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As filed with the Securities and Exchange Commission on June 3, 2013

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Gulf Coast Ultra Deep Royalty Trust

(Exact name of registrant as specified in its charter)

 

 

 

Delaware		6792		46-6448579
(State or other jurisdiction of incorporation or organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

 

 

 

333 N. Central Ave.

Phoenix, Arizona 85004

(602) 366-8100

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

 

 

Douglas N. Currault II

Assistant General Counsel and Secretary

Freeport-McMoRan Copper & Gold Inc., as depositor of the Royalty Trust

333 N. Central Ave.

Phoenix, Arizona 85004

(602) 366-8100

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

 

 

Copies to:

 

David E. Shapiro Wachtell, Lipton, Rosen & Katz 51 West 52nd Street New York, New York 10019 (212) 403-1000		Monique A. Cenac Jones Walker LLP 333 N. Central Avenue Phoenix, Arizona 85004 (602) 366-7604

 

 

Approximate date of commencement of proposed sale to the public: From time to time after this Registration Statement becomes effective.

If the only securities being registered on this Form are being offered pursuant to dividend or interest reinvestment plans, please check the following box:  ¨

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box:  x

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a registration statement pursuant to General Instruction I.D. or a post-effective amendment thereto that shall become effective upon filing with the Commission pursuant to Rule 462(e) under the Securities Act, check the following box.  ¨

If this Form is a post-effective amendment to a registration statement filed pursuant to General Instruction I.D. filed to register additional securities or additional classes of securities pursuant to Rule 413(b) under the Securities Act, check the following box.  ¨

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):

 

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

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of each class of securities to be registered		Amount to be registered(1)		Proposed maximum offering price per share(2)		Proposed maximum aggregate offering price(2)		Amount of registration fee(3)
Royalty Trust Units		38,805,688 units		N/A		$63,438,866		$8,654

(1)

Represents the maximum number of units that could be delivered by McMoRan Oil & Gas LLC, a subsidiary of Freeport-McMoRan Copper & Gold Inc. (“FCX”) and the selling securityholder, pursuant to this registration statement upon conversion of the outstanding convertible securities of McMoRan Exploration Co. (“MMR”) following completion of the merger on June 3, 2013, as described herein. This number is based on the number of royalty trust units held for delivery upon conversion of MMR’s outstanding convertible securities pursuant to the formula set forth in the Agreement and Plan of Merger, dated as of December 5, 2012, by and among MMR, FCX and INAVN Corp. (the “merger agreement”).

(2)

Estimated solely for the purpose of determining the registration fee pursuant to Rule 457(f)(2) under the Securities Act of 1933, as amended (the “Securities Act”), based on the pro forma March 31, 2013 book value of the Registrant’s assets after giving effect to the transactions contemplated by the merger agreement, calculated based on the implied market value of the royalty trust units as of May 31, 2013, the most recent practicable date.

(3)	Calculated pursuant to Section 6(b) of the Securities Act and Securities and Exchange Commission Fee Rate revised October 2012 at a rate equal to $136.40 per $1,000,000 of the proposed maximum aggregate offering price.

 

 

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

 

 

 

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INTRODUCTORY NOTE

This registration statement on Form S-1 (File No. 333-                    ) relates to the delivery by McMoRan Oil & Gas LLC, a subsidiary of Freeport-McMoRan Copper & Gold Inc. (“FCX”) of up to 38,805,688 units representing beneficial interests in the Gulf Coast Ultra Deep Royalty Trust (the “royalty trust units”) to holders of the following outstanding convertible securities of McMoRan Exploration Co. (“MMR”) upon conversion: 5 ¹/₄% convertible senior notes due 2013 (the “2013 notes”); 4% convertible senior notes due 2017 (the “2017 notes”); 8% convertible perpetual preferred stock (the “8% preferred stock”); and 5.75% convertible perpetual preferred stock, Series 1 (the “5.75% preferred stock” and together with the 2013 notes, the 2017 notes and the 8% preferred stock, the “convertible securities”).

On June 3, 2013, pursuant to the terms and conditions of the Agreement and Plan of Merger (the “merger agreement”), dated as of December 5, 2012 by and among MMR, FCX, and INAVN Corp., a Delaware corporation and wholly owned subsidiary of FCX (“Merger Sub”), Merger Sub merged with and into MMR, with MMR surviving the merger as a wholly owned subsidiary of FCX (the “merger”). At the effective time of the merger, each issued and outstanding share of MMR common stock (other than shares held by FCX, Merger Sub or any of their respective subsidiaries that were cancelled and holders who had perfected and not withdrawn a demand for appraisal rights) was converted into the right to receive $14.75 in cash and 1.15 royalty trust units (together, the “merger consideration”).

Pursuant to the convertible securities’ respective governing instruments, upon the consummation of the merger each series of the convertible securities became convertible into the type and amount of merger consideration paid in the merger to holders of MMR common stock, on an as-converted basis. As a result of this feature of the convertible securities, FCX, as the acquiror in the merger, will be obligated to deliver royalty trust units to the holders of the convertible securities in the future, at times and in amounts determined by such holders through their exercise of their conversion rights, and certain royalty trust units held by a subsidiary of FCX are available for this purpose.

In addition, the 2017 notes, the 8% preferred stock and the 5.75% preferred stock are entitled to a “make-whole” premium due to the occurrence of the merger, which provides that any conversions of such securities exercised within a designated period following the merger will be made at an increased conversion rate, as set forth in their respective governing documents.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

PRELIMINARY—SUBJECT TO COMPLETION—DATED JUNE 3, 2013

Gulf Coast Ultra Deep Royalty Trust

38,805,688 Royalty Trust Units

 

 

This prospectus relates to the delivery by McMoRan Oil & Gas LLC (the “selling securityholder”), a subsidiary of Freeport-McMoRan Copper & Gold Inc. (“FCX”) of up to 38,805,688 royalty trust units to holders of the following convertible securities of McMoRan Exploration Co. (“MMR”) upon conversion: 5 ¹/₄% convertible senior notes due 2013; 4% convertible senior notes due 2017; 8% convertible perpetual preferred stock and 5.75% convertible perpetual preferred stock, Series 1 (collectively, the “convertible securities”). None of FCX, the selling securityholder or Gulf Coast Ultra Deep Royalty Trust (the “Royalty Trust”) will receive any proceeds from this offering.

The Royalty Trust Units. The royalty trust units represent beneficial interests in the Royalty Trust, which holds a 5% gross overriding royalty interest in hydrocarbons saved and produced from each of the subject interests (as defined below) during the life of the Royalty Trust. The royalty trust units are not currently listed on a national securities exchange. The royalty trust units are expected to be quoted on the OTCQX Marketplace (the “OTCQX”).

On June 3, 2013, the Royalty Trust issued 230,172,696 royalty trust units. Of this amount, 129,210,542 royalty trust units were issued to former holders of MMR common stock as merger consideration, and the remaining 100,962,154 royalty trust units are held by the selling securityholder, a subsidiary of FCX, including 38,805,688 royalty trust units (approximately 16.9% of the total number of royalty trust units outstanding), which FCX may become obligated to deliver to holders of the convertible securities upon conversion. FCX is currently the largest holder of royalty trust units with approximately 43.9% of the outstanding royalty trust units.

The Royalty Trust Unitholders. Holders of royalty trust units are entitled to share in a 5% gross overriding royalty interest in hydrocarbons saved and produced from 20 of MMR’s specified shallow water Gulf of Mexico and onshore Gulf Coast ultra-deep exploration prospects. 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.

The Subject Interests. The “subject interests” consist of 20 ultra-deep (target depths generally greater than 18,000 total vertical depth) prospects. The offshore “subject interests” consist of the following: (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: (1) Highlander; (2) Lineham Creek; and (3) Tortuga. All of the subject interests are located in relatively shallow waters offshore of the state of Louisiana, or onshore in Louisiana. MMR does not own 100% of the working interest of any of the subject interests. As of December 5, 2012, the date of the merger agreement, the subject interests comprised all of MMR’s ultra-deep prospects and, as of the date of this prospectus, none of the subject interests had any reserves classified as proved, probable or possible (other than the Lineham Creek well) and none of the subject interests had any associated production.

 

 

Investing in royalty trust units involves risks that are described in the “Risk Factors” section beginning on page 12 of this prospectus.

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

The date of this prospectus is                     , 2013.

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TABLE OF CONTENTS

 

IMPORTANT NOTICE ABOUT INFORMATION IN THIS PROSPECTUS			i
SUMMARY			1
UNAUDITED PRO FORMA STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS			4
GULF COAST ULTRA DEEP ROYALTY TRUST UNAUDITED PRO FORMA STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS AT MARCH 31, 2013			5
NOTES TO THE UNAUDITED PRO FORMA STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS			5
HISTORICAL FINANCIAL DATA OF THE ROYALTY TRUST			6
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS			6
STATEMENTS OF CHANGES IN TRUST CORPUS			6
NOTES TO FINANCIAL STATEMENTS			6
THE OFFERING			10
RISK FACTORS			12
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			17
THE MERGER			18
USE OF PROCEEDS			20
PLAN OF DISTRIBUTION			20
PRICE RANGE OF ROYALTY TRUST UNITS			20
THE ROYALTY TRUST			21
DESCRIPTION OF THE SUBJECT INTERESTS			22
DESCRIPTION OF THE ROYALTY INTERESTS			27
DESCRIPTION OF THE ROYALTY TRUST AGREEMENT			29
DESCRIPTION OF THE ROYALTY TRUST UNITS			33
U.S. FEDERAL INCOME TAX CONSIDERATIONS			36
STATE TAX CONSIDERATIONS			44
ERISA CONSIDERATIONS			45
SELLING SECURITYHOLDER			46
LEGAL MATTERS			47
EXPERTS			47
ADDITIONAL INFORMATION			47

IMPORTANT NOTICE ABOUT INFORMATION IN THIS PROSPECTUS

You should rely only on the information contained in this prospectus. The Royalty Trust has not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. You should assume the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus or as of its date as applicable.

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

 

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RISK FACTORS

In addition to the other information included herein, including the matters addressed in “Cautionary Statement Regarding Forward-Looking Statements” beginning on page 17, you should carefully consider the matters described below.

Risks Related to the Royalty Trust Units

The value of the royalty trust units is uncertain.

The only assets and sources of income to the Royalty Trust are certain overriding royalty interests burdening the subject interests. These overriding 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.

While data from the seven ultra-deep wells drilled on the subject interests thus far tie ultra-deep geologic formations to productive zones encountered (i) onshore, (ii) in the deepwater Gulf of Mexico and (iii) in Mexico, only the Davy Jones No. 1 well has been completed and efforts continue to obtain a measurable flow rate. No other exploratory well in the subject interests has been completed and consequently none of the seven wells is producing. 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.

As of the date of this prospectus, none of the subject interests have any proved, probable or possible reserves associated with them (other than the onshore Lineham Creek well) and none of the subject interests have any associated production. As such, it is possible that no production is derived from the subject interests in the future, the result of which would be that the Royalty Trust receives no income from the subject interests.

