved reserves have been classified as proved undeveloped for more than five years. Proved undeveloped reserves were revised in 2013 resulting from additional drilling data obtained subsequent to McMoRan's contribution of the Lineham Creek subject interest to the Royalty Trust. See Note 8.





The following table reflects the present value of estimated future net cash flows before income taxes from the production and sale of estimated proved reserves associated with the subject interests reconciled to the standardized measure of discounted net cash flows as of December 31, 2013.


Proved ReservesDevelopedUndevelopedTotalEstimated undiscounted future net cash flows before income taxes$—$3,067,381$3,067,381Present value of estimated future net cash flows before income taxes (PV-10)(a), (b)$—$2,409,028$2,409,028Discounted future income taxes(c)—Standardized measure of discounted net cash flows$2,409,028


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|(a) | Calculated based on the twelve-month average of the first-day-of-the-month historical reference price for natural gas and oil during 2013 and costs prevailing at December 31, 2013 and using a 10% per annum discount rate as required by the SEC. The weighted average of these prices for all properties with proved reserves was $3.70 per thousand cubic feet (Mcf) of natural gas and $96.94 per barrel of oil at December 31, 2013.

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|(b) | Present value of estimated future net cash flows before income taxes (PV-10) is considered a non-GAAP (generally accepted accounting principles) financial measure as defined by the SEC. The Royalty Trust believes that the PV-10 presentation is relevant and useful to investors because it presents the discounted future net cash flows attributable to the subject interest's proved reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows (see Note 8).

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|(c) | For tax reporting purposes, the Royalty Trust is considered a non taxable "pass-through" entity (see Note 4).




Production and Productive Well Interests .  Currently, none of the subject interests have any associated production. In addition, there are no productive oil or natural gas wells, or wells capable of production, associated with the subject interests as of December 31, 2013. Since its inception, the Royalty Trust has received no proceeds from oil and gas production related to the subject interests.





REGULATION





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


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General . McMoRan’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. McMoRan 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 McMoRan’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. McMoRan’s oil and 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 gas properties.





Federal leases. As of December 31, 2013, there are 47 offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf relating to the subject interests. Federal offshore leases are administered by the BOEM. These leases were obtained through competitive bidding, contain relatively standard terms and require compliance with detailed BOEM regulations, BSEE regulations and the Outer Continental Shelf Lands Act (OCSLA), which are subject to interpretation and change. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard and the Environmental Protection Agency (EPA). BSEE has regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization.





BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. BSEE generally requires that lessees either have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that supplemental bonds or other surety can be obtained in all cases. McMoRan is currently satisfying the supplemental bonding requirements of BSEE by providing financial assurances. McMoRan’s ongoing compliance with applicable BSEE requirements will be subject to meeting certain financial and other criteria. Under some circumstances, BSEE could require any operations on federal leases to be suspended or terminated. Any suspension or termination of operations related to the subject interests for a prolonged duration would likely have a material adverse effect on the Royalty Trust’s future financial condition and results of operations.





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





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





Solid Waste. McMoRan’s operations require the disposal of both hazardous and nonhazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. In addition, the EPA and certain states in which McMoRan currently operates are presently in the process of developing stricter disposal standards for nonhazardous waste. Changes in these standards may impact McMoRan’s operations.





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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, McMoRan 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, McMoRan 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, McMoRan may be subject to cost recovery and to some other claims as a result of its operations.





Air. McMoRan’s operations are also subject to regulation of air emissions under the Clean Air Act, comparable state and local requirements and the OCSLA. The scheduled implementation of these laws could lead to the imposition of new air pollution control requirements on McMoRan's operations. Therefore, McMoRan may incur future capital expenditures to upgrade its air pollution control equipment.





Water. The Clean Water Act prohibits any discharge into waters of the United States except in strict conformance with permits issued by federal and state agencies. Failure to comply with the ongoing requirements of these laws or inadequate cooperation during a spill event may subject a responsible party to civil or criminal enforcement actions. 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. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. 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. The Oil Pollution Act requires parties responsible for offshore facilities to provide financial assurance in amounts that vary from $35 million to $150 million depending on a company’s calculation of its “worst case” oil spill. McMoRan currently maintains insurance on its respective facilities to meet the financial assurance obligations under the Oil Pollution Act.





Endangered Species. Several federal laws 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 McMoRan’s exploration, development, and production operations and impose civil or criminal penalties for noncompliance.





EMPLOYEES





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





COMPETITION





The production and sale of oil and natural gas in the shallow waters on the Shelf of the Gulf of Mexico and onshore 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. McMoRan’s competitors in these areas include major integrated oil and gas companies and numerous independent oil and gas companies, individual producers and operators.


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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.


If and to the extent that the subject interests begin to produce in commercial quantities, future price fluctuations for oil and natural gas will directly affect the amount of distributions to Royalty Trust unitholders, if any, and will also affect estimates of reserves attributable to the royalty interests and estimated and actual future net revenues of the Royalty Trust. Neither McMoRan nor the Royalty Trust can make reliable predictions of future oil and natural gas supply and demand, future product prices or the effects of future product prices on the Royalty Trust.


All of the Royalty Trust’s assets are located in the United States, where demand for natural gas is typically lower in summer than in the winter.  The Royalty Trust is not otherwise materially affected by seasonal factors.


TAX CONSIDERATIONS





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.





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. 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 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 2013 federal and state income tax returns. This tax information booklet can be obtained at  http://gultu.investorhq.businesswire.com/. 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.





The Royalty Trust owns an overriding royalty interest burdening the subject interests, which are located both in and outside 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


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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. The highest marginal rates for the payment of Louisiana income taxes are 6% for individuals, trusts and estates, and 8% for corporations. Individual taxpayers are allowed a deduction for depletion in Louisiana. Louisiana currently does not require the Royalty Trust to withhold Louisiana individual income taxes from distributions made to non-resident Royalty Trust unitholders. 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.


WHERE YOU CAN FIND OTHER INFORMATION





The Royalty Trust maintains a website at http://gultu.investorhq.businesswire.com. The Royalty Trust’s filings under the Exchange Act are available at 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.





The value of the royalty trust units is uncertain. To date there has been no production subject to the royalty interests; the subject interests are exploration concepts and, other than the onshore Lineham Creek subject interest, do not have proved, probable or possible reserves assigned to them.





The only assets and sources of income to the Royalty Trust are the royalty interests burdening the subject interests.  The royalty interests entitle the Royalty Trust to receive a portion of the proceeds derived from the sale of hydrocarbons from the subject interests, if any.  To the extent there is no production from the subject interests, the Royalty Trust receives no income. To date, there has been no production and no income attributable to the Royalty Trust.





While data from the eight ILTC wells drilled on the subject interests to date tie ILTC geologic formations encountered below the salt weld to productive zones encountered onshore, in the Deepwater Gulf of Mexico and in Mexico, only the Davy Jones No.  1 well has been completed and no commercial production has been established to date.  No other exploratory well in the subject interests has been completed.  As such, the subject interests remain “ exploration concepts ” and further drilling and flow testing will be required to determine the commercial potential of the subject interests. For information regarding the re-acquisition of the lease rights associated with the offshore Lafitte subject interest, see Note 7.





Currently, none of the subject interests have any proved, probable or possible reserves associated with them (other than the onshore Lineham Creek subject interest), and none of the subject interests have any associated production.  As such, it is possible that no production will be derived from the subject interests in the future, the result of which would be that the Royalty Trust would never receive any income from the subject interests, in which case the market value of the royalty trust units would be expected to be zero.





The Royalty Trust has no ability to direct or influence the exploration or development of the subject interests.  In addition, neither FCX nor McMoRan are under any obligation to fund or to commit any other resources to the exploration or development of the subject interests.





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The subject interests target ILTC formations in the shallow waters on the Shelf of the Gulf of Mexico and onshore South Louisiana, which have greater risks and costs associated with their exploration and development than conventional Gulf of Mexico prospects.





McMoRan's ILTC exploration prospects target formations below the salt weld on the Shelf of the Gulf of Mexico and onshore in South Louisiana. These targets have not traditionally been the subject of exploratory activity in these regions, and, therefore, little direct comparative data is available. To date, there has been no production of hydrocarbons from ILTC reservoirs in these areas. 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. Wells drilled in these formations are also significantly more expensive to drill and complete than wells drilled to more conventional depths. Major contributors to such increased costs 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. Consequently, drilling these types of wells is unusually expensive and risky.





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 currently are quoted on the OTCQX tier of the OTC market (a U.S. over-the-counter, or an inter-dealer market) (OTCQX). The OTCQX is a significantly more limited market than the national securities exchanges, which could affect the market price, trading volume, liquidity and resale price of the royalty trust units. The Royalty Trust will use its commercially reasonable best efforts to cause the royalty trust units to be listed on a national securities exchange upon satisfaction of the applicable listing criteria but the royalty trust units may not be accepted for listing on a national securities exchange.





