Gulf Coast Ultra Deep Royalty Trust - FORM 10-Q

Attached files

file	filename
EX-32 - EXHIBIT 32 - Gulf Coast Ultra Deep Royalty Trust	exhibit322q13.htm
EX-3 - EXHIBIT 3.1 - Gulf Coast Ultra Deep Royalty Trust	exhibit312q13.htm
EX-31 - EXHIBIT 31 - Gulf Coast Ultra Deep Royalty Trust	exhibit31certification2q13.htm



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

FORM 10-Q

(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2013
OR
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from		to
Commission File Number: 333-185742

Gulf Coast Ultra Deep Royalty Trust
(Exact name of registrant as specified in its charter)



Delaware	46-6448579
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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

Institutional Trust Services

919 Congress Avenue, Suite 500

Austin, Texas 78701

(Address of principal executive offices, including zip code)

(713) 483-6792

(Registrant's telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No

Indicate by check mark 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.



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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

o Yes x No

On July 31, 2013, there were outstanding 230,172,696 units representing beneficial interests in Gulf Coast Ultra Deep Royalty Trust.




Gulf Coast Ultra Deep Royalty Trust
TABLE OF CONTENTS

	Page

Part I. Financial Information

Item 1. Financial Statements:

Statements of Assets, Liabilities and Trust Corpus	3

Statements of Distributable Income	4

Statements of Changes in Trust Corpus	5

Notes to Financial Statements	6

Item 2. Trustee's Discussion and Analysis of Financial Condition and Results of Operations	9

Item 3. Quantitative and Qualitative Disclosures About Market Risk	14

Item 4. Controls and Procedures	15

Part II. Other Information

Item 1. Legal Proceedings	16

Item 1A. Risk Factors	16

Item 6. Exhibits	21

Glossary	21

Signature	23

Exhibit Index	24

Part I. FINANCIAL INFORMATION


Item 1.	Financial Statements.

GULF COAST ULTRA DEEP ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS



	June 30, 2013		December 31, 2012
ASSETS	(unaudited)		(audited)
Operating cash	$	128,072	$	10
Reserve Fund cash	1,000,000		—
Overriding royalty interests in subject interests	400,300,341		—
Total assets	$	401,428,413	$	10

LIABILITIES AND TRUST CORPUS
Reserve Fund liability	$	1,000,000	$	—
Trust corpus (230,172,696 units authorized, issued and outstanding)	400,428,413		$	10
Total liabilities and trust corpus	$	401,428,413	$	10

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

GULF COAST ULTRA DEEP ROYALTY TRUST

STATEMENTS OF DISTRIBUTABLE INCOME



	Three Months Ended			Six Months Ended
	June 30, 2013			June 30, 2013
	(unaudited)			(unaudited)
Royalty income	$	—		$	—
Administrative expenses	(221,938		)	(221,938		)
Administrative expenses in excess of royalty income	(221,938		)	(221,938		)
Distributable income	$	—		$	—
Distributable income per unit	$	—		$	—
Units outstanding at June 30, 2013	230,172,696			230,172,696

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

GULF COAST ULTRA DEEP ROYALTY TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS



	January 1, 2013 to June 30, 2013			December 18, 2012 (inception) to December 31, 2012
	(unaudited)			(audited)
Trust corpus, beginning of period	$	10		$	—
Trust contributions		350,000			10
Administrative expenses		(221,938	)		—
Overriding royalty interests in subject interests		400,300,341			—
Trust corpus, end of period	$	400,428,413		$	10

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

GULF COAST ULTRA DEEP ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Unaudited)