Further, the Royalty Trust has no ability to direct or influence the exploration or development of the subject interests. Additionally, FCX is under no obligation to fund or to commit any other resources to the exploration or development of the subject interests. For more information, see the section entitled “Description of the Royalty Trust Units” beginning on page 33.

The subject interests target ultra-deep formations in the shallow water Gulf of Mexico and onshore Gulf Coast, which have greater risks and costs associated with their exploration and development than conventional Gulf of Mexico prospects. The subject interests also include the Davy Jones ultra-deep prospect, which has not yet been fully evaluated.

MMR’s objectives in the subject interests are formations below the salt weld (i.e. ultra-deep targets) in the shallow water of the Gulf of Mexico and onshore in South Louisiana. These ultra-deep targets have not traditionally been the subject of exploratory activity in these regions, thus little direct comparative data is available. To date, there has been no production of hydrocarbons from ultra-deep reservoirs in these areas. As a result of the unavailability of direct comparative data and limitations of diagnostic tools that operate in the extreme temperatures and pressures encountered, it is much more difficult to predict with accuracy the reservoir quality and performance of ultra-deep formations. Additionally, ultra-deep formations are significantly more expensive to drill and complete than their conventional shallow water counterparts. Major contributors to such increased costs include (i) far higher temperatures and pressures encountered down hole and (ii) longer drilling times. Thus, costs for drilling and completing ultra-deep wells are significantly higher than shelf equivalents at more conventional depths.

For example, the Davy Jones ultra-deep prospect has not yet been fully evaluated, and the ultimate impact of this potentially significant discovery will depend on, among other things, the volume of recoverable resources from the Davy Jones location, which will require significant capital expenditures for commercial development. In January 2010, MMR announced a potentially significant discovery at the Davy Jones ultra-deep prospect. However, flow testing is required to confirm the ultimate hydrocarbon flow rates from the separate zones within

 

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this prospect. Because of the pressures and temperatures encountered down hole, certain specialty completion equipment was required. Completion activities were initiated in the fourth quarter of 2011, and initial flow testing procedures were attempted in March 2012; however, MMR encountered mechanical issues with the originally designed perforating equipment. Operations to obtain a measurable flow test at the Davy Jones ultra-deep prospect were temporarily halted in January 2013 while plans to pump a large scale hydraulic fracture treatment including proppant to facilitate hydrocarbon movement into the wellbore were developed. Future plans will incorporate data gained to date at Davy Jones as well as core and log data from the in progress well at Lineham Creek, located onshore approximately 50 miles northwest of Davy Jones. The rig was moved off location in February 2013 while a large scale hydraulic fracture treatment is designed to penetrate the Wilcox reservoirs to facilitate hydrocarbon movement in the wellbore. There is no assurance that Freeport-McMoRan Oil & Gas LLC will be able to effectively complete the flow testing of this prospect, or that once completed, the potential of the discovery in terms of recoverable product will be confirmed. MMR’s total investment in Davy Jones, which includes $474.8 million in allocated property acquisition costs, totaled approximately $1 billion at March 31, 2013. The continuing commercial development and exploitation of the Davy Jones prospect will also require significant additional capital expenditures.

An active public market for the royalty trust units may not develop or the royalty trust units may trade at low volumes, both of which could have an adverse effect on the resale price, if any, of the royalty trust units.

The royalty trust units are not currently listed on a national securities exchange. There is no market for the royalty trust units and a market may not develop, making it difficult or impossible to resell the royalty trust units, which would have an adverse effect on the resale price, if any, of the royalty trust units. Holders of royalty trust units 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. Neither FCX nor the Royalty Trust can predict the price, if any, at which the royalty trust units will trade in the future.

Because there has not been any public market for the royalty trust units, the market price and trading volume of the royalty trust units may be volatile.

Neither FCX nor the Royalty Trust can predict the extent to which investor interest will lead to a liquid trading market in the royalty trust units or whether the market price of the royalty trust units will be volatile. The market price of the royalty trust units could fluctuate significantly for many reasons, including, without limitation:

 

•

as a result of the risk factors listed in this prospectus;

 

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the inability of the underlying properties to achieve production of hydrocarbons;

 

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

 

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

 

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general economic, securities markets and industry conditions.

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, FCX and the Royalty Trust intend to treat the royalty trust units as mineral royalty interests for U.S. federal income tax purposes. But no ruling has been requested from the Internal Revenue Service (the “IRS”) regarding the proper treatment of the royalty trust units; therefore, there can be no assurance that the IRS will not assert, or that a court would not

 

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sustain, 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. Please review carefully the information under the section entitled “U.S. Federal Income Tax Considerations—U.S. Federal Income Tax Consequences of the Ownership and Disposition of the Royalty Trust Units” beginning on page 36, for a description of the material U.S. federal income tax consequences of the ownership and disposition of the royalty trust units.

Please consult your tax advisors as to the specific tax consequences to you 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.

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. Please review carefully the information under the section entitled “U.S. Federal Income Tax Considerations—U.S. Federal Income Tax Consequences of the Ownership and Disposition of the Royalty Trust Units—Tax Consequences to U.S. Royalty Trust Unitholders—Classification and Tax Treatment of the Royalty Trust Units” beginning on page 38, for a more detailed discussion of the availability of percentage depletion deduction to the Royalty Trust unitholders.

The Royalty Trust and FCX encourage holders of royalty trust units to consult their own tax advisors to determine whether and to what extent percentage depletion would be available to them.

The tax treatment of an investment in royalty trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.

In taxable years beginning after December 31, 2012, an individual having modified adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) may be subject to a “medicare tax” equal generally to 3.8% of the lesser of such excess or the individual’s net investment income, which appears to include royalty or interest income derived from investments such as the royalty trust units as well as any net gain from the disposition of royalty trust units.

In addition, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

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,

 

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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 its 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. For more information, see the section entitled “U.S. Federal Income Tax Considerations—U.S. Federal Income Tax Consequences of the Ownership and Disposition of the Royalty Trust Units” beginning on page 36.

Neither FCX nor the Royalty Trust has requested a ruling from the IRS regarding these tax questions, and neither FCX nor the Royalty Trust can assure you that the IRS will not challenge these positions on audit or that a court will not sustain such a challenge.

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 contained in President Obama’s Budget Proposal for Fiscal Year 2013 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.

You will be required to pay taxes on your pro-rata share of the taxable income attributable to the assets of the Royalty Trust even if you 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, you 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 you receive no cash distributions from the Royalty Trust. You may not receive cash distributions from the Royalty Trust equal to your 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 underlying properties may reduce Royalty Trust distributions. While the Royalty Trust, as the owner of the royalty interests, should not be responsible for the costs associated with these accidents, any such accidents may result in the loss of a productive well and associated reserves or interruption of production.

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 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 from the Royalty Trust to the holders of royalty trust units could be reduced or discontinued. In addition, lower oil and gas prices may reduce the likelihood that the underlying properties 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.

 

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The Royalty Trust is dependent on FCX for funding unless and until such time as it may receive income from any production on the underlying properties, and any such income may be insufficient to cover the Royalty Trust’s administrative expenses.

Because none of the underlying properties are at present producing any oil or gas, the Royalty Trust has no source of income. Therefore, it must rely on FCX for funding of its administrative expenses. FCX has agreed to pay annual trust expenses up to a maximum amount of $350,000, to the extent the trust lacks sufficient funds to pay such expenses. 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.

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 Royalty Trust, FCX’s interests and the interests of the Royalty Trust unitholders may not always be aligned. For example, in setting budgets for development and production expenditures for FCX’s properties, including the underlying properties, FCX may make decisions that could adversely affect future production from the underlying properties. Moreover, FCX could decide to sell or abandon some or all of the underlying properties, and that decision may not be in the best interests of the holders of the royalty trust units.

FCX may transfer or abandon underlying properties.

FCX may at any time transfer all or part of the underlying properties. The Royalty Trust unitholders are not entitled to vote on any transfer, and the Royalty Trust will not receive any proceeds of the transfer of the underlying properties. Following any such transfer, the underlying properties will continue to be subject to the royalty interests, but the net proceeds from the transferred underlying properties 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 underlying properties transferred, and FCX would have no continuing obligation to the Royalty Trust for those underlying properties.

The Royalty Trust is limited in duration, may be dissolved upon certain events and the royalty trust units are subject to a call feature after 5 years.

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 amended and restated 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 amended and restated 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 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 unit so long as FCX tenders payment within 30 days of such nine-month period. For more information, see the section entitled “Description of the Royalty Trust Agreement” beginning on page 29.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains “forward-looking statements.” Forward-looking statements are all statements other than statements of historical facts, such as statements about the financial conditions, earnings outlook and prospects of the Royalty Trust. The words “anticipates,” “may,” “can,” “plans,” “believes,” “estimates,” “expects,” “projects,” “intends,” “likely,” “will,” “should,” “to be,” and any similar expressions and/or statements that are not historical facts are intended to identify those assertions as forward-looking statements.

The Royalty Trust cautions readers that forward-looking statements are not guarantees 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 MMR shallow water, ultra-deep Gulf of Mexico prospects covered by the 5% gross overriding royalty interest will not produce hydrocarbons, general economic and business conditions, variations in the market demand for, and prices of, oil and natural gas, drilling results, unanticipated fluctuations in flow rates of producing wells due to mechanical or operational issues (including those experienced at wells operated by third parties where MMR is a participant), changes in oil and natural gas reserve expectations, the potential adoption of new governmental regulations, decisions by FCX not to develop the subject interests, any inability of FCX to develop the subject interests and other factors described herein. The risks and uncertainties identified in this prospectus should be read in conjunction with the other information in this prospectus.

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. The forward-looking statements included in this prospectus are made only as of the date of this prospectus and the Royalty Trust undertakes no obligation to update any forward-looking statements except as required by law.

 

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THE MERGER

Structure of the Merger

On June 3, 2013, FCX and MMR completed the transactions contemplated by the merger agreement by and among MMR, FCX, and Merger Sub. Pursuant to the merger agreement, on June 3, 2013, Merger Sub merged with and into MMR, with MMR surviving the merger as a wholly owned subsidiary of FCX.

Effective Time of the Merger

On June 3, 2013, the certificate of merger was duly filed with the Secretary of State of the State of Delaware and the merger was completed.

Merger Consideration

Each share of MMR common stock issued and outstanding immediately prior to the effective time of the merger, other than any dissenting shares or shares held by FCX and any of its subsidiaries, was converted into the right to receive $14.75 in cash, without interest and 1.15 royalty trust units (the “merger consideration”). As of the date of this prospectus, none of the subject interests associated with the royalty trust units had any reserves classified as proved, probable or possible (other than MMR’s onshore Lineham Creek well) and none of such subject interests had any associated production. Cash was paid in lieu of any fractional royalty trust units, and cash will be paid in lieu of any fractional royalty trust units that would otherwise be issuable upon conversion of convertible securities.

MMR Convertible Securities

Pursuant to the convertible securities’ respective governing instruments, upon the consummation of the merger, each series of the convertible securities became convertible into the type and amount of merger consideration paid in the merger to holders of MMR common stock, on an as-converted basis. As a result of this feature of the convertible securities, FCX, as the acquiror in the merger, will be obligated to deliver royalty trust units to the holders of the convertible securities in the future, at times and in amounts determined by such holders through their exercise of their conversion rights, and certain royalty trust units held by the selling securityholder, a subsidiary of FCX, are available for this purpose.