There is limited trading history in the royalty trust units, and although the royalty trust units are currently quoted on the OTCQX, 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 OTCQX 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 subject interests to produce hydrocarbons;




|  |                                                                                                                       
|- | ----------------------------------------------------------------------------------------------------------------------
|• | decisions by McMoRan to delay or not to pursue the exploration or development of some or all of the subject interests;




|  |                                                                                                                                                                           
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | 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 McMoRan; and




|  |                                                              
|- | -------------------------------------------------------------
|• | general economic, securities markets and industry conditions.




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 from their royalty trust units when they determine to sell them or may have to hold them for a substantial period of time until the market for the royalty trust units improves. FCX has a call right with respect to the outstanding royalty trust units at $10 per royalty trust unit, provided that the call right may not be exercised prior to June 3, 2018. This call right could impose a ceiling on the price of the royalty trust units. See Part I, Items 1. and 2. “Business and Properties - The Royalty Trust - The Royalty Trust Agreement - FCX Call Rights” of this Form 10-K. In addition, Royalty Trust


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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 the holder from the resale of its royalty trust units.





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 well developed in the area of overriding royalty interests on exploration prospects that are not classified as proved, probable or possible reserves and are undeveloped wells that may be drilled in the future.  As a result, there is uncertainty as to the proper tax treatment of the 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 as of the date hereof, the Royalty Trust intends 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.





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 your particular circumstances.





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 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 costly to implement and maintain, and any distributions to Royalty Trust unitholders could be reduced as a result.





If the 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, and the Royalty Trust cannot assure that the IRS will not challenge these positions on audit or that a court would not sustain such a challenge.





No assurance can be given with respect to the availability and extent of percentage depletion deductions to the Royalty Trust unitholders for any taxable year.





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 oil or gas property.  As a result, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the Royalty Trust unitholders for any taxable year.





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.





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Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.





Among the changes included in President Obama's Budget Proposal for Fiscal Year 2015 is the elimination of certain key U.S. federal income tax preferences relating to oil and natural gas exploration and production.  The President's budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources.  Specifically, the budget proposes to repeal the deduction for percentage depletion with respect to wells, including interests such as the royalty interests, in which case only cost depletion would be available.





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.





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.  While the Royalty Trust, as the owner of the 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.





In the event McMoRan is unable to procure or maintain the suspension of operations (SOO) granted by the BSEE with respect to certain of its ILTC gas play acreage associated with the subject interests, McMoRan's ability to exploit some of the potentially valuable acreage associated with its ILTC gas play and the subject interests could be adversely affected.





McMoRan's interests in the offshore leases located in federal waters on the Gulf of Mexico's outer continental shelf are administered by the BOEM and the BSEE and require compliance with BOEM and BSEE regulations and the OCSLA. Under the OCSLA, McMoRan is required to promptly and efficiently explore and develop any block or blocks to which these federal leases pertain within the initial term of such lease.





During the initial term of a lease, McMoRan's ability to drill, rework, or produce a particular well in paying quantities may, despite McMoRan's diligent efforts, be delayed. In this case, McMoRan has the ability to request that the BSEE extend the lease term beyond its scheduled expiration or termination. Provided McMoRan's request in this regard is made timely and in accordance with regulatory guidelines, the BSEE may grant or direct an SOO on the condition that McMoRan commit to undertake or complete certain specified actions during the extended term. While the decision of the BSEE to grant or direct an SOO is made on a case-by-case basis, an SOO, if granted, is of limited duration.





Approximately 40,000 net acres associated with the subject interests are scheduled to expire in 2014.





While it is not uncommon for companies in the oil and gas industry to continue to operate leases under an SOO granted by the BSEE, in the event (1) McMoRan fails to satisfy any obligations or conditions set forth in an SOO with respect to a particular lease, (2) McMoRan is unable to procure an SOO from the BSEE prior to the expiration of a primary lease term, (3) the BSEE denies a request to grant an additional SOO (or an extension of an existing SOO) with respect to a particular lease, or (4) the BSEE terminates an SOO previously granted based on a determination that either the circumstances justifying the SOO no longer exist or that the lease otherwise now warrants termination, McMoRan's ability to exploit some of the potentially valuable acreage associated with its ILTC gas play and the subject interests could be adversely affected.





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The Royalty Trust is vulnerable to risks associated with operations in the Gulf of Mexico and onshore in the Gulf Coast area because the subject interests are located exclusively in those areas.





These risks include:





|  |                                                                                                                                                                                                                                                                                                                                                      
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | tropical storms and hurricanes, which are particularly common in the Gulf of Mexico and the Gulf Coast area 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;




|  |                                                                                                                                               
|- | ----------------------------------------------------------------------------------------------------------------------------------------------
|• | 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 in the Gulf of Mexico and the Gulf Coast area could have a material adverse effect on the subject interests, on the Royalty Trust's results of operations and financial condition, and on the market price of the Royalty Trust units.





Any future distributions from the Royalty Trust will be subject to fluctuating prices for oil and gas.





Oil and 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 FCX, McMoRan and the Royalty Trust.  To the extent there is production of oil and gas associated with the royalty interests, the royalties that the Royalty Trust may receive from its share of production will be affected by changes in the prices of oil and gas.  As a result, future distributions, if any, from the Royalty Trust to its unitholders could be reduced or discontinued.  In addition, lower oil and gas prices may reduce the likelihood that the subject interests will be developed or that any oil and gas discovered will be economic to produce.  The volatility of energy prices reduces the accuracy of estimates of future cash distributions to the Royalty Trust unitholders and the value of the royalty trust units.





The Royalty Trust is entirely dependent on FCX for funding unless and until such time as it may receive income from any production on the subject interests, and even if the Royalty Trust receives income from production on the subject interests, any such income may be insufficient to cover the Royalty Trust's administrative expenses.





Because none of the subject interests currently have any associated production, the Royalty Trust currently has no source of income. Therefore, it must rely on FCX for funding of its administrative expenses. Pursuant to the royalty trust agreement, FCX has agreed to pay annual trust expenses up to a maximum amount of $350,000, with no right to repayment or interest due, to the extent the Royalty Trust lacks sufficient funds to pay administrative expenses. In addition to such annual contribution, 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. Any material adverse change in FCX’s financial condition or results of operations could materially and adversely affect the Royalty Trust and the Royalty Trust unitholders.





The Royalty Trust’s 2013 administrative expenses exceeded its funds available to pay such administrative expenses.  In accordance with the royalty trust agreement, during the year ended December 31, 2013, FCX deposited $350,000 into the Royalty Trust's operating cash account to cover portions of its administrative and other expenses, representing FCX's maximum annual contribution for reimbursement of such expenses with no right of repayment or interest due, and all of such funds were utilized to pay administrative expenses. In addition to its contribution of $350,000 to the Royalty Trust, FCX loaned $450,000, on an unsecured, interest-free basis, to the Royalty Trust to cover additional administrative expenses incurred during 2013.  Such funds borrowed by the Trustee to cover expenses or liabilities rank in priority to Royalty Trust unitholder distributions, and the Royalty Trust unitholders will not receive any distributions until all borrowed funds are repaid.  The amount borrowed by the Royalty Trust from FCX as of December 31, 2013 totaled $450,000.





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FCX's interests and the interests of the Royalty Trust unitholders may not always be aligned.





Because FCX has interests in oil and gas properties not included in the subject interests, FCX'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 FCX's properties, including the subject interests, FCX may make decisions that could adversely affect future production from the subject interests.  Moreover, FCX could decide to sell or abandon some or all of the subject interests, and any such decision would not be in the best interests of the Royalty Trust unitholders.





FCX may transfer or abandon the subject interests.





FCX may at any time transfer all or part of the subject interests.  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 interests.  Following any such transfer, the subject interests would continue to be subject to the royalty interests, but the net proceeds from the transferred subject interests would be calculated separately and paid by the transferee.  The transferee would be responsible for all of FCX's obligations relating to the royalty interests on the portion of the subject interests transferred, and FCX would have no continuing obligation to the Royalty Trust for those subject interests.





The Royalty Trust is limited in duration, may be dissolved upon certain events and the royalty trust units are subject to call features after June 3, 2018.





The Royalty Trust will dissolve on the earlier of (i)  June 3, 2033, (ii)  the sale of all of the royalty interests, (iii)  upon the election of the Trustee following its resignation for cause (as more fully described in the royalty trust agreement), (iv) upon a vote of the holders of 80% (which after June 3, 2018, shall be reduced to 66 2⁄3 %) or more of the outstanding royalty trust units held by persons other than FCX or any of its affiliates, 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 described in the next paragraph.  The 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 royalty interests to a third party pursuant to the terms of the royalty trust agreement (in which case the royalty interests may extend through June 3, 2033).