1. FORMATION OF THE ROYALTY TRUST AND BASIS OF ACCOUNTING

Gulf Coast Ultra Deep Royalty Trust (the Royalty Trust), is a statutory trust created under the Delaware Statutory Trust Act pursuant to a trust agreement entered into on December 18, 2012 (inception), between Freeport-McMoRan Copper & Gold Inc. (FCX), as depositor, Wilmington Trust, National Association, as the Delaware trustee, and certain officers of FCX, as regular trustees (the royalty trust agreement). The Royalty Trust was created to hold a 5% gross overriding royalty interest (collectively, the royalty interests) in hydrocarbons saved and produced from 20 of McMoRan Oil & Gas LLC's (McMoRan) specified shallow water Gulf of Mexico and onshore Gulf Coast ultra-deep exploration prospects (the subject interests). McMoRan owns less than 100% of the working interest in each of the subject interests. McMoRan is a wholly owned subsidiary of McMoRan Exploration Co. (MMR). 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, FCX and MMR completed the transactions contemplated by the Agreement and Plan of Merger, dated as of December 5, 2012 (the merger agreement), by and among MMR, FCX, and INAVN Corp., a Delaware corporation and wholly owned subsidiary of FCX (Merger Sub). Pursuant to the merger agreement, on June 3, 2013, Merger Sub merged with and into MMR, with MMR surviving the merger as an indirect wholly owned subsidiary of FCX (the merger). In connection with the merger, on June 3, 2013, (1) FCX, as depositor, McMoRan, as grantor, The Bank of New York Mellon Trust Company, N.A., a national banking association, as trustee (the Trustee), and BNY Mellon Trust of Delaware, as Delaware trustee (the Delaware trustee), entered into the amended and restated royalty trust agreement to govern the Royalty Trust and the respective rights and obligations of FCX, the Trustee, the Delaware Trustee, and the Royalty Trust unitholders with respect to the Royalty Trust; and (2) the Royalty Trust entered into the master conveyance of overriding royalty interest (the master conveyance) by and between McMoRan, as grantor, and the Royalty Trust, as grantee, pursuant to which McMoRan conveyed to the Royalty Trust the royalty interests in future production from the subject interests. Other than its formation, receipt of deposits and receipt of the conveyance of the royalty interests, the Royalty Trust has not conducted any activities.

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

The financial statements of the Royalty Trust are prepared on a modified cash basis and are not intended to present the financial position and results of operations in conformity with U.S. generally accepted accounting principles (GAAP). This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the Securities and Exchange Commission (the SEC), as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. There has been no distributable income paid or due to the Royalty Trust's unit holders since inception and through June 30, 2013.

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

2. OVERRIDING ROYALTY INTERESTS

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 the subject interests during the life of the Royalty Trust. An overriding royalty interest in general represents a non-operating interest in an oil and gas property that provides the owner a specified share of production without any related operating expenses or development costs and is carved out of an oil and gas lessee's working or cost-bearing interest under the lease. 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 neither the royalty trust nor holders of royalty trust units have any such rights.

(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 Louisiana, or onshore in Louisiana. McMoRan does not own 100% of the working interest of any of the subject interests. The royalty interests in future production from the subject interests burden all of McMoRan's current leasehold interests associated with such prospects, and will burden any leasehold interests associated with such prospects which are acquired by McMoRan on or before December 5, 2017 as estimated in the table below (subject to McMoRan's right to dispose of a portion of the working interest to a percentage not less than the estimated working interests estimated in the table below). Each of the royalty interests has been, or will be, proportionately reduced based on McMoRan's working interest to equal the product of 5% multiplied by a fraction, the numerator of which is the working interest held by McMoRan and its affiliates in the applicable subject interest (subject to a cap equal to McMoRan's estimated working interest (equal to the working interest McMoRan owns or expects to acquire and as estimated 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 McMoRan's ultra-deep prospects and, currently, none of the subject interests have any reserves classified as proved, probable or possible (other than the Lineham Creek well) and none of the subject interests have any associated production. Additional ultra-deep prospects developed by McMoRan will not be included in the subject interests. As of June 30, 2013, approximately 0.9 Bcfe of proved reserves were deemed attributable to the Royalty Trust's 1.8% overriding royalty interest in the Lineham Creek sands encountered above 24,000 feet.