In addition, the 2017 notes, the 8% preferred stock and the 5.75% preferred stock are entitled to a “make-whole” premium due to the occurrence of the merger, which provides that any conversions of such securities exercised within a designated period following the merger will be made at an increased conversion rate, as set forth in their respective governing documents.

Legal Proceedings

Between December 11, 2012 and December 26, 2012, ten putative class actions challenging the proposed merger of FCX with MMR were filed purportedly on behalf of a class of MMR stockholders by purported MMR stockholders. Nine were filed in the Court of Chancery of the State of Delaware (the “Court of Chancery”). On January 9, 2013, one of the actions was voluntarily dismissed by the plaintiff. On January 25, 2013, the Court of Chancery consolidated the remaining eight actions into a single action, In re McMoRan Exploration Co. Stockholder Litigation, No. 8132-VCN. One action was also filed on December 19, 2012 in the Civil District Court for the Parish of Orleans of the State of Louisiana: Langley v. Moffett et al., No. 2012-11904. The actions name some or all of the following as defendants: MMR and its directors, FCX, the Royalty Trust, subsidiaries of FCX and Plains Exploration & Production Company. The lawsuits allege, among other things, that members of MMR’s board of directors breached their fiduciary duties to MMR’s stockholders because they, among other things, pursued their own interests at the expense of stockholders, failed to maximize stockholder value with respect to the merger and failed to disclose material facts regarding the merger. These lawsuits seek, among other things, an injunction barring or rescinding the merger, damages and attorney’s fees and costs.

 

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On May 6, 2013, the parties in In re McMoRan Exploration Co. Stockholder Litigation entered into a memorandum of understanding (the MOU) setting forth an agreement to settle the action. The settlement will be subject to, among other things, the execution of a stipulation of settlement by the parties, and final approval by the Court of Chancery. Upon final approval of the settlement by the Court of Chancery, the consolidated action will be dismissed with prejudice and all defendants will be released from any and all claims concerning the MMR Merger as described in the MOU judicial approval.

The action titled Langley v. Moffett et al., No. 2012-11904, filed on December 19, 2012, in the Civil District Court for the Parish of Orleans of the State of Louisiana, was stayed pending final disposition of the consolidated Delaware action.

 

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USE OF PROCEEDS

None of FCX, the selling securityholder or the Royalty Trust will receive any proceeds from the delivery of the royalty trust units by the selling securityholder, a subsidiary of FCX, to holders of the convertible securities upon conversion.

PLAN OF DISTRIBUTION

The royalty trust units offered and sold pursuant to this prospectus will be delivered by the selling securityholder, a subsidiary of FCX, directly to the holders of the convertible securities upon conversion. FCX and the Royalty Trust are required to pay all fees and expenses incident to the registration of the royalty trust units to be offered pursuant to this prospectus in accordance with the terms of the amended and restated trust agreement of the Royalty Trust.

PRICE RANGE OF ROYALTY TRUST UNITS

The royalty trust units currently are not listed on a national securities exchange. The royalty trust units are expected to be quoted on the OTCQX. Quotations on the OTCQX will reflect bid and ask quotations, may reflect inter-dealer prices, without retail markup, markdown or commission, and may not represent actual transactions. Prior to June 3, 2013, there were no royalty trust units outstanding. As of the date of this prospectus, there is no trading price history for the royalty trust units.

As of June 3, 2013, the Royalty Trust has approximately 6,390 record holders of the royalty trust units. The number of record holders was determined from the records of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various brokers, banks, trusts or other nominees.

 

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THE ROYALTY TRUST

The Royalty Trust 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. The Royalty Trust was created to hold certain overriding royalty interests (the “royalty interests”) in hydrocarbons saved and produced from MMR’s shallow water Gulf of Mexico and onshore Gulf Coast ultra-deep exploration prospects (the “subject interests”). MMR owns less than 100% of the working interest in each of the subject interests. On May 29, 2013, Wilmington Trust, National Association, was replaced by BNY Trust of Delaware, as 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., as trustee. On June 3, 2013, in connection with the closing of the merger, a subsidiary of MMR conveyed the overriding royalty interests to the Royalty Trust.

Since 2008, MMR’s ultra-deep drilling activities (below the salt weld, i.e., the listric fault) have confirmed MMR’s geologic model and the highly prospective nature of this emerging geologic trend. Data from seven wells drilled to date tie geologic formations encountered below the salt weld to productive zones onshore, in the deepwater Gulf of Mexico and in Mexico. Each of these seven wells is included in the subject interests, along with additional exploration prospects that will also be burdened by the Royalty Trust. To date, only the Davy Jones No. 1 well has been completed and efforts continue to obtain a measurable flow rate. 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.

AS OF THE DATE OF THIS PROSPECTUS, NONE OF THE SUBJECT INTERESTS ASSOCIATED WITH THE ROYALTY TRUST UNITS HAD ANY RESERVES CLASSIFIED AS PROVED, PROBABLE OR POSSIBLE (OTHER THAN THE LINEHAM CREEK WELL) AND NONE OF SUCH SUBJECT INTERESTS HAD ANY ASSOCIATED PRODUCTION. The Royalty Trust has no ability to influence the exploration or development of the subject interests. In addition, FCX is under no obligation to fund or to commit any other resources to the exploration or development of the subject interests.

 

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DESCRIPTION OF THE SUBJECT INTERESTS

The “subject interests” consist of 20 ultra-deep (target depths generally greater than 18,000 total vertical depth) prospects. The offshore “subject interests” consist of the following: (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: (1) Highlander; (2) Lineham Creek; and (3) Tortuga. All of the subject interests are located in relatively shallow waters offshore of the state of Louisiana, or onshore in Louisiana. MMR does not own 100% of the working interest of any of the subject interests. The 5% gross overriding royalty interests in hydrocarbons saved and produced from the subject interests burden all of MMR’s current leasehold interests associated with such prospects, and will burden any leasehold interests associated with such prospects which are acquired by MMR on or before December 5, 2017 as reflected in the table below (subject to MMR’s right to dispose of its working interest to a percentage not less than the estimated working interests set forth in the table below). Each of the 5% gross overriding royalty interests has been, or will be, proportionately reduced based on MMR’s working interest to equal the product of 5% multiplied by a fraction, the numerator of which is the working interest held by MMR and its affiliates in the applicable subject interest (subject to a cap equal to MMR’s estimated working interest (equal to the working interest MMR owns or expects to acquire and as set forth in the table below) in each subject interest, on a prospect by prospect basis) and the denominator of which is 100% as reflected in the table below. As of December 5, 2012, the date of the merger agreement, the subject interests comprised all of MMR’s ultra-deep prospects and, as of the date of this prospectus, none of the subject interests had any reserves classified as proved, probable or possible (other than the Lineham Creek well) and none of the subject interests had any associated production. Additional ultra-deep prospects developed by MMR will not be included in the subject interests. As of the date of this prospectus, MMR’s independent reserve engineers have assigned initial estimates of 12.9 Bcfe of net proved reserves, 46.6 Bcfe of net probable reserves and 82.2 Bcfe of net possible reserves, associated with interim drilling results through December 31, 2012, from the sands encountered above 24,000 feet in the Lineham Creek well, located on one of the onshore subject interests.

 

Subject Interest Name		Estimated Working Interest				Operator		Estimated Overriding Royalty Interest (5% proportionately reduced to reflect the Estimated Working Interest)
Davy Jones			63.40	%		McMoRan			3.17	%
Blackbeard East			72.00	%		McMoRan			3.6	%
Lafitte			72.00	%		McMoRan			3.6	%
Blackbeard West			69.40	%		McMoRan			3.47	%
England			36.00	%		Undetermined			1.8	%
Barbosa			72.00	%		McMoRan			3.6	%
Morgan			72.00	%		McMoRan			3.6	%
Barataria			72.00	%		McMoRan			3.6	%
Blackbeard West #3			69.40	%		McMoRan			3.47	%
Drake			72.00	%		McMoRan			3.6	%
Davy Jones West			36.00	%		McMoRan			1.8	%
Hurricane			72.00	%		McMoRan			3.6	%
Hook			72.00	%		McMoRan			3.6	%
Captain Blood			72.00	%		McMoRan			3.6	%
Bonnet			72.00	%		McMoRan			3.6	%
Queen Anne’s Revenge			72.00	%		McMoRan			3.6	%
Calico Jack			36.00	%		McMoRan			1.8	%
Highlander			72.00	%		McMoRan			3.6	%
Lineham Creek			36.00	%		Chevron			1.8	%
Tortuga			72.00	%		McMoRan			3.6	%

 

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Ultra-Deep Oil and Gas Prospects Acreage. At March 31, 2013, MMR owned or controlled interests in approximately 534 oil and gas leases in the Gulf of Mexico and onshore Louisiana, covering approximately 385,000 gross acres (240,000 net acres to MMR’s interests), associated with MMR’s ultra-deep prospects which are included in the subject interests. Approximately 66,000 net acres owned by MMR and associated with MMR’s ultra-deep prospects are scheduled to expire in 2013, a portion of which MMR expects to retain by drilling operations or other means. Of the acreage expected to be allowed to expire, approximately 12,000 net acres would have no impact on the specified resource potential, and approximately 4,000 net acres, if the acreage is not reacquired in the future, would reduce the gross unrisked potential of certain prospects from approximately 18 tcfe to approximately 14 tcfe. No specific production volumes associated with the expiring leases has been included in the projections.

The following table shows the oil and gas acreage associated with MMR’s ultra-deep prospects in which MMR owned interests as of March 31, 2013.*

 

		Developed								Undeveloped
		Gross Acres				Net Acres				Gross Acres				Net Acres
Offshore (federal waters)			0				0				255,505				161,389
Onshore Louisiana			0				0				55,442				28,085
Total at March 31, 2013			0				0				310,947				189,474

 

*	In addition, MMR controls approximately 74,500 gross acres (50,600 net acres) by options to lease.

Ultra-Deep Exploration and Development Activities. Since 2008, MMR’s drilling activities in the shallow waters of the Gulf of Mexico below the salt weld (i.e. listric fault) have successfully confirmed MMR’s geologic model and the highly prospective nature of this emerging geologic trend. The data from seven wells drilled to date indicate the presence below the salt weld of geologic formations including Upper/Middle/Lower Miocene, Frio, Vicksburg, Jackson, Yegua, Sparta carbonate, Wilcox, Tuscaloosa and Cretaceous carbonate, which have been prolific onshore, in the deepwater Gulf of Mexico and in international locations. The results of these activities indicate the potential for a major new geologic trend spanning 200 miles in the shallow waters of the Gulf of Mexico and onshore in the Gulf Coast area. Further drilling and flow testing will be required to determine the ultimate potential of this new trend.

MMR has incurred drilling and other related costs for in-progress and/or unproven exploratory wells totaling approximately $1.2 billion at March 31, 2013. In addition, its allocated costs for the working interests acquired in properties associated with MMR’s current in-progress and unproven wells totaled $693.5 million at March 31, 2013.