FCX has a call right with respect to the outstanding royalty trust units at $10 per royalty trust unit, provided that the call right may not be exercised prior to June 3, 2018.  In addition, at any time after June  3,  2018, if 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 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 FCX or MMR or to control the development or operation of the subject interests.


The royalty trust units are a passive investment that entitle the Royalty Trust unitholders only to receive cash distributions, if any, from the royalty interests. Royalty Trust unitholders have no voting rights with respect to FCX or MMR and, therefore, have no managerial, contractual or other ability to influence their activities or the development or operations of the subject interests. Additionally, FCX is under no obligation to fund or to commit any resources to the exploration or development of the subject interests.





FCX may sell royalty trust units in the public or private markets, and any such sales would be highly likely to have a material adverse effect on the trading price of the royalty trust units.


FCX holds an aggregate of 62,285,438 royalty trust units, representing approximately 27.1% of the outstanding royalty trust units.  FCX may sell royalty trust units in the public or private markets.  Any such sales would be highly likely to have a material adverse effect on the trading price of the royalty trust units.  A small number of other unitholders also hold significant percentages of the outstanding royalty trust units, and sales by such holders could also 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 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 so long as it holds a significant percentage of the total royalty trust units.


Item 1B.  Unresolved Staff Comments





None.





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 currently are not listed on a national securities exchange; however, the Royalty Trust will use its commercially reasonable best efforts to cause the royalty trust units to be listed on a national securities exchange upon satisfaction of applicable listing criteria. Since October 10, 2013, the royalty trust units have been quoted on the OTCQX tier of the OTC markets (the “ OTCQX ” ) under the symbol “ GULTU ” .  Previously, between June 4, 2013 (the date of initial trading) and October 9, 2013, the royalty trust units were quoted on the Over-the-Counter Bulletin Board (the “ OTCBB ” ).  The following table shows the high and low sales prices per royalty trust unit as reported on the OTCQX and the OTCBB for the periods indicated.  Quotations on the OTCQX and the OTCBB reflect bid and ask quotations, may reflect inter-dealer prices, without retail markup, markdown or commission, and may not represent actual transactions.   There have been no distributions from the royalty trust to date.





2013HighLowFirst Quartern/an/aSecond Quarter$2.50$1.75Third Quarter2.352.00Fourth Quarter2.442.01





As of February 28, 2014 there were 230,172,696 royalty trust units outstanding and 5,606 Royalty Trust unitholders of record.





Recent Sales of Unregistered Securities and Related Royalty Trust Unitholder Matters


On June 3, 2013, the Royalty Trust issued 230,172,696 royalty trust units. Of this amount, 129,216,862 royalty trust units were ultimately delivered to former holders of MMR common stock as merger consideration, and the remaining 100,955,834 royalty trust units were held by McMoRan, including 38,805,688 royalty trust units (approximately 16.9% of the total number of royalty trust units outstanding), which McMoRan, on behalf of FCX, held for delivery to holders of certain convertible securities of MMR upon conversion. At December 31, 2013 there


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were no MMR convertible securities outstanding, and FCX, through its wholly-owned subsidiary McMoRan, held 62,285,438 royalty trust units. FCX is currently the largest holder of royalty trust units with approximately 27.1% of the outstanding royalty trust units.





Securities Authorized for Issuance Under Equity Compensation Plans


None.





Issuer Purchases of Royalty Trust Units by the Issuer and Affiliated Purchasers


None.





Item 6.  Selected Financial Data





The following table sets forth selected audited historical financial data of the Royalty Trust for the period December 18, 2012 (inception) through December 31, 2012 and for the year ended December 31, 2013.  The historical information shown in the table below may not be indicative of the Royalty Trust’s future results.  You should read the information below together with Part II, Items 7. and 7A. “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk” and Part II, Item 8. “Financial Statements and Supplementary Data” of this Form 10-K.  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.


20132012Financial DataPeriods Ended December 31:Royalty income$—$—Interest income4—Administrative expenses(606,163)—Administrative expenses in excess of income(606,159)—Distributable income$—$—At December 31:Overriding royalty interests in subject interests$400,300,341$—Total assets$401,494,215$10Trust corpus$400,044,192$10Royalty Trust units outstanding230,172,696—





Items 7. and 7A.  Trustee’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk





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 the Royalty Trust’s future operating results. All subsequent 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. Additionally, please refer to the section entitled “Forward-Looking Statements” in Part I of this Form 10-K.





On June 3, 2013, Freeport-McMoRan Copper & Gold Inc. (FCX) and McMoRan Exploration Co. (MMR) completed the transactions contemplated by an 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, on June 3, 2013, Merger Sub merged with and into MMR, with MMR surviving the merger as an indirect wholly owned subsidiary of FCX (the merger).





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The Royalty Trust was created as contemplated by the merger agreement, and is a statutory trust created by FCX under the Delaware Statutory Trust Act pursuant to a trust agreement entered into on December 18, 2012, between 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 Royalty Trust’s 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 royalty interests) in future production from each of McMoRan Oil & Gas LLC's (McMoRan) shallow water Inboard Lower Tertiary/Cretaceous (ILTC, previously referred to as ultra-deep) exploration prospects located on the Shelf of the Gulf of Mexico and onshore 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 that were acquired by FCX pursuant to the merger and were not considered part of FCX's purchase consideration of MMR. McMoRan owns less than 100% of the working interest in each of the subject interests. FCX's portfolio of oil and gas assets is held through its wholly owned subsidiary, Freeport-McMoRan Oil & Gas LLC (FMO&G). MMR and McMoRan are wholly owned subsidiaries of FMO&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 interest (the master conveyance) pursuant to which McMoRan conveyed to the Royalty Trust the royalty interests in future production from the subject interests. Other than its formation, its receipt of contributions and loans from FCX for administrative and other expenses as provided for in the royalty trust agreement, its payment of such administrative expenses and its receipt of the conveyance of the royalty interests from McMoRan pursuant to the master conveyance, 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.





Since 2008, McMoRan's ILTC drilling activities (below the salt weld, i.e., the listric fault) have confirmed McMoRan's belief relating to its geologic model and the highly prospective nature of this emerging geologic trend.  Data from eight ILTC wells drilled to date indicate the presence of geologic formations that are analogous to productive formations in the Deepwater Gulf of Mexico and onshore in the Gulf Coast region.  Each of these eight wells was included in the subject interests, along with additional exploration prospects that will also be burdened by the royalty interests.  No commercial production has been established to date.  As such, the subject interests are considered “exploration concepts” and further drilling and flow testing will be required to determine the commercial potential of the subject interests. For information regarding the re-acquisition of the lease rights associated with the offshore Lafitte subject interest, see Note 7.





Currently, none of the subject interests have any reserves classified as proved, probable or possible associated with the subject interests (other than the onshore Lineham Creek subject interest), and none of the subject interests have any associated production. The Royalty Trust has no ability to direct or influence the exploration or development of the subject interests.  In addition, neither FCX nor McMoRan are under any obligation to fund or to commit any resources to the exploration or development of the subject interests.  If McMoRan does not fund the exploration and development of the subject interests, or if for any other reason production from the subject interests in commercial quantities is not established or maintained, Royalty Trust unitholders would lose their investment in the royalty trust units.





North American Natural Gas and Crude Oil Market Prices





Market prices for natural gas and crude oil can fluctuate significantly. During the period from January 2004 through February 2014, the New York Mercantile Exchange (NYMEX) natural gas price fluctuated from a low of $2.04 per million British thermal units (MMBtu) in 2012 to a high of $13.91 per MMBtu in 2005 and the West Texas Intermediate (WTI) crude oil price ranged from a low of $32.48 per barrel in 2004 to a high of $145.29 per barrel in 2008. Crude oil and natural gas prices are affected by numerous factors beyond McMoRan's control as described further in Part I, Item 1A. "Risk Factors" of this Form 10-K. The following graph presents the NYMEX natural gas prices and the WTI crude oil prices from January 2004 through February 2014.





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OPERATIONAL ACTIVITIES





Oil and Gas Activities


For additional information regarding McMoRan’s current oil and gas activities in relation to the Royalty Trust’s subject interests, see - 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


Currently, none of the subject interests associated with the Royalty Trust have any related production. In addition, there are no productive oil or natural gas wells, or wells capable of production, as of December 31, 2013. The Royalty Trust has received no proceeds from oil and gas production related to the subject interests.





Acreage Position


For information regarding McMoRan’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





Currently, none of the subject interests associated with the Royalty Trust have any reserves classified as proved, probable or possible (other than the onshore Lineham Creek subject interest) and none of the subject interests have any associated production. As a result, the Royalty Trust has received no proceeds from oil and gas production from the subject interests since its inception. For the year ended December 31, 2013, the Royalty Trust paid administrative expenses of $606,163, which consisted primarily of legal and accounting expenses incurred in connection with the formation and administration of the Royalty Trust. The Royalty Trust paid no administrative expenses in 2012.