Information concerning estimated working interests and estimated overriding royalty interests for each of the subject interests as of June 30, 2013 is set forth below:




Subject Interest Name	McMoRan's Estimated Working Interest	Operator	Royalty Trust's Estimated Overriding Royalty Interests (5% proportionately reduced to reflect the Estimated Working Interest)
Davy Jones	63.4%	McMoRan	3.17%
Blackbeard East	72%	McMoRan	3.6%
Lafitte ^(a)	—	McMoRan	—
Blackbeard West	69.4%	McMoRan	3.47%
England	36%	Chevron	1.8%
Barbosa	72%	McMoRan	3.6%
Morgan ^(b)	—	McMoRan	—
Barataria	72%	McMoRan	3.6%
Blackbeard West #3	69.4%	McMoRan	3.47%
Drake	72%	McMoRan	3.6%
Davy Jones West	36%	McMoRan	1.8%
Hurricane	72%	McMoRan	3.6%
Hook	72%	McMoRan	3.6%
Captain Blood	72%	McMoRan	3.6%
Bonnet	72%	McMoRan	3.6%
Queen Anne's Revenge	72%	McMoRan	3.6%
Calico Jack	36%	McMoRan	1.8%
Highlander	72%	McMoRan	3.6%
Lineham Creek	36%	Chevron	1.8%
Tortuga	72%	McMoRan	3.6%

(a) In June 2013 McMoRan requested from the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE) that its pending request for the issuance of a Suspension of Production (SOP) lease extension for the Lafitte unit properties be returned without action, which effectively relinquished McMoRan's lease rights to the Lafitte unit. In the event on or before December 5, 2017, McMoRan acquires one or more leasehold interests covering the same area and blocks covered by the terminated leases, such newly acquired leasehold interests shall become subject interests, and if this were to occur, it is expected that McMoRan would hold an approximate 72% working interest in such reacquired leases, equating to a Royalty Trust estimated overriding royalty interest of 3.6%.

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

The Royalty Trust will dissolve on the earlier of (i) June 3, 2033, (ii) the sale of all of the royalty interests, (iii) the election of the Trustee following its resignation for cause (as more fully described in the amended and restated royalty trust agreement), (iv) a vote of the holders of 80% (which after June 3, 2018, shall be reduced to 66⅔%) 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 royalty trust agreement (in which case the royalty interests may extend through June 3, 2033).

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

3. INCOME TAXES

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

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.

4. RELATED PARTY TRANSACTIONS

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

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, such amount to be loaned by FCX, on an unsecured, interest-free basis, as set forth in the amended and restated royalty trust agreement.

FCX has agreed to provide and maintain a $1.0 million stand-by reserve account or an equivalent letter of credit for the benefit of the Royalty Trust to enable the Trustee to draw on the reserve account or letter of credit to pay obligations of the Royalty Trust in the event that the Royalty Trust has inadequate funds to pay the Royalty Trust's obligations at any time. After the one-year anniversary of the date of the royalty trust agreement, with the consent of the Trustee, FCX may reduce the reserve account or substitute a letter of credit with a different face amount for the original letter of credit or any substitute letter of credit. In connection with this arrangement, FCX has provided $1.0 million in the form of a reserve fund cash account to the Royalty Trust, which amount is reflected as Reserve Fund Cash with a corresponding Reserve Fund Liability in the accompanying Statements of Assets, Liabilities and Trust Corpus. For additional information regarding entry into the amended and restated royalty trust agreement, see Note 1.

Compensation of the Trustee. The trustee is entitled to annual compensation of $150,000 (provided that the first year in which the Royalty Trust receives any payment pursuant to the conveyances of the royalty interests, the annual compensation shall be increased to $200,000 annually), 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.

5. CONTINGENCIES

Litigation. The following information includes a discussion of updates to previously reported legal proceedings included in Note 5 of the Trust's quarterly report on Form 10-Q for the quarter ended March 31, 2013.