Lineham Creek Onshore Well

The Lineham Creek exploration prospect, which is located onshore in Cameron Parish, Louisiana has been drilled to a total vertical depth of 29,424 feet. The well recently encountered a mechanical issue. In November 2012, the well encountered pay sands above 24,000 feet, as identified by wireline logs. Independent reserve engineers retained by MMR have assigned initial estimates of proved, probable and possible reserves associated with interim drilling results through December 31, 2012, from the sands encountered above 24,000 feet in this ultra-deep exploratory well including 12.9 Bcfe of net proved reserves, 46.6 Bcfe of net probable reserves and 82.2 Bcfe of net possible reserves. These proved reserves are believed to be the first proved reserves to be recorded in the sub-salt, ultra-deep trend. Development plans will be determined following completion of drilling and evaluation of the well’s deeper objectives. The well, which is targeting Eocene and Paleocene objectives below the salt weld, has a proposed total depth of 30,500 feet. MMR is participating for a 36.0 percent working interest. MMR’s investment in Lineham Creek totaled $62.4 million at March 31, 2013.

 

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Lomond North Onshore Well

The Lomond North ultra-deep prospect, which is located onshore in the Highlander area, primarily in St. Martin Parish, Louisiana, is currently drilling below 20,300 feet. This exploratory well has a proposed total depth of 30,000 feet and is targeting Eocene, Paleocene and Cretaceous objectives below the salt weld. MMR controls rights to approximately 80,000 gross acres in Iberia, St. Martin, Assumption and Iberville Parishes, Louisiana. MMR is operator and currently holds a 72.0 percent working interest. MMR’s investment in Lomond North totaled $66.8 million at March 31, 2013.

Davy Jones

Davy Jones No. 1 completion activities initiated in the fourth quarter of 2011, and initial flow testing procedures were attempted in March 2012; however, MMR encountered mechanical issues with the well’s originally designed perforating equipment. Subsequent activities to flow the well were conducted in 2012, and additional procedures to achieve a measurable flow are required. Future plans will incorporate data gained to date at Davy Jones as well as core and log data from the in progress well at Lineham Creek, located onshore approximately 50 miles northwest of Davy Jones. The rig was moved off location in February 2013 while a large-scale hydraulic fracture treatment is designed to penetrate the Wilcox reservoirs to facilitate hydrocarbon movement into the wellbore. MMR’s investment in well drilling, completion and other costs specifically attributable to Davy Jones No. 1 approximated $339.4 million as of March 31, 2013.

Long-lead equipment required for completing and testing Davy Jones No. 2 is expected to be available in the third quarter of 2013. Davy Jones is located on a 20,000 acre structure that has multiple additional drilling opportunities.

MMR expects to commence operations at the Davy Jones complex prior to July 24, 2013 or request approval of a lease expiration extension by the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE).

MMR has drilled two sub-salt wells in the Davy Jones field. The Davy Jones No. 1 well logged 200 net feet of pay in multiple Wilcox sands, which were all full to base. The Davy Jones offset appraisal well (Davy Jones No. 2), which is located two and a half miles southwest of Davy Jones No. 1, confirmed 120 net feet of pay in multiple Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect, and also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections.

MMR is the operator and holds a 63.4 percent working interest and a 50.2 percent net revenue interest in Davy Jones. MMR’s total investment in Davy Jones, which includes $474.8 million in allocated property acquisition costs, totaled approximately $1 billion at March 31, 2013.

Blackbeard East

The Blackbeard East ultra-deep exploration by-pass well, which is located on South Timbalier Block 144 in 80 feet of water, was drilled to a total depth of 33,318 feet in January 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate. MMR’s lease rights to South Timbalier Block 144 were scheduled to expire on August 17, 2012. Prior to the expiration, MMR submitted an application for Suspension of Production (SOP) to the BSEE to allow MMR to continue to hold its rights to the lease. In addition, MMR subsequently submitted to BSEE an Application for Permit Modification (APM) related to its development plans for Blackbeard East to test and complete the Middle Miocene sands in the South Timbalier 144 #1 BP1 well. In April 2013 BSEE approved MMR’s APM for completion of the Blackbeard East well. MMR continues to pursue, with BSEE, approval of a unit to facilitate development of the Blackbeard East prospect. The unit would consist of South Timbalier Blocks 144, 145, 164 and 165. MMR continues to hold its rights to the South Timbalier 144

 

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lease while the SOP application is under administrative consideration by BSEE. MMR’s ability to continue to preserve its interest in the South Timbalier 144 lease will require final approval of the SOP from BSEE, and our ability to continue to preserve the entirety of the Blackbeard East prospect will require final approval by BSEE of the SOP and the unit.

MMR holds a 72.0 percent working interest and a 57.4 percent net revenue interest in Blackbeard East. MMR’s total investment in Blackbeard East, which includes $130.5 million in allocated property acquisition costs, totaled $311.4 million at March 31, 2013.

Lafitte

The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Upper Eocene, and Sparta carbonate. MMR’s lease rights to Eugene Island Block 223 were scheduled to expire on October 8, 2012. Prior to the lease expiration, MMR submitted its initial development plans to complete and test the Jackson/Yegua sands in the upper Eocene for Lafitte to the BSEE. This completion will require the development of 30,000 psi equipment. MMR continues to hold its rights to this lease while the development plans are under administrative consideration by the BSEE.

MMR holds a 72.0 percent working interest and a 58.3 percent net revenue interest in Lafitte. MMR’s total investment in Lafitte, which includes $35.8 million in allocated property acquisition costs, totaled $198.3 million at March 31, 2013.

Blackbeard West Unit

The Blackbeard West No. 1 well was drilled to a total depth of 32,997 feet in October 2008 and logs below 30,067 feet indicated potential hydrocarbon bearing zones measuring 220 net feet requiring further evaluation. The well has been temporarily abandoned while MMR evaluates whether to drill deeper or complete the well to test the existing zones. MMR’s lease rights to the Blackbeard West Unit (including Blackbeard West No. 1) are currently held by activities associated with Blackbeard West No. 2 (discussed below) while its evaluation of Blackbeard West No. 1 continues. MMR holds a 69.4 percent working interest and a 56.5 percent net revenue interest in Blackbeard West No. 1. MMR’s investment in the Blackbeard West No. 1 drilling costs approximated $31.1 million at March 31, 2013.

The Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal Block 188 was drilled to a total depth of 25,584 feet in January 2013. Through logs and core data, MMR has identified three potential hydrocarbon bearing Miocene sand sections between approximately 20,800 and 24,000 feet. Initial completion efforts are expected to focus on the development of approximately 50 net feet of laminated sands in the Middle Miocene located at approximately 24,000 feet. Additional development opportunities in the well bore include approximately 80 net feet of potential low-resistivity pay at approximately 22,400 feet and an approximate 75 foot gross section at approximately 20,900 feet. Pressure and temperature data indicate that a completion at these depths could utilize conventional equipment and technologies. MMR holds a 69.4 percent working interest and a 53.1 percent net revenue interest in Ship Shoal Block 188. MMR’s investment in Blackbeard West No. 2 totaled $92.9 million at March 31, 2013. In addition, MMR has approximately $27.6 million of leasehold costs for the Blackbeard West unit resulting from allocated property acquisition costs.

Hurricane Deep

The Hurricane Deep well, which is located in 12 feet of water on South Marsh Island Block 217, was drilled to a total depth of 21,378 feet in July 2011. Log results indicated the presence of Operc and Gyro sands in areas not subject to the override that MMR determined could be pursued in an updip location. The well has been

 

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temporarily abandoned to preserve the wellbore while MMR evaluates opportunities to sidetrack or deepen the well. MMR’s total investment in Hurricane Deep, which includes $24.8 million in allocated property acquisition costs, totaled $55.5 million at March 31, 2013.

If current or future activities are not successful in generating production that will allow MMR to recover all or a portion of our investment in any of our in-progress and/or unproven wells, MMR may be required to write down its investment in such properties to their estimated fair value.

Ultra-Deep Exploratory and Development Drilling. As of December 31, 2012, there were no productive or dry exploratory or development wells associated with the ultra-deep prospects, which does not include 9 gross (6.2 net) in-progress wells at December 31, 2012, 8 gross (5.5 net) in-progress wells at December 31, 2011 and 6 gross (3.9 net) in-progress wells at December 31, 2010. There are no updates for March 31, 2013.

 

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DESCRIPTION OF THE ROYALTY INTERESTS

The royalty interests conveyed to the Royalty Trust consist of overriding royalty interests in hydrocarbons saved and produced from certain MMR shallow water Gulf of Mexico and onshore Gulf Coast ultra-deep exploration prospects.

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. 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 expense 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 holders of royalty trust units will not have such rights. Unlike royalty interests that are retained by the mineral rights owner that grants the leasehold, an “overriding” royalty is generally granted to a party that does not own any interest in the underlying minerals, and the overriding royalty interest expires when production ceases and the lease terminates. Additionally, an owner of a working interest may generally decline participation in any operation and allow other consenting working interest owners to conduct such operations, as provided under the applicable operating agreement. In such instances, the overriding royalty interest owner generally would not be entitled to its share of production until the consenting working interest owners recoup a multiple of costs incurred with respect to such operations as set forth in the applicable operating agreement.

 

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The overriding royalty interest in the subject interests is a 5% gross overriding royalty interest (proportionately reduced based on MMR’s working interest to equal the product of 5% multiplied by a fraction, the numerator of which is the working interest held by MMR and its affiliates in the applicable subject interest (subject to a cap equal to MMR’s estimated working interest (equal to the working interest MMR owns or expects to acquire and as set forth herein) in each subject interest, on a prospect by prospect basis) and the denominator of which is 100%) in hydrocarbons saved and produced from certain MMR shallow water Gulf of Mexico and onshore Gulf Coast ultra-deep exploration prospects. MMR owns less than 100% of the working interest in each of the subject interests. The table below reflects MMR’s estimated working interest (equal to the working interest MMR owns or expects to acquire) in each of the subject interests.

 

Subject Interest Name		Estimated Working Interest
Davy Jones			63.40	%
Blackbeard East			72.00	%
Lafitte			72.00	%
Blackbeard West			69.40	%
England			36.00	%
Barbosa			72.00	%
Morgan			72.00	%
Barataria			72.00	%
Blackbeard West #3			69.40	%
Drake			72.00	%
Davy Jones West			36.00	%
Hurricane			72.00	%
Hook			72.00	%
Captain Blood			72.00	%
Bonnet			72.00	%
Queen Anne’s Revenge			72.00	%
Calico Jack			36.00	%
Highlander			72.00	%
Lineham Creek			36.00	%
Tortuga			72.00	%

Pursuant to the merger agreement, on June 3, 2013, MMR conveyed to the Royalty Trust pursuant to a master conveyance agreement (the “master conveyance”) the overriding royalty interests in the subject interests. The overriding royalty interest conveyed to the Royalty Trust applies only to those hydrocarbons saved and produced from the MMR shallow water Gulf of Mexico and onshore Gulf Coast ultra-deep exploration prospects, as discussed above and as specifically set forth in the applicable recordable conveyance.