LIQUIDITY AND CAPITAL RESOURCES





Because none of the subject interests currently have any associated production, the Royalty Trust currently has no source of income.  Pursuant to the royalty trust agreement, FCX has agreed to pay annual trust expenses up to a maximum amount of $350,000, with no right to repayment or interest due, to the extent the Royalty Trust lacks sufficient funds to pay administrative expenses. In addition to such annual contribution, FCX has agreed to lend money, on an unsecured, interest-free basis, to the Royalty Trust to fund the Royalty Trust’s ordinary


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administrative expenses as set forth in the royalty trust agreement.





In accordance with the royalty trust agreement, during the year ended December 31, 2013, FCX deposited $350,000 into the Royalty Trust's operating cash account to cover portions of its administrative and other expenses, representing FCX's maximum annual contribution for reimbursement of such expenses with no right of repayment or interest due, and all of such funds were utilized to pay administrative expenses.  In addition to its contribution of $350,000 during the year ended December 31, 2013, FCX loaned $450,000, on an unsecured, interest-free basis, to the Royalty Trust to cover additional administrative expenses incurred during 2013, and $193,851 of such funds remained in operating cash as of December 31, 2013. The amount borrowed from FCX as of December 31, 2013 totaled $450,000.





Pursuant to the royalty trust agreement, FCX agreed to provide and maintain a $1.0 million stand-by reserve account or 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 in the event that the Royalty Trust had inadequate funds to pay the Royalty Trust's obligations at any time. After the one-year anniversary of the date of the royalty trust agreement, 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, which may be reduced from time to time with the consent of the Trustee.





The Royalty Trust has no source of liquidity or capital resources other than contributions, loans and establishment of reserves from FCX. Any material adverse change in FCX's financial condition or results of operations could materially and adversely affect the Royalty Trust and the Royalty Trust unitholders.





Off-Balance Sheet Arrangements


The Royalty Trust has no off-balance sheet arrangements. The Royalty Trust has not guaranteed the debt of any other party, nor does the Royalty Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.





CONTRACTUAL OBLIGATIONS


A summary of the Royalty Trust’s contractual obligations as of December 31, 2013 is provided in the following table:


Payments Due by Year20142015201620172018After 2018Total(in thousands)Trustee Administrative Fee(a)$150$150$150$150$150(a)(a)Total(a)$150$150$150$150$150(a)(a)


(a)  The Trustee Administrative Fee compensates the Trustee for performance of the Trustee’s duties and responsibilities related to the administration of the Royalty Trust, including usual and customary ministerial duties, preparation and filing of all SEC reports and press releases, record keeping, document compliance, coordination with the transfer agent as it relates to distributions and other related duties and maintenance of accounts on various systems.   The Trustee will be paid the sum of $150,000 per year until the first year in which the Royalty Trust receives any payment pursuant to the conveyances of the royalty interests, at which time such sum shall be increased to $200,000 per year.


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CRITICAL ACCOUNTING POLICIES AND ESTIMATES





The financial statements of the Royalty Trust are prepared on a modified cash basis and are not intended to present the Royalty Trust’s financial position and results of operations in conformity with U.S. generally accepted accounting principles.  This other comprehensive basis of accounting corresponds to the accounting and reporting rules permitted for royalty trusts by the SEC, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. There has been no distributable income paid or due to the Royalty Trust unitholders from inception through December 31, 2013.





As required for financial reporting purposes, the amount recorded in the accompanying financial statements for the overriding royalty interests conveyed to the Royalty Trust was derived from the actual number of royalty trust units issued, MMR's $16.75 per share closing price for its common stock on June 3, 2013, the closing date of the merger, and the related implied initial value of the royalty trust units of approximately $400.3 million. Application of income tax requirements resulted in a different per royalty trust unit value for tax reporting purposes of the Royalty Trust unitholders.


The initial value of the Royalty Trust’s overriding royalty interests in the subject interests of $400.3 million will be amortized using the units of production method based on proved reserves, on an individual subject interest basis, once production has been established for the respective subject interests. Such non-cash amortization will be charged directly to the Royalty Trust Corpus, and will not affect distributable cash or the determination of distributable cash per royalty trust unit.


The Trustee 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 such royalty interests. Indications of potential impairment with respect to such 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, exploitation costs, and/or drilling plans, and other matters that arise that could negatively impact the Royalty Trust’s carrying values of the royalty interests. When such royalty interests are deemed impaired, the related impairment amounts are charged to the Royalty Trust Corpus in the period such impairment is determined. No impairment charges were recorded in the financial statements accompanying this Form 10-K.





DISCLOSURES ABOUT MARKET RISKS





The Royalty Trust is a passive entity and, except for the Royalty Trust’s ability to borrow from FCX as necessary to pay liabilities of the Royalty Trust that cannot be paid with cash on hand, the Royalty Trust is prohibited from engaging in loan transactions. The Royalty Trust periodically holds short-term investments acquired with funds held by the Royalty Trust for the payment of its administrative and other expenses. Because of the short-term nature of these investments and limitations on the types of investments which may be held by the Royalty Trust, the Royalty Trust is not subject to any material interest rate risk. The Royalty Trust does not engage in transactions in foreign currencies which could expose the Royalty Trust unitholders to foreign currency related market risk nor does the Royalty Trust engage in any other financial derivative transactions.





Any future revenue from the royalty interests will be subject to both fluctuations in production and sales prices of crude oil and natural gas. Sales prices can vary significantly with fluctuations in the market prices of these commodities.  Any future production will be subject to uncertainties, many of which will be beyond McMoRan’s control, including the timing and flow rates associated with the initial production from discoveries, weather-related factors, shut-in or recompletion activities on any of the subject interests’ related properties or on third-party owned pipelines or facilities and the state of the financial and commodity markets. Any of these factors, among others, could materially affect estimated annualized sales volumes. For more information regarding risks associated with oil and gas production and commodity price fluctuations, see Part I, Item 1A. “Risk Factors” of this Form 10-K.





NEW ACCOUNTING STANDARDS





The Trustee does not expect the provisions of any recently issued accounting standards to have a significant impact on the Royalty Trust’s future financial statements and disclosures.











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Item 8.  Financial Statements and Supplementary Data





REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





TO THE TRUSTEE AND HOLDERS OF ROYALTY TRUST UNITS


OF GULF COAST ULTRA DEEP ROYALTY TRUST:





We have audited the accompanying statements of assets, liabilities and trust corpus of Gulf Coast Ultra Deep Royalty Trust (the Royalty Trust) as of December 31, 2013 and 2012, and the related statements of distributable income and changes in trust corpus for the year ended December 31, 2013 and the period from December 18, 2012 (inception) through December 31, 2012. 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 these financial statements based on our audits.





We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.





As described in Note 1 to 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.





In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the Royalty Trust at December 31, 2013 and 2012, and the distributable income and changes in trust corpus for the year ended December 31, 2013 and the period from December 18, 2012 (inception) through December 31, 2012, in conformity with the modified cash basis of accounting described in Note 1.








/s/ Ernst & Young LLP





New Orleans, Louisiana


March 31, 2014





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GULF COAST ULTRA DEEP ROYALTY TRUST


STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS





December 31,20132012ASSETSOperating cash$193,851$10Reserve Fund cash1,000,023—Overriding royalty interests in subject interests400,300,341—Total assets$401,494,215$10LIABILITIES AND TRUST CORPUSReserve Fund liability$1,000,023$—Loan payable to Freeport-McMoRan Copper & Gold Inc. (FCX)450,000—Trust corpus (230,172,696 royalty trust units authorized, issued and outstanding as of December 31, 2013)400,044,19210Total liabilities and trust corpus$401,494,215$10








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





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GULF COAST ULTRA DEEP ROYALTY TRUST


STATEMENTS OF DISTRIBUTABLE INCOME





Period FromDecember 18, 2012Year Ended(inception) ThroughDecember 31, 2013December 31, 2012Royalty income$—$—Interest income4—Administrative expenses(606,163)—Administrative expenses in excess of income$(606,159)$—Distributable income$—$—Distributable income per unit$—$—Royalty trust units outstanding at December 31, 2013 and 2012230,172,696—





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





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GULF COAST ULTRA DEEP ROYALTY TRUST


STATEMENTS OF CHANGES IN TRUST CORPUS





Year Ended December 31, 2013Period From December 18, 2012(inception) Through December 31, 2012Trust corpus, beginning of period$10$—Trust contributions350,00010Administrative expenses in excess of income(606,159)—Overriding royalty interests in subject interests400,300,341—Trust corpus, end of period$400,044,192$10





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





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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 U.S. generally accepted accounting principles (GAAP).  This other comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the Securities and Exchange Commission (SEC), as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. There has been no distributable income paid or due to the Royalty Trust unitholders from inception through December 31, 2013.





The Royalty Trust's operating cash and reserve fund cash amounts represent deposits in highly liquid short-term United States Treasury money market funds.