On June 28, 2013, the parties in In Re McMoRan Exploration Co. Stockholder Litigation, No. 8132-VCN, entered into a settlement agreement. A settlement hearing is scheduled for October 11, 2013. The Royalty Trust will not incur any costs in connection with the settlement.

6. SUBSEQUENT EVENTS

The Royalty Trust evaluated events after June 30, 2013, and through the date the financial statements were issued, and determined any events or transactions occurring during this period that would require recognition or disclosure are appropriately addressed in these financial statements.

Item 2. Trustee's Discussion and Analysis of Financial Condition and Results of Operations.

OVERVIEW

In trustee's discussion and analysis “we,” “us,” and “our” refer to Gulf Coast Ultra Deep Royalty Trust (the Royalty Trust). You should read the following discussions in conjunction with our financial statements. The results of operations reported and summarized below are not necessarily indicative of future operating results. Unless otherwise specified, all references to Notes refer to Notes to Financial Statements included elsewhere in this Form 10-Q. Also see the glossary of definitions (beginning on page 20) for some of the oil and gas industry terms we use in this Form 10-Q. The information below has been furnished to the Trustee by FCX and McMoRan.

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

The Royalty Trust 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 agreement). The Royalty Trust was created to hold certain overriding royalty interests (collectively, the royalty interests) in hydrocarbons saved and produced from 20 of McMoRan Oil & Gas LLC's (McMoRan) specified shallow water Gulf of Mexico and onshore Gulf Coast ultra-deep exploration prospects (the subject interests). McMoRan is a wholly owned subsidiary of MMR. McMoRan 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 (the Delaware Trustee), through an action of the depositor. Effective June 3, 2013, the regular trustees were replaced by The Bank of New York Mellon Trust Company, N.A., as trustee (the Trustee).

On June 3, 2013, (1) FCX, as depositor, McMoRan, as grantor, the Trustee and the Delaware Trustee, entered into the amended and restated royalty trust agreement to govern the Royalty Trust and the respective rights and obligations of FCX, the Trustee, the Delaware Trustee, and the Royalty Trust unitholders with respect to the Royalty Trust; and (2) the Royalty Trust entered into the master conveyance of overriding royalty interest (the master conveyance) by and between McMoRan, as grantor, and the Royalty Trust, as grantee, pursuant to which McMoRan conveyed to the Royalty Trust a 5% gross overriding royalty interest in hydrocarbons saved and produced from the 20 specified McMoRan ultra deep exploration prospects. Other than its formation and conveyance of the royalty interests, the Royalty Trust has not conducted any activities. The Trustee has no involvement with, control over, or responsibility for, any aspect of the operations on or relating to the properties in which the Royalty Trust has an interest.

Since 2008, McMoRan's ultra-deep drilling activities (below the salt weld, i.e., the listric fault) have confirmed McMoRan'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 (including one well on the Lafitte prospect where lease rights have been relinquished) 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 are considered “exploration concepts” and further drilling and flow testing will be required to determine the commercial potential of the subject interests.

Currently, none of the subject interests have any reserves classified as proved, probable or possible (other than the Lineham Creek well), and none of such subject interests have any associated production. The Royalty Trust has no ability to influence the exploration or development of the subject interests. In addition, neither FCX nor McMoRan are under any obligation to fund or to commit any other resources to the exploration or development of the subject interests.

LIQUIDITY AND CAPITAL RESOURCES

None of the subject interests are currently producing oil or gas. Accordingly, the Royalty Trust currently has no source of income. FCX has agreed to pay annual trust expenses up to a maximum amount of $350,000, to the extent the Royalty Trust lacks sufficient funds to pay such expenses. During the quarter ended June 30, 2013, FCX deposited $350,000 into the Royalty Trust's operating cash account. At June 30, 2013, $128,072 of such funds remained in the account. FCX has agreed to lend money to the Royalty Trust to fund the Royalty Trust's ordinary administrative expenses in excess of its funds available to pay such expenses, such amount to be loaned by FCX, on an unsecured, interest-free basis, as set forth in the amended and restated royalty trust agreement. FCX has agreed to provide and maintain a $1.0 million stand-by reserve account or equivalent letter of credit for the benefit of the Royalty Trust to enable the Trustee to draw on the reserve account or letter of credit to pay obligations of the Royalty Trust in the event that the Royalty Trust has inadequate funds to pay the Royalty Trust's obligations at any time. In connection with this arrangement, FCX has provided $1.0 million in the form of a reserve fund cash account to the Royalty Trust. The Royalty Trust has no source of liquidity or capital resources other than contributions and establishment of reserves from FCX. Any material adverse change in FCX's financial condition or results of operations could materially and adversely affect the Royalty Trust and the Royalty Trust unitholders.