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 overriding royalty interests hydrocarbons are valued at the wellhead (after deduction or withholding of specified taxes and less any specified post-production costs) and neither MMR nor FCX has any duty to transport or market the produced hydrocarbons away from the wellhead without cost. The overriding royalty interest hydrocarbons are subject to and bear production and other like taxes.

The Royalty Trust has no ability to influence the exploration or development of the subject interests, and FCX has no obligation to commit or expend drilling, exploration or development capital with respect to 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.

 

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DESCRIPTION OF THE ROYALTY TRUST AGREEMENT

On June 3, 2013, an amended and restated trust agreement with respect to the trust was entered into by the depositor and the trustees. From that date, the Royalty Trust and the respective rights and obligations of FCX, the trustees and the Royalty Trust unitholders with respect to the Royalty Trust are governed by the amended and restated trust agreement (the “amended and restated trust agreement”). The following discussion summarizes material terms of the amended and restated trust agreement. You are urged to read carefully the full text of the amended and restated trust agreement, a copy of which has been filed as an exhibit to the registration statement of which this prospectus forms a part.

Creation and Organization of the Royalty Trust. The Royalty Trust was created 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, 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., as trustee.

Upon the execution of the amended and restated trust agreement, the Royalty Trust issued 230,172,696 royalty trust units, which includes royalty trust units held by a subsidiary of FCX for the satisfaction of conversions of the convertible securities. The make-whole premiums applicable to the convertible securities, which are available for a limited time after the closing of the merger, account for approximately 3,318,807, or 1.4%, of the royalty trust units issued. The convertible security holders may choose not to convert and FCX will retain any royalty trust units that are not issued to these outstanding convertible security holders.

The Royalty Trust was created to acquire and hold the royalty interests for the benefit of the Royalty Trust unitholders. The royalty interests are passive in nature, and neither the trustees 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. None of FCX, MMR or any other operators of the underlying properties included in the subject interests has any contractual commitments to the Royalty Trust to conduct drilling on the underlying properties or to maintain their ownership interest in any of these underlying properties. For a description of the royalty interests and the subject interests and other information relating to them, see the sections entitled “Description of the Royalty Interests” beginning on page 27 and “Description of the Subject Interests” beginning on page 22.

The beneficial interest in the Royalty Trust was divided into 230,172,696 royalty trust units, and each royalty trust unit represents an equal undivided portion of the beneficial interest in the Royalty Trust. Pursuant to the merger agreement, holders of MMR common stock received 1.15 royalty trust units for each share of MMR common stock as consideration for their shares of MMR common stock. For additional information concerning the royalty trust units, see the section entitled “Description of the Royalty Trust Units” beginning on page 33.

Assets of the Royalty Trust. The assets of the Royalty Trust consist of the royalty interests and cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the Royalty Trust unitholders, if any.

Duties and Limited Powers of the Trustee. The duties of the trustee are specified in the amended and restated 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.

 

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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 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. FCX has agreed to lend money to the Royalty Trust to fund certain of the Royalty Trust’s ordinary administrative expenses in excess of its funds available to pay such expenses and the amount to be paid by FCX, on an unsecured, interest-free basis, as set forth in the amended and restated trust agreement.

The only asset the Royalty Trust may acquire is 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 amended and restated 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 amended and restated 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 amended and restated 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 amended and restated 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; 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 the trustee 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. For more information, see the section entitled “Description of the Royalty Trust Units—Liability of the Royalty Trust Unitholders and the Royalty Trust” beginning on page 34. The trustee ensures that all contractual liabilities of the Royalty Trust are limited to the assets of the Royalty Trust.

 

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Funding of Administrative Expenses. If the Royalty Trust’s expenses exceed its funds available to pay such expenses, FCX will fund the administrative expenses and reporting obligations of the Royalty Trust and all other expenses, up to a maximum amount of $350,000 per year.

FCX has agreed to lend money to the Royalty Trust to fund certain of the Royalty Trust’s ordinary administrative expenses in excess of its funds available to pay such expenses and the amount to be paid by FCX, on an unsecured, interest-free basis, as set forth in the amended and restated trust agreement.

Amendment of Trust Agreement. Any amendment of the amended and restated trust agreement requires a vote of holders of 66 ²/₃% 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 66 ²/₃%) 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 amended and restated 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 amended and restated 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 is entitled to annual compensation of $200,000 (provided that until the first year in which the Royalty Trust receives any payment pursuant to the conveyances of the royalty interests, the annual compensation shall be $150,000), plus reimbursement of 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 assets.

Approval of Matters by Royalty Trust Unitholders. Unless otherwise required by the amended and restated 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 unitholder is present). Pursuant to the amended and restated trust agreement, the affirmative vote of the holders of 80% (which, after June 3, 2018, shall be reduced to 66 ²/₃%) of the outstanding royalty trust units held by persons other than FCX or its subsidiaries will be required to terminate the Royalty Trust or approve a sale of all or substantially all of the royalty interests, whether in a single transaction or series of transactions. The affirmative vote of the holders of 66 ²/₃% of the outstanding royalty trust units will be required to (1) amend the amended and restated 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 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.

FCX Call Rights. FCX will maintain a call right with respect to the outstanding royalty trust units at $10.00 per royalty trust unit, provided that the call right may not be exercised prior to June 3, 2018. In addition, at any

 

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time after June 3, 2018, if the VWAP (as defined below) per royalty trust unit is equal to $0.25 or less for the immediately preceding consecutive nine-month period, FCX will maintain the right to 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. “VWAP” per royalty trust unit on any trading day means the market price of one royalty trust unit from the opening of trading on the relevant trading day until the close of trading on the relevant trading day determined, using a volume-weighted average method. If the VWAP of the royalty trust units cannot be determined, the closing price of the royalty trust units for the relevant trading day, on the market or system that the royalty trust units are most commonly quoted or traded, will be substituted for the VWAP.

Duration of the Trust. The Royalty Trust will dissolve on the earlier of (i) June 3, 2033, (ii) the sale of all of the royalty interests, (iii) upon a vote 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, (iv) upon the election of the Trustee following its resignation for cause (as more fully described in the amended and restated trust agreement) or (v) the exercise of the FCX call rights described in the preceding 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 amended and restated trust agreement (in which case the royalty interests may extend through June 3, 2033).

 

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DESCRIPTION OF THE ROYALTY TRUST UNITS

General

Each royalty trust unit represents an undivided share of beneficial interest in the Royalty Trust. Each holder of a royalty trust unit has the same rights as the holder of any other royalty trust unit. Upon the execution of the amended and restated trust agreement, the Royalty Trust issued 230,172,696 royalty trust units, which includes royalty trust units held by a subsidiary of FCX for the satisfaction of conversions of the convertible securities. The make-whole premiums applicable to the convertible securities, which are available for a limited time after the closing of the merger, account for approximately 3,318,807, or 1.4%, of the royalty trust units issued. The convertible security holders may choose not to convert and FCX will retain any royalty trust units that are not issued to these outstanding convertible security holders.

Distributions and Income Computations

Each quarter, the trustee will determine 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 (which may, after such time as any of the royalty interests commence generating cash proceeds, include loans from FCX in the circumstances described in the section entitled “Description of the Royalty Trust Agreement—Funding of Administrative Expenses” beginning on page 31, 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 decides to hold as a reserve against future liabilities. The trustee shall establish a cash reserve equal to such amount. The Royalty Trust unitholders that own their royalty trust units on the close of business on the record date for each calendar quarter (the “quarterly record date”) 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 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 would be amortized for tax purposes over several quarterly periods. For more information, see the section entitled “U.S. Federal Income Tax Considerations—U.S. Federal Income Tax Consequences of the Ownership and Disposition of the Royalty Trust Units” beginning on page 36.

Transfer of the Royalty Trust Units

The Royalty Trust unitholders are permitted to transfer their royalty trust units in accordance with the amended and restated trust agreement. The trustee will not require either the transferor or transferee to pay a service charge for any transfer of a 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 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, the Royalty Trust will mail to each Royalty Trust unitholder of record on a quarterly record date a report, which may be a copy of the Royalty Trust’s quarterly report on Form 10-Q, showing the assets, liabilities and distributable income of the Royalty

 

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Trust for the quarter. Within 90 days following the end of each year, the Royalty Trust will mail to the Royalty Trust unitholders of record, as of a date to be selected by the trustee, an annual report, which may be a copy of the Royalty Trust’s annual report on Form 10-K, containing audited financial statements of the Royalty Trust. In each case, the foregoing obligations shall be deemed satisfied if the trustee files a copy of the Royalty Trust’s annual report on Form 10-K and a copy of the Royalty Trust’s quarterly reports on Form 10-Q on the Electronic Data Gathering, Analysis, and Retrieval (EDGAR) system maintained by the SEC or otherwise makes such reports publicly available on an Internet website that is generally available to the public.

The Royalty Trust will file all required Royalty Trust federal and state income tax and information returns. Within 75 days following the end of each fiscal year, the Royalty Trust will prepare and mail 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.

Each Royalty Trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours 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 DGCL. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

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.

Voting Rights of the Royalty Trust Unitholders

The Royalty Trust unitholders’ voting rights are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Royalty Trust unitholders or for annual or other periodic re-election of the trustee.

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. Each Royalty Trust unitholder will be entitled to one vote for each royalty trust unit owned.

Unless otherwise required by the amended and restated 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 an unaffiliated Royalty Trust unitholder is present). The affirmative vote of the holders of 80% (which, after June 3, 2018, shall be reduced to 66 ²/₃%) of the outstanding royalty trust units held by persons other than FCX or its subsidiaries will be required to terminate the Royalty Trust or approve a sale of all or substantially all of the royalty interests, whether in a single transaction or series of transactions. The affirmative vote of the holders of 66 ²/₃% of the outstanding royalty trust units will be required to (1) amend an amended and restated 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

 

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trust units), (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.

 

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U.S. FEDERAL INCOME TAX CONSIDERATIONS

U.S. Federal Income Tax Consequences of the Ownership and Disposition of the Royalty Trust Units

The following discussion is a general summary of the material U.S. federal income tax considerations of the ownership and disposition of the royalty trust units. The following discussion does not address any aspects of U.S. taxation other than U.S. federal income taxation. This discussion does not address any U.S. federal estate or gift tax laws or any foreign, state or local tax consequences of the ownership and disposition of royalty trust units.

FCX AND THE ROYALTY TRUST URGE YOU TO CONSULT YOUR OWN TAX ADVISOR AS TO THE SPECIFIC TAX CONSEQUENCES TO YOU 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 (INCLUDING CHANGES IN APPLICABLE TAX LAWS AND ANY PENDING OR PROPOSED LEGISLATION) IN LIGHT OF YOUR PARTICULAR CIRCUMSTANCES.