As required for financial reporting purposes, the amount recorded in the accompanying financial statements for the overriding royalty interests conveyed to the Royalty Trust was derived from the actual number of royalty trust units issued, McMoRan Exploration Co.'s (MMR) $16.75 per share closing price for its common stock on June 3, 2013, the closing date of the merger (as defined in Note 2), and the related implied initial value of the royalty trust units of approximately $400.3 million. Application of income tax requirements resulted in different values for tax reporting purposes for the Royalty Trust unitholders. For more information on the conveyance of the overriding royalty interests, see Note 2.


The initial value of the Royalty Trust’s overriding royalty interests in the subject interests (defined in Note 2 below) of $400.3 million will be amortized using the units of production method based on proved reserves, on an individual subject interest basis, once production has been established for the respective subject interests. Such non-cash amortization will be charged directly to the Royalty Trust Corpus, and will not affect distributable cash or the determination of distributable cash per royalty trust unit.


The Trustee 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 such royalty interests. Indications of potential impairment with respect to such 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, exploitation costs, and/or drilling plans, and other matters that arise that could negatively impact the Royalty Trust’s carrying values of the royalty interests. When such royalty interests are deemed impaired, the related impairment amounts are charged to the Royalty Trust Corpus in the period such impairment is determined. No impairment charges were recorded in the accompanying financial statements.





2. FORMATION OF THE ROYALTY TRUST


On June 3, 2013, Freeport-McMoRan Copper & Gold Inc. (FCX) and 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, on June  3,  2013, Merger Sub merged with and into MMR, with MMR surviving the merger as an indirect wholly owned subsidiary of FCX (the merger). The Royalty Trust was created as contemplated by the merger agreement, and is a statutory trust created 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. The Royalty Trust was created to hold a 5% gross overriding royalty interest (collectively, the royalty interests) in future production from each of McMoRan Oil & Gas LLC's (McMoRan) shallow water Inboard Lower Tertiary/Cretaceous (ILTC, previously referred to as ultra-deep) exploration prospects located on the Shelf of the Gulf of Mexico and onshore 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 that were acquired by FCX pursuant to the merger and were not considered part of FCX's purchase consideration of MMR. McMoRan owns less than 100% of the working interest in each of the subject interests. FCX's portfolio of oil and gas assets is held through its wholly owned subsidiary, Freeport-McMoRan Oil & Gas LLC (FMO&G). MMR and McMoRan are wholly owned subsidiaries of FMO&G.





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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).





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 royalty interests in future production from the subject interests. Other than its formation, its receipt of contributions and loans from FCX, its payment of administrative expenses, and its receipt of the conveyance of the royalty interests, the Royalty Trust has conducted no other activities.





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 under 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 applicable operating agreements, 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 in general 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 “ subject interests ” consist of 20 specified shallow water  ILTC (target depths generally greater than 18,000 total vertical depth) exploration prospects located on the Shelf of the Gulf of Mexico and onshore South Louisiana. The offshore “ subject interests ” consist 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 ” consist of the following exploration prospects: (1)  Highlander; (2)  Lineham Creek; and (3)  Tortuga.   McMoRan does not own 100% of the working interest of any of the subject interests.  The royalty interests in future production from the subject interests burden all of McMoRan's initial leasehold interests associated with such prospects, and will burden any leasehold interests associated with such prospects which are acquired by McMoRan on or before December  5, 2017 up to the working interests in the table below (subject to McMoRan's right to dispose of a portion of the working interest to a percentage not less than the estimated working interests estimated in the table below).  Each of the royalty interests has been, or will be, proportionately reduced based on McMoRan's working interest to equal the product of 5% multiplied by a fraction, the numerator of which is the working interest held by McMoRan and its affiliates in the applicable subject interest (subject to a cap equal to McMoRan's estimated working interest (equal to the working interest McMoRan owns or expects to acquire and as reflected in the table below) in each subject interest, on a prospect by prospect basis) and the denominator of which is 100%.  As of December 5, 2012, the date of the merger agreement, the subject interests comprised all of McMoRan's ILTC prospects.





Currently, none of the subject interests have any reserves classified as proved, probable or possible (other than the onshore Lineham Creek subject interest) and none of the subject interests have any associated production. Additional ILTC prospects developed by McMoRan hereafter (other than those reflected below) will not be included in the subject interests.  Approximately 0.7 Bcfe of proved reserves in sands encountered above 24,000 feet are currently deemed attributable to the Royalty Trust's 1.8% overriding royalty interest (the applicable royalty interest proportionately reduced to reflect McMoRan ’ s estimated working interest) in the onshore Lineham Creek subject interest. Information concerning McMoRan's estimated working interests and the Royalty Trust's estimated overriding royalty interests for each of the subject interests as of December 31, 2013 is set forth below:


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Subject Interest NameMcMoRan's EstimatedWorkingInterest Related to theSubjectInterestsOperatorRoyalty Trust's EstimatedOverridingRoyalty Interests(5% proportionatelyreduced to reflectthe EstimatedWorking Interest)Davy Jones63.4%McMoRan3.17%Blackbeard East72%McMoRan3.6%Lafitte(a)—McMoRan—Blackbeard West69.4%McMoRan3.47%England(b)36%Chevron1.8%Barbosa72%McMoRan3.6%Morgan(c)—McMoRan—Barataria72%McMoRan3.6%Blackbeard West #369.4%McMoRan3.47%Drake72%McMoRan3.6%Davy Jones West36%McMoRan1.8%Hurricane72%McMoRan3.6%Hook72%McMoRan3.6%Captain Blood72%McMoRan3.6%Bonnet72%McMoRan3.6%Queen Anne's Revenge72%McMoRan3.6%Calico Jack36%McMoRan1.8%Highlander72%McMoRan3.6%Lineham Creek36%Chevron1.8%Tortuga72%McMoRan3.6%





(a)     In June 2013 McMoRan requested from the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE) that its then pending request for the issuance of a Suspension of Production (SOP) lease extension for the Lafitte unit properties be returned without action, which effectively relinquished McMoRan's lease rights to the Lafitte unit. In the event on or before December 5, 2017, McMoRan acquires one or more leasehold interests covering the same area and blocks covered by the terminated leases, such newly acquired leasehold interests shall become subject interests, and if this were to occur, it is expected that McMoRan would hold an approximate 72% working interest in such reacquired leases, equating to an estimated overriding royalty interest of 3.6% to be held by the Royalty Trust.  On March 19, 2014, McMoRan was published as the apparent high bidder in the Central Gulf of Mexico Oil and Gas Lease Sale 231 for the lease rights to Eugene Island 223 (associated with the offshore Lafitte subject interest). The bid is subject to approval by the Bureau of Ocean Energy Management (BOEM) (see Note 7).





(b)    On March 19, 2014, McMoRan was published as the apparent high bidder in the Central Gulf of Mexico Oil and Gas Lease Sale 231 for the lease rights to Vermillion 17, 38 and 39 (associated with the offshore England subject interest). The bids are subject to approval by the BOEM (see Note 7).





(c)     McMoRan's rights to the Morgan lease expired on May 31, 2013. In the event on or before December 5, 2017, McMoRan acquires a leasehold interest covering the same area and block covered by the terminated lease, such newly acquired leasehold interest shall become a subject interest, and if this were to occur, it is expected that McMoRan would hold an approximate 72% working interest in such reacquired lease, equating to an estimated overriding royalty interest of 3.6% to be held by the Royalty Trust.





The Royalty Trust has no ability to influence the exploration or development of the subject interests. In addition, neither FCX nor McMoRan are under any obligation to fund or to commit any other resources to the exploration or development of the subject interests.





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The Royalty Trust will dissolve on the earlier of (i)  June 3, 2033, (ii)  the sale of all of the 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 80% (which after June 3, 2018, shall be reduced to 66 2⁄3 %) or more of the outstanding royalty trust units held by persons other than FCX or any of its affiliates, 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 described in the next paragraph.  The 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 royalty interests to a third party pursuant to the terms of the royalty trust agreement (in which case the royalty interests may extend through June 3, 2033).





FCX will maintain a call right with respect to the outstanding royalty trust units at $10 per royalty trust unit, provided that the call right may not be exercised prior to June 3, 2018.  In addition, at any time after June  3,  2018, 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 of such nine-month period.





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.





5.  RELATED PARTY TRANSACTIONS


Funding of Administrative Expenses. As required under the royalty trust agreement, FCX contributed $350,000 to the Royalty Trust in 2013 to cover portions of its administrative and other expenses, representing FCX's maximum annual contribution for reimbursement of such expenses with no right of repayment or interest due.





In addition to its maximum annual contribution of up to $350,000 (for which FCX has no right of repayment or interest due), FCX has agreed to loan amounts, on an unsecured, interest-free basis, to the Royalty Trust to fund certain of the Royalty Trust's ordinary administrative expenses as set forth in the royalty trust agreement. During the year ended December 31, 2013, in addition to its maximum annual contribution, FCX loaned $450,000, on an unsecured, interest-free basis, to the Royalty Trust to cover additional administrative expenses incurred during 2013. The amount borrowed from FCX as of December 31, 2013 totaled $450,000.