All references to “Royalty Trust unitholders” (including U.S. Royalty Trust unitholders and non-U.S. Royalty Trust unitholders as defined below) are to beneficial owners of the royalty trust units. This summary does not address the effect of the U.S. federal estate or gift tax laws or the tax considerations arising under the law of any state, local or non-U.S. jurisdiction. Moreover, the discussion does not address all aspects of U.S. federal income taxation that may be relevant to a Royalty Trust unitholder in light of that holder’s particular circumstances or to a holder subject to special rules (such as a bank, insurance company or other financial institution, broker or dealer in securities or commodities, regulated investment company, real estate investment trust, tax-exempt organization, person subject to the alternative minimum tax, trader in securities that elects to use a mark-to-market method of accounting for its securities holdings, “controlled foreign corporation” or “passive foreign investment company,” person that is an S-corporation, partnership or other pass-through entity, person that own its interest in the royalty trust units through an S-corporation, partnership or other pass-through entity, person that at any time own more than 5% of the aggregate fair market value of the royalty trust units, expatriate and certain former citizen or long-term resident of the United States, U.S. person whose functional currency is not the U.S. dollar, person who hold the royalty trust units as a position in a hedging transaction, “straddle,” “conversion transaction” or other risk reduction transaction, or person deemed to sell the royalty trust units under the constructive sale provisions of the Code. This discussion is based on the Code, applicable Treasury regulations, administrative interpretations and court decisions, each as in effect as of the date of this prospectus and all of which are subject to change, possibly with retroactive effect.

Accordingly, Royalty Trust unitholders are encouraged to consult their own tax advisor as to the particular consequences to them of the ownership and disposition of an investment in royalty trust units, including the applicability of any U.S. federal income, federal estate or gift tax, state, local and foreign tax laws, changes in applicable tax laws and any pending or proposed legislation.

No ruling has been requested from the IRS regarding any matter affecting the royalty trust or Royalty Trust unitholders. Instead, the Royalty Trust relies on opinions of counsel. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the royalty trust units and the prices at which royalty trust units trade. Furthermore, the tax treatment of the Royalty Trust, or of an investment in the Royalty Trust, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Weil, Gotshal & Manges LLP and are based on the accuracy of the representations made by MMR and the Royalty Trust.

 

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As used herein, the term “U.S. Royalty Trust unitholder” means a beneficial owner of royalty trust units that for U.S. federal income tax purposes is:

 

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an individual who is a citizen or a resident of the United States for U.S. federal income tax purposes;

 

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a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia;

 

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an estate the income of which is subject to U.S. federal income taxation regardless of its source; or

 

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a trust if it is subject to the primary supervision of a U.S. court and the control of one or more U.S. persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. treasury regulations to be treated as a U.S. person.

The term “non-U.S. Royalty Trust unitholder” means any beneficial owner of a royalty trust unit, other than an entity that is classified for U.S. federal income tax purposes as a partnership, that is not a U.S. Royalty Trust unitholder.

If a partnership (including for this purpose any entity or arrangement treated as a partnership for U.S. federal income tax purposes) is a beneficial owner of royalty trust units, the tax treatment of a partner in the partnership depends upon the status of the partner and the activities of the partnership. A Royalty Trust unitholder that is a partnership, and the partners in such partnership, should consult their own tax advisors about the U.S. federal income tax consequences of owning and disposing of royalty trust units.

Classification and Taxation of the Royalty Trust

In the opinion of Weil, Gotshal & Manges LLP, for U.S. federal income tax purposes, the Royalty Trust will be treated as a grantor trust and not as an unincorporated business entity. 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. A grantor trust files an information return, reporting all items of income or deduction which must be included in the tax returns of the Royalty Trust unitholders based on their respective accounting methods and taxable years without regard to the accounting method and tax year of the Royalty Trust. Each Royalty Trust unitholder, depending upon its accounting method, will recognize taxable income when the Royalty Trust receives or accrues it, even if it is not distributed until later.

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 remainder of the discussion below is based on Weil, Gotshal & Manges LLP’s opinion that the Royalty Trust will be classified as a grantor trust for U.S. federal income tax purposes.

Reporting Requirements for Widely-Held Fixed Investment Trusts

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

 

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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.

Tax Rates

Beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 20%. Moreover these rates are subject to change by new legislations at any time.

The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals and certain estates and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income would generally include interest income derived from investments such as the royalty trust units and gain realized by a Royalty Trust unitholder from a sale of royalty trust units. In the case of an individual, the tax will be imposed on the lesser of (i) the Royalty Trust unitholder’s net income from all investments, and (ii) the amount by which the Royalty Trust unitholder’s modified adjusted gross income exceeds $250,000 (if the Royalty Trust unitholder is married and filing jointly or a surviving spouse) or $200,000 (if the Royalty Trust unitholder is not married). In the case of an estate or trust, the tax will be imposed on the lesser of (1) undistributed net investment income, or (2) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Tax Consequences to U.S. Royalty Trust Unitholders

Classification and Tax Treatment of the Royalty Trust Units. The royalty interests held by the Royalty Trust have the tax characteristics of mineral royalty interests to the extent they are, at the time of their creation, reasonably expected to have an economic life that corresponds substantially to the economic life of the mineral property or properties burdened thereby. Payments out of production that are received in respect of a mineral interest that constitutes a 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.

In contrast, the royalty interest held by the Royalty Trust has the tax characteristics of production payments governed by Section 636 of the Code to the extent they are not, at the time of their creation, reasonably expected to extend in substantial amounts over the entire productive lives of the mineral property or properties they burden. Payments out of production that are received in respect of a mineral interest that constitutes a production payment for federal income tax purposes are treated under current law as consisting of a receipt of principal and interest on a nonrecourse debt obligation, with the interest component being taxable as ordinary income.

The tax treatment of royalty interests in specified developed wells that have been drilled is well developed. The law is less developed in the area of royalty interests in prospects that are only exploration concepts, on which there is no production and there are no reserves classified as proved, probable or possible. As a result, the treatment of the royalty trust units is uncertain, and counsel is unable to express any opinion as to their proper tax treatment. Based on the state of facts as of the date hereof, FCX and the Royalty Trust intend to treat the royalty trust units as mineral royalty interests for U.S. federal income tax purposes; however, there can be no assurance that the IRS will not assert, or that a court would not sustain, that the royalty trust units should be treated as, with respect to one or more of the prospects, debt instruments for U.S. federal income tax purposes subject to the Treasury Regulations applicable to contingent payment debt instruments (the “CPDI regulations”). Moreover, it is possible that there could be a change in the relevant facts that would cause FCX and the Royalty Trust to treat the royalty trust units as production payments as to one or more of the prospects. Accordingly, the summary below includes discussion of the tax consequences of the royalty trust units being treated as production payments subject to the CPDI regulations.

 

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Royalty Trust Units Treated as Mineral Royalty Interests. Payments out of production that are received 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 depletion allowance must be computed separately by each Royalty Trust unitholder for each oil or gas property, within the meaning of Section 614 of the Code.

Percentage depletion is generally available with respect to Royalty Trust unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, oil and natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the Royalty Trust unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the Royalty Trust unitholder from the property for each taxable year, computed without the depletion allowance.

A Royalty Trust unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the Royalty Trust unitholder’s average daily production of domestic oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic oil and natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a Royalty Trust unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, the deduction for domestic production activities, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the Royalty Trust unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

In addition to the limitations on percentage depletion discussed above, President Obama’s budget proposal for the fiscal year 2013 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, in which case only cost depletion would be available (as described below). It is uncertain whether this or any other legislative proposals will ever be enacted and, if so, when any such proposal would become effective.

The Royalty Trust unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the Royalty Trust unitholder’s allocated share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the Royalty Trust unitholder’s share of the total adjusted tax basis in the property. Each Royalty Trust unitholder will compute cost depletion using their basis in their royalty trust units. Information is provided to each Royalty Trust unitholder reflecting how his basis should be allocated among each property represented by his royalty trust units.

It should be noted that the deductions for depletion may be itemized deductions, the deductibility of which would be subject to limitations that disallow itemized deductions that are less than 2% of a taxpayer’s adjusted gross income, or reduce the amount of itemized deductions that are otherwise allowable by the lesser of (i) 3% of (A) adjusted gross income over (B) $100,000 ($50,000 in the case of a separate return filed by a married

 

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individual), subject to adjustment for inflation and (ii) 80% of the amount of itemized deductions that are otherwise allowable, or both. Although the matter is not free from doubt, deductions in respect of basis recovery should not be itemized deductions, as the deductions should, under Section 62(a)(4) of the Code, be considered deductions that are attributable to property held for the productions of royalty income.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the Royalty Trust unitholders. Further, because depletion is required to be computed separately by each Royalty Trust unitholder and not by the Royalty Trust, 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 percentage depletion would be available to them.

Royalty Trust Units Treated as Production Payments. As discussed above, there can be no assurance that the IRS will not assert, or that a court would not sustain, that the royalty trust units should be treated as production payments under Section 636 of the Code or otherwise as a debt instrument for U.S. federal income tax purposes that is subject to the CPDI regulations.

Under the CPDI regulations, a U.S. Royalty Trust unitholder generally would be required to accrue income on the royalty trust units in the amounts described below, regardless of whether the U.S. Royalty Trust unitholder uses the cash or accrual method of tax accounting. The CPDI regulations provide that a U.S. Royalty Trust unitholder must accrue an amount of ordinary interest income for U.S. federal tax purposes, for each accrual period prior to and including the maturity date of the debt instrument that equals:

 

•

the product of (i) the adjusted issue price of the debt instrument represented by ownership of royalty trust units as of the beginning of the accrual period; and (ii) the comparable yield to maturity (as defined below) of such debt instrument, adjusted for the length of the accrual period;

 

•

divided by the number of days in the accrual period; and

 

•

multiplied by the number of days during the accrual period that the Royalty Trust unitholder held the royalty trust units.

For these purposes, the “issue price” of the debt instrument represented by each production payment held by the Royalty Trust is the portion of the fair market value of the royalty trust units on June 3, 2013 that is allocable to the production payment based on the relative fair market value of the production payment to the other assets of the Royalty Trust. The “adjusted issue price” of such a debt instrument is its issue price increased by any interest income previously accrued, determined without regard to any adjustments to interest accruals described below, and decreased by the projected amount of any payments scheduled to be made with respect to the debt instrument at an earlier time (without regard to the actual amount paid).

Under the CPDI regulations, MMR would be required to establish the comparable yield for the debt instrument represented by ownership of the royalty trust units. The term “comparable yield” means the annual yield MMR would be expected to pay, as of June 3, 2013, on a fixed rate debt security with no contingent payments but with terms and conditions otherwise comparable to those of the debt instruments represented by ownership of royalty trust units. The CPDI regulations also require that MMR provide to the Royalty Trust, solely for determining the amount of interest accruals for U.S. federal income tax purposes, a schedule of the projected amounts of payments (the “projected payments”), on the debt instrument held by the Royalty Trust. These payments set forth on the schedule must produce a total return on such debt instrument equal to its comparable yield. Amounts treated as interest under the CPDI regulations are treated as original issue discount for all purposes of the Code.

Under the CPDI regulations, if the Royalty Trust receives in a taxable year actual payments with respect to the debt instrument held by the Royalty Trust that in the aggregate exceed the total amount of projected payments

 

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for that taxable year, the Royalty Trust unitholders would incur a “net positive adjustment” equal to the amount of such excess. The Royalty Trust unitholders would treat a “net positive adjustment” as additional ordinary interest income for that taxable year.