Pursuant to the royalty trust agreement, FCX 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 the reserve account or letter of credit to pay obligations of the Royalty Trust in the event that the Royalty Trust had inadequate funds to pay the Royalty Trust's obligations at any time. After the one-year anniversary of the date of the royalty trust agreement, 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, which amount is reflected as reserve fund cash with a corresponding reserve fund liability in the accompanying Statements of Assets, Liabilities and Trust Corpus. For additional information regarding the royalty trust agreement, see Note 2.


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Compensation of the Trustee. The Trustee will be paid the sum of $150,000 per year until the first year in which the Royalty Trust receives any payment pursuant to the conveyances of the royalty interests, at which time such sum shall be increased to $200,000 per year, and will receive reimbursement for its reasonable out-of-pocket expenses incurred in connection with the administration of the Royalty Trust. 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 and other amounts to which it is entitled under the royalty trust agreement.





Royalty Trust Units Held by FCX. On June 3, 2013, the Royalty Trust issued 230,172,696 royalty trust units. Of this amount, 129,216,862 royalty trust units were ultimately delivered to former holders of MMR common stock as merger consideration, and the remaining 100,955,834 royalty trust units were held by McMoRan, including 38,805,688 royalty trust units (approximately 16.9% of the total number of royalty trust units outstanding), which McMoRan, on behalf of FCX, held for delivery to holders of certain convertible securities of MMR upon conversion. At December 31, 2013 there were no MMR convertible securities outstanding, and FCX, through its indirect wholly owned subsidiary McMoRan, held 62,285,438 royalty trust units (or 27.1% of the outstanding royalty trust units).  FCX is currently the largest holder of outstanding royalty trust units.





6.  CONTINGENCIES


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





7.  SUBSEQUENT EVENTS


On March 19, 2014, McMoRan was published as the apparent high bidder in the Central Gulf of Mexico Oil and Gas Lease Sale 231 for the lease rights to Eugene Island Block 223 (associated with the offshore Lafitte subject interest) and Vermillion Blocks 17, 38 and 39 (associated with the offshore England subject interest). The bids are subject to approval by the BOEM. If approved by the BOEM, these lease rights would be subject to the overriding royalty interests held by the Royalty Trust.





The Trustee evaluated all other events after December 31, 2013, and through the date the Royalty Trust ’ s financial statements were issued, and determined that all events or transactions occurring during this period requiring recognition or disclosure were appropriately addressed in these financial statements.





8. SUPPLEMENTARY OIL AND GAS INFORMATION  (UNAUDITED)


McMoRan’s reserves associated with the Royalty Trust are located offshore in the Gulf of Mexico and onshore in the Gulf Coast region of the United States. Supplementary information presented below is prepared in accordance with requirements prescribed by U.S. GAAP.





Proved Oil and Natural Gas Reserves. Proved oil and natural gas reserves for the period from conveyance of the royalty interests to the Royalty Trust (June 3, 2013) through December 31, 2013 have been estimated by Ryder Scott Company, L.P. (Ryder Scott), in accordance with the guidelines established by the SEC as set forth in Rule 4-10 (a)(6), (22), (26) and (31). All estimates of oil and natural gas reserves are inherently imprecise and subject to change as new technical information about the properties is obtained.  Estimates of proved reserves for wells with little or no production history are less reliable than those based on a long production history.  Subsequent evaluation of the same reserves may result in variations which may be substantial.  Revisions of proved reserves represent changes in previous estimates of proved reserves resulting from new information obtained from production history, additional development drilling and/or changes in other factors, including economic considerations.  Discoveries and extensions represent additions to proved reserves resulting from (1) extensions of proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to initial discovery, and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Oil is stated in thousands of barrels (MBbls) and natural gas in millions of cubic feet (MMcf). The following table discloses estimated proved reserves attributable to the Royalty Trust’s 1.8% overriding royalty interest (the applicable royalty interest proportionately reduced to reflect McMoRan’s estimated working interest) in the onshore Lineham Creek subject interest from June 3, 2013 (conveyance of royalty interests) through December 31, 2013.





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Gas(MMcf)Oil(MBbls)Proved reserves:June 3, 2013 (conveyance of royalty interests)8569Revisions of previous estimates(169)(2)Discoveries and extensions——Production——Sales of reserves——Purchases of reserves——December 31, 20136877Proved developed reserves:December 31, 2013——





Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Natural Gas Reserves.


The Royalty Trust’s standardized measure of discounted future net cash flows (Standardized Measure) and changes therein relating to proved oil and natural gas reserves were computed using reserve valuations based on regulations and parameters prescribed by the SEC.  SEC regulations require the use of the twelve-month average of the first-day-of-the month historical reference price for natural gas and oil.  The weighted average of these prices for all properties with proved reserves was $3.70 per thousand cubic feet (Mcf) of natural gas and $96.94 per barrel of oil at December 31, 2013.


December 31,2013Future cash inflows$3,207,065Future costs applicable to future cash flows:Production costs (primarily production and ad valorem taxes)(139,684)Development and abandonment costs—Future income taxes(a)—Future net cash flows3,067,381Discount for estimated timing of net cash flows (10% discount rate)(b)(658,353)Standardized measure$2,409,028





|    |                                                                                                             
|--- | ------------------------------------------------------------------------------------------------------------
|(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.




38


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Changes in Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Natural Gas Reserves.


2013June 3, 2013 (conveyance of royalty interests)$2,713,309Sales, net of production expense—Net changes in sales and transfer prices, net of production expense282,189Extensions, discoveries and improved recoveries—Changes in estimated future development costs—Previously estimated development costs incurred during the year—Sales of reserves in-place—Revisions of quantity estimates(761,070)Accretion of discount174,600Net change in income taxes—Balance at December 31, 2013$2,409,028





9.  QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


Royalty IncomeAdministrative Expenses in Excess of IncomeDistributable IncomeDistributable Income Per Unit(a)20131stQuarter$—$—$—$—2ndQuarter—(221,938)——3rdQuarter—(242,359)——4thQuarter—(141,862)——$—$(606,159)$—20124thQuarter(b)$—$—$—$—$—$—$—





|    |                                                                                                                                          
|--- | -----------------------------------------------------------------------------------------------------------------------------------------
|(a) | Since administrative expenses are in excess of income there was no distributable income to be disbursed to the Royalty Trust unitholders.




|    |                                                                                     
|--- | ------------------------------------------------------------------------------------
|(b) | Period from December 18, 2012 (formation of the Royalty Trust) to December 31, 2012.




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 controls and 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 Securities Exchange Act of 1934) as of the end of the period covered by this Form 10-K. Based on this


39


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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 amended and restated royalty trust agreement (the royalty trust agreement) and (ii) the master conveyance of overriding royalty interest (the master conveyance), the Royalty Trust's disclosure controls and procedures necessarily rely on (A) information furnished by McMoRan, including information relating to results of operations, the costs and revenues attributable to the subject interests under the master conveyance 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 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 15(d)-15(f) promulgated under the Securities Exchange Act of 1934. 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 (1992 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, 2013.





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.





This annual report does not include an attestation report of the Royalty Trust’s independent registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.





(b) Changes in internal control over financial reporting .   During the quarter ended December 31, 2013, 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 FCX.





Item 9B.  Other Information





Not Applicable.





PART III





Item 10.  Directors, Executive Officers and Corporate Governance





The Royalty Trust has no directors or executive officers, and, therefore, the Royalty Trust has not adopted a Code of Ethics and the Royalty Trust does not have an audit 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.





Section 16(a) Beneficial Ownership Reporting Compliance


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The Royalty Trust has no directors or officers. Accordingly, only holders of more than 10% of the royalty trust units are required to file with the SEC initial reports of ownership of royalty trust units and reports of changes in such ownership pursuant to Section 16 of the Exchange Act. Based solely on a review of these reports and any such reports furnished to the Trustee, the Trustee is not aware of any person having failed to file on a timely basis the reports required by Section 16(a) of the Exchange Act during the most recent fiscal year.


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.





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


Security Ownership of Certain Beneficial Owners


Based on filings with the SEC, 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, 2013 and all royalty trust units beneficially owned are held with sole voting and investment power.