Conversely, if the Royalty Trust receives in a taxable year actual payments with respect to the debt instrument held by the Royalty Trust that in the aggregate are less than the amount of projected payments for that taxable year, the Royalty Trust unitholders would incur a “net negative adjustment” under the CPDI regulations equal to the amount of such deficit. This adjustment would (a) first reduce the Royalty Trust unitholders’ interest income on the debt instrument held by the Royalty Trust for that taxable year, and (b) to the extent of any excess after the application of (a) give rise to an ordinary loss to the extent of the Royalty Trust unitholders’ interest income on such debt instrument during prior taxable years, reduced to the extent such interest was offset by prior net negative adjustments. Any negative adjustment in excess of the amount described in (a) and (b) carries forward, as a negative adjustment to offset future interest income in respect of the debt instrument held by the royalty trust or to reduce the amount realized on a sale, exchange, conversion or retirement of such debt instrument.

If the royalty trust units are treated as production payments, under Section 636 of the Code or otherwise as a debt instrument, neither the Royalty Trust nor the Royalty Trust unitholders would be entitled to claim depletion deductions with respect to the royalty trust units or the subject interests.

Royalty Trust Administrative Expenses. Expenses of the Royalty Trust include administrative expenses of the trustee. The deductions so allowed may be itemized deductions which may be subject to limitations on deductibility. Under these rules, administrative expenses attributable to the royalty trust units are miscellaneous itemized deductions that generally have to be aggregated with an individual Royalty Trust unitholder’s other miscellaneous itemized deductions. These rules disallow itemized deductions that are less than 2% of a taxpayer’s adjusted gross income, or reduce the amount of itemized deductions that are otherwise allowable by the lesser of (i) 3% of (A) adjusted gross income over (B) $100,000 ($50,000 in the case of a separate return by a married individual), subject to adjustment for inflation, and (ii) 80% of the amount of itemized deductions that are otherwise allowable, or both. Although the matter is not free from doubt, deductions with respect to such administrative expenses should not be itemized deductions, as the deductions should, under Section 62(a)(4) of the Code, be considered deductions that are attributable to property held for the production of royalty income. If the royalty trust units are treated as production payments under Section 636 of the Code, however, deductions with respect to such administrative expenses should be itemized deductions subject to the limitations described above. Royalty Trust expenses that are borne by FCX may result in income for federal income tax purposes to the Royalty Trust unitholders.

Disposition of Royalty Trust Units. For U.S. federal income tax purposes, a sale of royalty trust units is treated as a sale by the U.S. Royalty Trust unitholder of his interest in the assets of the Royalty Trust. Generally, a holder recognizes gain or loss on the sale or exchange of his royalty trust units measured by the difference between the amount realized on the sale or exchange and his adjusted basis for such royalty trust units. Unless the royalty trust units are treated as production payments under Section 636 of the Code, gain or loss on the sale of royalty trust units by a holder who is not a dealer of the royalty trust units is generally a capital gain or loss. In the case of non-corporate taxpayers, such capital gains are taxable at a maximum rate of 20% if the royalty trust units have been held for more than one year. A portion of the gain is treated as ordinary income to the extent of the depletion recapture amount explained below.

A Royalty Trust unitholder’s basis in his royalty trust units is equal to the fair market value of such royalty trust units on the date of conversion of the convertible security, reduced by deductions for depletion claimed by the holder, but not below zero. Upon the sale of royalty trust units, the holder must treat as ordinary income his or her depletion recapture amount equal to the lesser of the gain on such sale or the sum of the prior depletion deductions taken with respect to the royalty trust units, but not in excess of the initial basis of the royalty trust units. In addition, the IRS could take the position that a portion of the sales proceeds is ordinary income to the extent of any accrued income at the time of the sale that was allocable to the royalty trust units sold even though the cash representing such income had not been distributed to the selling Royalty Trust unitholder.

 

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Should the IRS treat the royalty trust units as a production payment under Section 636 of the Code, the CPDI regulations require that gain recognized upon a sale or exchange of a royalty trust unit attributable to the royalty trust units (the amount of which is reduced by any unused adjustments as discussed above) will generally be treated as ordinary interest income. Any loss will be ordinary loss to the extent of interest previously included in income (reduced by any negative adjustments thereto), and thereafter, capital loss (which will be long-term if the royalty trust unit is held for more than one year). Net capital loss may offset no more than $3,000 of ordinary income in the case of individuals, and in the case of corporations may only be used to offset capital gain.

Backup Withholding. Backup withholding is currently imposed at a rate of 28%. Backup withholding may apply with respect to payments received, including distributions of trust income, unless the Royalty Trust unitholder receiving such a payment (i) is an exempt holder (generally, a corporation, tax-exempt organization, qualified pension or profit-sharing trust, individual retirement account, or nonresident alien individual who or which, when required, certifies as to his, her or its status) or (ii) provides a certificate containing the holder’s name, address, correct federal taxpayer identification number and a statement that the holder is a U.S. person and is not subject to backup withholding.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules are allowable as a refund from the IRS or credit against a holder’s U.S. federal income tax liability provided the required information is timely furnished to the IRS.

Tax Consequences to Non-U.S. Royalty Trust Unitholders

The following is a summary of material U.S. federal income tax consequences that apply to you if you are a non-U.S. Royalty Trust unitholder. Non-U.S. Royalty Trust unitholders should consult their own independent tax advisors to determine the U.S. federal, state, local and foreign tax consequences that may be relevant to them.

Tax Treatment of the Royalty Trust Units. The Royalty Trust (or the appropriate intermediary if the royalty trust units are held in street name) is required to withhold at a rate of 30% on royalty income paid to non-U.S. Royalty Trust unitholders unless such holder is eligible for a lower rate under an applicable income tax treaty or the interest is effectively connected with the non-U.S. Royalty Trust unitholder’s conduct of a trade or business in the United States. The same result would occur if the royalty trust units are treated as a debt instrument subject to the CPDI regulations. For more information, see “—Classification and Tax Treatment of the Royalty Trust Units” above.

A non-U.S. Royalty Trust unitholder that is eligible for a lower rate under an applicable income tax treaty or if such income is effectively connected with such holder’s conduct of a trade or business in the United States may provide appropriate certification to the Royalty Trust (or the appropriate intermediary if the royalty trust units are held in street name) on IRS Form W-8BEN (in the case of a claim of treaty benefits) or Form W-8ECI (with respect to the non-U.S. Royalty Trust unitholder’s conduct of a trade or business in the United States).

If a non-U.S. Royalty Trust unitholder is engaged in a trade or business in the United States, and if payments on or gain realized on a sale or other disposition of a royalty trust unit are effectively connected with the conduct of this trade or business, the non-U.S. Royalty Trust unitholder, although exempt from U.S. withholding tax (if the appropriate certification is furnished), will generally be taxed in the same manner as a U.S. Royalty Trust unitholder. For more information, see “—Tax Consequences to U.S. Royalty Trust Unitholders” above. Any such non-U.S. Royalty Trust unitholder should consult its own tax advisors with respect to other tax consequences of the ownership of the royalty trust units, including the possible imposition of a 30% branch profits tax in the case of a non-U.S. Royalty Trust unitholder that is classified for U.S. federal income tax purposes as a corporation.

 

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Sale or Exchange of Royalty Trust Units. The royalty trust units are treated as “United States real property interests” for U.S. federal income tax purposes. However, as long as the royalty trust units are regularly traded on an established securities market, gain realized by a non-U.S. Royalty Trust unitholder on a sale of royalty trust units is subject to U.S. federal income tax only if:

 

•

the gain is, or is treated as, effectively connected with business conducted by the non-U.S. Royalty Trust unitholder in the United States, and in the case of an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by the non-U.S. Royalty Trust unitholder;

 

•

the non-U.S. Royalty Trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale; or

 

•

the non-U.S. Royalty Trust unitholder owns currently or owned at certain earlier times directly or by applying certain attribution rules, more than 5% of the royalty trusts units.

Backup Withholding Tax and Information Reporting. Payments to non-U.S. Royalty Trust unitholders of interest, and amounts withheld from such payments, if any, generally are required to be reported to the IRS and to the non-U.S. Royalty Trust unitholder.

A non-U.S. Royalty Trust unitholder may be subject to backup withholding tax, currently at a rate of 28% with respect to payments from the Royalty Trust and the proceeds from dispositions of royalty trust units, unless such non-U.S. Royalty Trust unitholder complies with certain certification requirements (usually satisfied by providing a duly completed IRS Form W-8BEN) or otherwise establishes an exemption. Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules are allowed as a refund from the IRS or a credit against a non-U.S. Royalty Trust unitholder’s U.S. federal income tax liability, provided certain required information is provided to the IRS.

Payments of the proceeds of a sale of a royalty trust unit effected by the U.S. office of a U.S. or foreign broker are subject to information reporting requirements and backup withholding unless the non-U.S. Royalty Trust unitholder properly certifies under penalties of perjury as to its foreign status and certain other conditions are met or the non-U.S. Royalty Trust unitholder otherwise establishes an exemption. Information reporting requirements and backup withholding generally do not apply to any payment of the proceeds of the sale of a royalty trust unit effected outside of the United States by a foreign office of a broker. However, unless such a broker has documentary evidence in its records that the holder is a non-U.S. Royalty Trust unitholder and certain other conditions are met, or the non-U.S. Royalty Trust unitholder otherwise establishes an exemption, information reporting applies to a payment of the proceeds of the sale of a royalty trust unit effected outside the United States by such a broker if it:

 

•

is a United States person;

 

•

derives 50% or more of its gross income for certain periods from the conduct of a trade or business in the United States;

 

•

is a controlled foreign corporation for U.S. federal income tax purposes; or

 

•

is a foreign partnership that, at any time during its taxable year, has more than 50% of its income or capital interests owned by United States persons or is engaged in the conduct of a U.S. trade or business.

Any amount withheld under the backup withholding rules may be credited against the non-U.S. Royalty Trust unitholder’s U.S. federal income tax liability and any excess may be refundable if the required information is timely provided to the IRS.

 

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STATE TAX CONSIDERATIONS

The following is intended as a brief summary of certain information regarding state and local income taxes affecting individuals who become Royalty Trust unitholders. State and local tax laws vary from state to state. FCX, the selling securityholder and the Royalty Trust urge you to consult your own tax advisor regarding the state and local tax consequences of the conversion of convertible securities into royalty trust units and cash and the ownership of royalty trust units.

Conversion of convertible securities into royalty trust units and cash will be a fully taxable transaction for United States federal income tax purposes and may also be taxable for state and local income tax purposes. The state and local income tax consequences of conversion will depend on the specific circumstances of each individual Royalty Trust unitholder, such as the Royalty Trust unitholder’s state of residence and use of the convertible securities by the individual, and the various state and local individual income tax laws. For example, any gain recognized on the conversion by an individual who is not a legal resident of Louisiana would not be subject to Louisiana individual income tax unless the convertible securities had been used by the individual in such a manner as to establish a business situs for the convertible securities in Louisiana. Because the state and local tax consequences of the conversion could vary depending on the individual Royalty Trust unitholder’s facts and circumstances and the various state and local income tax laws, FCX, the selling securityholder and the Royalty Trust urge you to consult your own tax advisor regarding the state and local tax consequences of conversion to you in your particular circumstances.