Name and Address of Beneficial OwnerTotal Numberof UnitsBeneficiallyOwnedPercent of OutstandingUnits(a)Freeport-McMoRan Copper & Gold Inc.McMoRan Oil and Gas LLC333 N. Central Ave.Phoenix, AZ 8500462,285,438(b)27.1%Mount Kellett Capital Management LP623 Fifth Avenue, 18th FloorNew York, NY 1002235,759,004(c)15.5%Leon G. Cooperman11431 W. Palmetto Park RoadBoca Raton, FL 3342816,863,043(d)7.3%Paulson & Co. Inc.1251 Avenue of the AmericasNew York, NY 1002013,721,855(e)6.0%





|    |                                                                              
|--- | -----------------------------------------------------------------------------
|(a) | Based on 230,172,696 royalty trust units outstanding as of December 31, 2013.




|    |                                      
|--- | -------------------------------------
|(b) | Based on information provided by FCX.




|    |                                                                                                                                                                  
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------
|(c) | Based on an amended Schedule 13G filed with the SEC on January 6, 2014 by certain funds and managed accounts affiliated with Mount Kellett Capital Management LP.




|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(d) | Based on an amended Schedule 13G filed with the SEC on February 4, 2014 by Leon G. Cooperman, on his own behalf and on behalf of investment firms identified therein.  According to the amended Schedule 13G, Mr. Cooperman, on a consolidated basis, has (a)  sole voting and dispositive power over 10,511,639 of the royalty trust units reported and (b) shared voting and dispositive power over 6,351,404 of the royalty trust units reported.




|    |                                                                                      
|--- | -------------------------------------------------------------------------------------
|(e) | Based on a Schedule 13G filed with the SEC on February 14, 2014 by Paulson & Co. Inc.

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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.





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





Other than its formation, its receipt of contributions and loans from FCX to pay administrative and other expenses as provided for in the royalty trust agreement, its payment of such expenses and the conveyance of the subject interests from McMoRan to the Royalty Trust pursuant to the master conveyance, the Royalty Trust has not conducted any activities or entered into any transactions.





Funding of Administrative Expenses . As required under the royalty trust agreement, FCX contributed $350,000 to the Royalty Trust in 2013 to cover portions of its administrative and other expenses, representing FCX's maximum annual contribution for reimbursement of such expenses with no right of repayment or interest due.





In addition to its annual contribution of up to $350,000 (for which FCX has no right of repayment or interest due), FCX has agreed to loan amounts, on an unsecured, interest-free basis, to the Royalty Trust to fund certain of the Royalty Trust's ordinary administrative expenses as set forth in the royalty trust agreement. During the year ended December 31, 2013, in addition to its maximum annual contribution, FCX loaned $450,000, on an unsecured, interest-free basis, to the Royalty Trust to cover additional administrative expenses incurred during 2013. The amount borrowed from FCX as of December 31, 2013 totaled $450,000.





Pursuant to the royalty trust agreement, FCX 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 the reserve account or letter of credit to pay obligations of the Royalty Trust in the event that the Royalty Trust had inadequate funds to pay the Royalty Trust's obligations at any time. After the one-year anniversary of the date of the royalty trust agreement, 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, which amount is reflected as reserve fund cash with a corresponding reserve fund liability in the accompanying Statements of Assets, Liabilities and Trust Corpus. For additional information regarding the royalty trust agreement, see Note 2.





Compensation of the Trustee . The Trustee will be paid the sum of $150,000 per year until the first year in which the Royalty Trust receives any payment pursuant to the conveyances of the royalty interests, at which time such sum shall be increased to $200,000 per year, and will receive reimbursement for its reasonable out-of-pocket expenses incurred in connection with the administration of the Royalty Trust. 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 and other amounts to which it is entitled under the royalty trust agreement.





Royalty Trust Units Held by FCX . On June 3, 2013, the Royalty Trust issued 230,172,696 royalty trust units. Of this amount, 129,216,862 royalty trust units were ultimately delivered to former holders of MMR common stock as merger consideration, and the remaining 100,955,834 royalty trust units were held by McMoRan, including 38,805,688 royalty trust units (approximately 16.9% of the total number of royalty trust units outstanding), which McMoRan, on behalf of FCX, held for delivery to holders of certain convertible securities of MMR upon conversion. At December 31, 2013 there were no MMR convertible securities outstanding, and FCX, through its indirect wholly owned subsidiary McMoRan, held 62,285,438 units of the Royalty Trust (27.1% of the outstanding royalty trust units) and is currently the largest holder of outstanding royalty trust units.





For more detail on the contributions and loans from FCX, see Part I, Items 7. and 7A. “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk - Liquidity and Capital Resources” and Note 5 of this Form 10-K.





The Royalty Trust has no directors.


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Item 14. Principal Accounting Fees and Services


Fees and Related Disclosures for Accounting Services


The following table discloses the fees for professional services billed to the Royalty Trust by Ernst & Young LLP in each of the last two fiscal years:


20132012Audit Fees$150,000$—Audit-Related Fees——Tax Fees——All Other Fees——





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 Ernst & Young LLP. 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.





PART IV





Item 15.  Exhibits and Financial Statement Schedules





(a)(1)  Financial Statements .  Reference is made to Part II, Item 8. "Financial Statements and Supplementary Data" of this Form 10-K.





|       |                                                                                                                                                                                                           
|------ | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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.  Reference is made to the Exhibit Index beginning on page E-1 hereof.




____________________





GLOSSARY





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





Bcfe .  Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.





Block .  A block depicted on the Outer Continental Shelf Leasing and Official Protraction Diagrams issued by BOEM (defined below) or a similar depiction on official protraction or similar diagrams issued by a state bordering on the Gulf of Mexico.





BOEM. The Bureau of Ocean Energy Management (an agency of the Department of the Interior; formed upon dissolution of the Bureau of Ocean Energy Management, Regulation and Enforcement on October 1, 2011, and responsible for pre-leasing environmental and leasing matters).





BSEE. The Bureau of Safety and Environmental Enforcement (an agency of the Department of the Interior; formed upon dissolution of the Bureau of Ocean Energy Management, Regulation and Enforcement on October 1, 2011, and responsible for environmental matters related to operations, safety and operational matters generally).





Completion .  The installation of permanent equipment for the production of natural gas or oil, or, in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.





Exploratory well .  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.





Field .  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.


Gross well or gross acre. A well or acre in which the registrant owns a working interest. The numbers of gross wells is the total number of wells in which the registrant owns a working interest.


Net well or net acre. Deemed to exist when the sum of the fractional ownership working interests in gross wells or gross acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or 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.





Pay. Reservoir rock containing oil or gas.





Possible reserves .  Those additional reserves that are less certain to be recovered than probable reserves.





Probable reserves .  Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.





Productive well .  A well that is found to be capable of producing hydrocarbons in quantities sufficient such that proceeds from the sale of production exceed production expenses and taxes.





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.





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





Sands. Sandstone or other sedimentary rocks.





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, or for other oil and gas definitions, please see Rule 4-10 of Regulation S-X.








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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 TrustBy:The Bank of New York MellonTrust Company, N.A., as TrusteeBy:/s/ Michael J. UlrichMichael J. UlrichVice PresidentDate:  March 31, 2014





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.








S-1


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Appendix A-1











GULF COAST ULTRA DEEP ROYALTY TRUST





PROVED RESERVES

















Estimated





Future Reserves and Income





Attributable to Certain





Royalty Interests

















SEC Parameters

















As of





December 31, 2013


























Val Rick RobinsonVal Rick Robinson, P.E.TBPE License No. 105137Senior Vice President


[SEAL]


RYDER SCOTT COMPANY, L.P.


TBPE Firm Registration No. F-1580

















RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


---













TBPE REGISTERED ENGINEERING FIRM F-1580FAX (713) 651-08491100 LOUISIANA STREETSUITE 4600HOUSTON, TEXAS 77002-5294TELEPHONE (713) 651-9191








February 14, 2014








Gulf Coast Ultra Deep Royalty Trust


The Bank of New York Mellon Trust Company, N.A., as trustee


Attn: Michael J. Ulrich


Institutional Trust Services


919 Congress Avenue, Suite 500


Austin, Texas  78701





Gentlemen:





At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain royalty interests of Gulf Coast Ultra Deep Royalty Trust (the Trust) as of December 31, 2013.  The subject properties are located in the state of Louisiana.  The reserves found herein are derived from the reserves evaluation prepared for Freeport-McMoRan Oil & Gas LLC (FM O&G), a wholly owned subsidiary of Freeport-McMoRan Copper & Gold Inc., as of December 31, 2013.  The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).  Our third party study, completed on February 7, 2014, and presented herein, was prepared for public disclosure by The Bank of New York Mellon Trust Company, N.A. (the Trustee), on behalf of Gulf Coast Ultra Deep Royalty Trust in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.





The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of the Trust as of December 31, 2013.





The estimated reserves and future net income amounts presented in this report, as of December 31, 2013 are related to hydrocarbon prices.  The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations.  Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study are summarized in the following table.


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February 14, 2014


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SEC PARAMETERS


Estimated Net Reserves and Income Data


Certain Royalty Interests of


Gulf Coast Ultra Deep Royalty Trust As of December 31, 2013


TotalProvedUndevelopedNet Remaining ReservesOil/Condensate - Barrels6,868Gas - MMCF687Income DataFuture Gross Revenue$3,166,692Deductions99,311Future Net Income (FNI)$3,067,381Discounted FNI @ 10%$2,409,028





Liquid hydrocarbons are expressed in standard 42 gallon barrels.  All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.