The Royalty Trust will own an overriding royalty interest burdening the subject interests, which are located both in and outside Louisiana. Weil, Gotshal & Manges LLP has opined 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 will also be treated as a grantor trust for Louisiana income tax purposes. As a grantor trust, the Royalty Trust will not be subject to Louisiana income tax at the Royalty Trust level. Rather, for Louisiana individual income tax purposes, 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. Consequently, individual Royalty Trust unitholders may be subject to Louisiana individual income tax on all or a portion of their shares of any Royalty Trust income. Individual Royalty Trust unitholders who are legal residents of Louisiana will be subject to Louisiana individual income tax on all of their shares of any Royalty Trust income. Individual Royalty Trust unitholders who are not legal residents of Louisiana generally will be subject to Louisiana individual income tax only on the portion of their shares of any Royalty Trust income that is sourced to Louisiana. For Louisiana individual income tax purposes, royalties from mineral properties are specifically sourced to the state where such property is located at the time the income is derived.

Individual royalty trust unitholders who are required to file Louisiana individual income tax returns and pay Louisiana individual income tax on all or a portion of their proportionate shares of any Royalty Trust income may be subject to penalties for failure to comply with such requirements. 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 conversion of convertible securities into royalty trust units and cash and their receipt of any income from the Royalty Trust.

FCX, THE SELLING SECURITYHOLDER AND THE ROYALTY TRUST URGE YOU TO CONSULT YOUR OWN TAX ADVISOR AS TO THE SPECIFIC STATE AND LOCAL TAX CONSEQUENCES TO YOU OF THE CONVERSION OF CONVERTIBLE SECURITIES INTO ROYALTY TRUST UNITS AND CASH AND THE OWNERSHIP AND DISPOSITION OF ROYALTY TRUST UNITS IN LIGHT OF YOUR PARTICULAR FACTS AND CIRCUMSTANCES.

 

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ERISA CONSIDERATIONS

The Employee Retirement Income Security Act of 1974, as amended (“ERISA”), regulates qualified pension plans, profit-sharing plans, stock bonus plans, simplified employee pension plans, Keogh plans, tax deferred annuities or IRAs established or maintained by an employer or employee organization, and other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Code provides similar requirements and standards which are applicable to qualified plans, which include certain of the plans described above, and to individual retirement accounts, whether or not subject to ERISA.

A fiduciary of an employee benefit plan should carefully consider fiduciary standards under ERISA regarding the plan’s particular circumstances before authorizing an investment in royalty trust units. Among other things, a fiduciary should consider:

 

•

whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA;

 

•

whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and

 

•

whether the investment is in accordance with the documents and instruments governing the plan as required by Section 404(a)(1)(D) of ERISA.

A fiduciary should also consider whether an investment in royalty trust units might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Section 4975 of the Code. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are plan assets in the transaction. The Department of Labor has published regulations concerning whether or not a plan’s assets would be deemed to include an interest in the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Code. These regulations provide that the underlying assets of an entity will not be considered “plan assets” if the equity interests in the entity are a publicly offered security. Fiduciaries, however, will need to determine whether the acquisition of royalty trust units is a nonexempt prohibited transaction under the general requirements of Section 406 of ERISA and Section 4975 of the Code.

The prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential employee benefit plan investors should consult with their counsel to determine the consequences under ERISA and the Code of their acquisition and ownership of royalty trust units.

 

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SELLING SECURITYHOLDER

On June 3, 2013, FCX and MMR completed the transactions contemplated by the merger agreement by and among MMR, FCX, and Merger Sub. Pursuant to the merger agreement, on June 3, 2013, Merger Sub merged with and into MMR, with MMR surviving the merger as a wholly owned subsidiary of FCX.

On June 3, 2013, the Royalty Trust issued 230,172,696 royalty trust units. Of this amount, 129,210,542 royalty trust units were issued to former holders of MMR common stock as merger consideration, and the remaining 100,962,154 royalty trust units are held by the selling securityholder, a subsidiary of FCX, including 38,805,688 royalty trust units (approximately 16.9% of the total number of royalty trust units outstanding) which FCX may become obligated to deliver to holders of the convertible securities upon conversion. FCX is currently the largest holder of royalty trust units, with approximately 43.9% of the outstanding royalty trust units.

The selling securityholder, including its transferees, pledgees or donees or their successors (all of whom may be the selling securityholder), may from time to time offer and deliver pursuant to this prospectus any or all of the royalty trust units. When we refer to “selling securityholder” in this prospectus, we mean McMoRan Oil & Gas LLC and FCX collectively, as well as its transferees, pledgees or donees or its successors.

Prior to the closing of the merger, McMoRan Oil & Gas LLC was a wholly owned subsidiary of MMR and the principal operating subsidiary through which MMR conducted its oil and gas operations. Upon closing of the merger on June 3, 2013, McMoRan Oil & Gas LLC became a wholly owned subsidiary of FCX.

The following table sets forth certain information as of June 3, 2013 regarding the beneficial ownership of royalty trust units by the selling securityholder and the royalty trust units being offered by the selling securityholder. Information with respect to beneficial ownership is based upon information obtained from the selling securityholder. Assuming all of the royalty trust units being registered are delivered to the holders of convertible securities, the selling securityholder will own the royalty trust units set forth in the following table after completion of this offering.

 

Name and Address of Beneficial Owner		Royalty Trust Units Beneficially Owned Before Offering				Royalty Trust Units Being Offered		Royalty Trust Units Beneficially Owned After the Offering
		Number		Percent(1)				Number		Percent(1)
Freeport-McMoRan Copper & Gold Inc. McMoRan Oil & Gas LLC 333 N. Central Avenue Phoenix, AZ 85004		100,962,154		43.9%		38,805,688		62,156,466		27.0%

 

(1)	Percentages are based on 230,172,696 royalty trust units outstanding as of June 3, 2013.

 

 

 

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LEGAL MATTERS

The validity under Delaware law of the royalty trust units offered by this prospectus is being passed upon by Morris, Nichols, Arsht & Tunnell LLP.

EXPERTS

The financial statements of the Gulf Coast Ultra Deep Royalty Trust for the period from December 18, 2012 (inception) to December 31, 2012, appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, an independent registered public accounting firm, as set forth in their report thereon, appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

ADDITIONAL INFORMATION

We have filed with the United States Securities and Exchange Commission, a registration statement on Form S-1 under the Securities Act relating to the royalty trust units that includes important business and financial information about us that is not included in or delivered with this prospectus. If we have made references in this prospectus to any contracts, agreements or other documents and also filed any of those contracts, agreements or other documents as exhibits to the registration statement, you should read the relevant exhibit for a more complete understanding of the document or the matter involved.

We are required to file annual, quarterly and current reports and other information with the SEC. You may read and copy any document we file with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. Our SEC filings are also available to the public at the SEC’s website at http://www.sec.gov.

You may obtain copies of the information and documents incorporated by reference in this prospectus at no charge by writing or telephoning us at the following address or telephone number:

Gulf Coast Ultra Deep Royalty Trust

c/o Freeport-McMoRan Copper & Gold Inc., as depositor

333 N. Central Ave.

Phoenix, Arizona 85004

(602) 366-8100

 

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 13.

Other Expenses of Issuance and Distribution.

Set forth below are the expenses to be incurred in connection with the issuance and distribution of the securities to be registered. With the exception of the SEC registration fee, the amounts set forth below are estimates.

 

SEC Filing Fees		$	8,700
Legal Fees			200,000
Accounting Fees			150,000
Printing and Mailing Costs			200,000
Transfer agent and registrar fees			5,000
Trustee fees and expenses			15,000
Miscellaneous			6,300
Total		$	585,000

 

Item 14.

Indemnification of Directors and Officers.

The amended and restated trust agreement provides that The Bank of New York Mellon Trust Company, N.A. (“Trustee”), BNY Mellon Trust of Delaware (“Delaware Trustee”) and their respective officers, agents and employees shall be indemnified against and from any and all liabilities, obligations, costs, expenses, actions, suits, claims, damages (including consequential damages and all other types of damages), losses, penalties, taxes, fees and other charges of any kind and any nature whatsoever, including without limitation any liability arising out of or in connection with any liability under environmental laws, or in the doing of any act done or performed or omission occurring on account of its being Trustee or Delaware Trustee or acting in such capacity, except such liability, expense, claims, damages or loss as to which it is liable under the amended and restated trust agreement. In this regard, the trustee shall be liable only for its own fraud, willful misconduct or gross negligence or for acts or omissions in bad faith or with gross negligence in the selection and retention of such agent or employee. The Trustee and the Delaware Trustee are each entitled to indemnification from the assets of the Royalty Trust and each shall have a lien on the assets of the Royalty Trust to secure it for the foregoing indemnification.

 

Item 15.

Recent Sales of Unregistered Securities.

On June 3, 2013, in exchange for the transactions contemplated by the Master Conveyance of Overriding Royalty Interest by and between McMoRan Oil & Gas LLC and the registrant, the registrant issued 230,172,696 royalty trust units to McMoRan Oil & Gas LLC pursuant to Section 4(2) of the Securities Act. The issuance of such royalty trust units was not registered under the Securities Act because such issuance did not constitute a public offering.

 

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Item 16.

Exhibits.

 

Exhibit Number		Description
3.1		Certificate of Trust of Gulf Coast Ultra Deep Royalty Trust (incorporated herein by reference to Exhibit 3.1 to the Royalty Trust’s registration statement on S-4 filed with the SEC on December 28, 2012).
3.2		Certificate of Amendment of Certificate of Trust of Gulf Coast Ultra Deep Royalty Trust.
5.1		Opinion of Morris, Nichols, Arsht & Tunnell LLP regarding legality of securities being registered.
8.1		Opinion of Weil, Gotshal & Manges LLP regarding tax matters.
10.1		Trust Agreement of Gulf Coast Ultra Deep Royalty Trust, dated as of December 18, 2012 (incorporated herein by reference to Exhibit 3.1 to the Royalty Trust’s registration statement on S-4 filed with the SEC on December 28, 2012).
10.2		Amended and Restated Trust Agreement of Gulf Coast Ultra Deep Royalty Trust, dated as of June 3, 2013.
10.3		Master Conveyance of Overriding Royalty Interest by and between McMoRan Oil & Gas LLC and Gulf Coast Ultra Deep Royalty Trust , dated as of June 3, 2013.
23.1		Consent of Ernst &Young LLP, the independent registered public accounting firm for Gulf Coast Ultra Deep Royalty Trust.
23.2		Consent of Morris, Nichols, Arsht & Tunnell LLP for legality opinion (included in Exhibit 5.1 hereto).
23.3		Consent of Weil, Gotshal & Manges LLP for tax opinion (included in Exhibit 8.1 hereto).

 

Item 17.

Undertakings.

(a) The undersigned registrant hereby undertakes:

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, if the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(5) That, for the purpose of determining liability of the registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(b) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of their counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, Gulf Coast Ultra Deep Royalty Trust has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Phoenix, State of Arizona, on June 3, 2013.

 

 

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