The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C.  The program was used at the request of FM O&G.  Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized.  Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding.  The rounding differences are not material.





The future gross revenue is after the deduction of production taxes.  The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, and development costs.  The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.  Because the interests evaluated herein include only royalty interests, no operating or development costs are shown; however, these costs have been considered in determining economic limits of these properties.





Gas reserves account for approximately 79 percent and liquid hydrocarbon reserves account for the remaining 21 percent of total future gross revenue from proved reserves.





The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly.  Future net income was discounted at four other discount rates which were also compounded monthly.  These results are shown in summary form as follows.


RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


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Gulf Coast Ultra Deep Royalty Trust


February 14, 2014


Page 3


Discounted Future Net IncomeAs of December 31, 2013Discount RateTotalPercentProved8$2,526,36815$2,142,42620$1,909,62025$1,705,827





The results shown above are presented for your information and should not be construed as our estimate of fair market value.





Reserves Included in This Report





The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.





The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.





No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist.





Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”  All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  At the Trustee’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.





Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.”  The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”





Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.  For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”  Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.  Therefore, the proved reserves


RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


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February 14, 2014


Page 4





included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.





FM O&G’s operations may be subject to various levels of governmental controls and regulations.  These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.





The estimates of reserves presented herein were based upon a detailed study of the properties in which the Trust owns an interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.





Estimates of Reserves





The estimation of reserves involves two distinct determinations.  The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures.  These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy.  These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves.  Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.





In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves.  If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator.  Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported.  For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.”  The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.”  The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.”  All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.


RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS


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February 14, 2014


Page 5





Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.





All of the proved undeveloped reserves included herein were estimated by the volumetric method.  The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by FM O&G or which we have obtained from public data sources that were available through December 2013.  The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.





To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.  Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.





FM O&G has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In preparing our forecast of future proved production and income, we have relied upon data furnished by FM O&G with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by FM O&G.  We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.





In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.  The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.”  In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.





Future Production Rates





Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing.  For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by FM O&G.  Wells or locations


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that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production.  Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.





The future production rates from wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.





Hydrocarbon Prices





The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements.  For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract.  Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.





FM O&G furnished us with the above mentioned average prices in effect on December 31, 2013.  These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.  In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.





The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.”  The differentials used in the preparation of this report were furnished to us by FM O&G.  The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by FM O&G to determine these differentials.





In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.”  The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserve category for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.








GeographicAreaProductPriceReferenceAverageBenchmarkPricesAverageProvedRealizedPricesUnitedStatesOil/CondensateWTI Cushing$96.94/Bbl$96.94/BblGasHenry Hub$3.67/MMBTU$3.70/MCF





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The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.





Costs





Operating costs for the leases and wells in this report are based on the operating expense reports of FM O&G and include only those costs directly applicable to the leases or wells.  The operating costs include a portion of general and administrative costs allocated directly to the leases and wells.  For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs.  The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements.  Other costs such as transportation and/or processing fees, are included as deductions.  The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by FM O&G.  No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.





Development costs were furnished to us by FM O&G and are based on authorizations for expenditure for the proposed work or actual costs for similar projects.  The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs.





The proved undeveloped reserves in this report have been incorporated herein in accordance with FM O&G’s plans to develop these reserves as of December 31, 2013.  The implementation of FM O&G’s development plans as presented to us and incorporated herein is subject to the approval process adopted by FM O&G’s management.  As the result of our inquiries during the course of preparing this report, FM O&G has informed us that the development activities included herein have been subjected to and received the internal approvals required by FM O&G’s management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to FM O&G.  Where appropriate, FM O&G has provided written documentation supporting their commitment to proceed with the development activities as presented to us.  Additionally, FM O&G has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.





Current costs used by FM O&G were held constant throughout the life of the properties.





Standards of Independence and Professional Qualification





Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years.  Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada.  We have over eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.





Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our


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staff have authored or co-authored technical papers on the subject of reserves related topics.  We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.





Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.





We are independent petroleum engineers with respect to both FM O&G and the Trust.  Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.





The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.





Terms of Usage





The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC on behalf of the Trust.





The Trustee makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. We have consented to the reference to our name as well as to the references to our third party report on behalf of the Trust, which appears in the December 31, 2013 annual report on Form 10-K of the Trust.





We have provided the Trustee with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made on behalf of the Trust and the original signed report letter, the original signed report letter shall control and supersede the digital version.





The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.





Very truly yours,





RYDER SCOTT COMPANY, L.P.


TBPE Firm Registration No. F-1580





\s\ Val Rick Robinson





Val Rick Robinson, P.E.


TBPE License No. 105137


Senior Vice President


[SEAL]


VRR (DPR)/pl











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Professional Qualifications of Primary Technical Engineer





The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Mr. Val Rick Robinson was the primary technical person responsible for the estimate of the reserves, future production and income presented herein.





Mr. Robinson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.  Before joining Ryder Scott, Mr. Robinson served in a number of engineering positions with ExxonMobil Corporation.  For more information regarding Mr. Robinson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.





Mr. Robinson earned a Bachelor of Science degree in Chemical Engineering from Brigham Young University in 2003 and is a licensed Professional Engineer in the State of Texas.  He is also a member of the Society of Petroleum Engineers.





In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Robinson fulfills.  As part of his 2013 continuing education hours, Mr. Robinson attended 23 hours of formalized training including the 2013 RSC Reserves Conference and various professional society presentations covering such topics as the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, overviews of the various productive basins of North America, computer software, and professional ethics.





Based on his educational background, professional training and more than 10 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Robinson has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.








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PETROLEUM RESERVES DEFINITIONS





As Adapted From:


RULE 4-10(a) of REGULATION S-X PART 210


UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)





PREAMBLE





On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA).  The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K.  The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”.  The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.  Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).





Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC.  The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.





Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.





Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.





Reserves may be attributed to either conventional or unconventional petroleum accumulations.  Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.  Examples of unconventional petroleum accumulations include coalbed or coalseam methane


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(CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.





Reserves do not include quantities of petroleum being held in inventory.





Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.








RESERVES (SEC DEFINITIONS)





Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:





Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.





Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results).  Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).








PROVED RESERVES (SEC DEFINITIONS)





Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:





Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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.





(i) The area of the reservoir considered as proved includes:





(A) The area identified by drilling and limited by fluid contacts, if any, and





(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.


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(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.





(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.





(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:





(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and





(B) The project has been approved for development by all necessary parties and entities, including governmental entities.





(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.














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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES





As Adapted From:


RULE 4-10(a) of REGULATION S-X PART 210


UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)





and





PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)


Sponsored and Approved by:


SOCIETY OF PETROLEUM ENGINEERS (SPE)


WORLD PETROLEUM COUNCIL (WPC)


AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)


SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)








Reserves status categories define the development and producing status of wells and reservoirs.  Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).








DEVELOPED RESERVES (SEC DEFINITIONS)





Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:





Developed oil and gas reserves are reserves of any category that can be expected to be recovered:





(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and





(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.





Developed Producing (SPE-PRMS Definitions)





While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.





Developed Producing Reserves


Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.





Improved recovery reserves are considered producing only after the improved recovery project is in operation.


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Developed Non-Producing


Developed Non-Producing Reserves include shut-in and behind-pipe reserves.





Shut-In


Shut-in Reserves are expected to be recovered from:


|    |                                                                                                        
|--- | -------------------------------------------------------------------------------------------------------
|(1) | completion intervals which are open at the time of the estimate, but which have not  started producing;

|    |                                                                           
|--- | --------------------------------------------------------------------------
|(2) | wells which were shut-in for market conditions or pipeline connections; or

|    |                                                        
|--- | -------------------------------------------------------
|(3) | wells not capable of production for mechanical reasons.




Behind-Pipe


Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.





In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.








UNDEVELOPED RESERVES (SEC DEFINITIONS)





Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:





Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.





(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.





(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.





(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.














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Gulf Coast Ultra Deep Royalty Trust


Exhibit Index


FiledExhibitwith thisIncorporated by ReferenceNumberExhibit TitleForm 10-KFormFile No.Date Filed3.1Composite Certificate of Trust of Gulf Coast Ultra Deep Royalty Trust10-Q333-185742August 14, 201310.1Amended and Restated Royalty Trust Agreement of Gulf Coast Ultra Deep Royalty Trust, dated as of June 3, 20138-K333-185742June 4, 201310.2Master Conveyance of Overriding Royalty Interest by and between McMoRan Oil & Gas LLC and Gulf Coast Ultra Deep Royalty Trust, dated as of June 3, 20138-K333-185742June 4, 201323.1Consent of Ryder Scott Company, L.P.X31Certification pursuant to Rule 13a-14(a)/15d-14(a)X32Certification pursuant to 18 U.S.C. Section 1350X99.1Report of Ryder Scott Company, L.P.X





E-1