DESCRIPTION OF THE SUBJECT INTERESTS

The “subject interests” consist of 20 specified 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 Louisiana, or onshore in Louisiana. McMoRan does not own 100% of the working interest of any of the subject interests. The 5% gross overriding royalty interest in hydrocarbons saved and produced from the subject interests burden all of McMoRan's current leasehold interests associated with such prospects, and will burden any leasehold interests associated with such prospects which are acquired by McMoRan on or before December 5, 2017 as estimated in the table below (subject to McMoRan'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 McMoRan's working interest to equal the product of 5% multiplied by a fraction, the numerator of which is the working interest held by McMoRan and its affiliates in the applicable subject interest (subject to a cap equal to McMoRan's estimated working interest (equal to the working interest McMoRan owns or expects to acquire and as estimated in the table below) in each subject interest, on a prospect by prospect basis) and the denominator of which is 100% as reflected in the table below. As of December 5, 2012, the date of the merger agreement, the subject interests comprised all of McMoRan's ultra-deep prospects and, currently, none of the subject interests have any reserves classified as proved, probable or possible (other than the Lineham Creek well) and none of the subject interests have any associated production. Additional ultra-deep prospects developed by McMoRan will not be included in the subject interests. As of June 30, 2013, approximately 0.9 Bcfe of proved reserves were deemed attributable to the Royalty Trust's 1.8% overriding royalty interest in the Lineham Creek sands encountered above 24,000 feet.

Information concerning estimated working interests and estimated royalty interests for each of the subject interests as of June 30, 2013 is set forth below:



Subject Interest Name	McMoRan's Estimated Working Interest	Operator	Royalty Trust's Estimated Overriding Royalty Interests (5% proportionately reduced to reflect the Estimated Working Interest)
Davy Jones	63.4%	McMoRan	3.17%
Blackbeard East	72%	McMoRan	3.6%
Lafitte ^(a)	—	McMoRan	—
Blackbeard West	69.4%	McMoRan	3.47%
England	36%	Chevron	1.8%
Barbosa	72%	McMoRan	3.6%
Morgan ^(b)	—	McMoRan	—
Barataria	72%	McMoRan	3.6%
Blackbeard West #3	69.4%	McMoRan	3.47%
Drake	72%	McMoRan	3.6%
Davy Jones West	36%	McMoRan	1.8%
Hurricane	72%	McMoRan	3.6%
Hook	72%	McMoRan	3.6%
Captain Blood	72%	McMoRan	3.6%
Bonnet	72%	McMoRan	3.6%
Queen Anne's Revenge	72%	McMoRan	3.6%
Calico Jack	36%	McMoRan	1.8%
Highlander	72%	McMoRan	3.6%
Lineham Creek	36%	Chevron	1.8%
Tortuga	72%	McMoRan	3.6%

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

The Royalty Trust has no ability to influence the exploration or development of the subject interests. In addition, neither FCX nor McMoRan are under any obligation to fund or to commit any other resource to the exploration or development of the subject interests. Future determinations by FCX or McMoRan with respect to exploration and development activities (or the lack thereof) associated with the subject interests will likely impact the Royalty Trust's ability to realize value from the subject interests and the level of potentially distributable funds available to Royalty Trust unitholders.

Ultra-Deep Oil and Gas Prospects Acreage. At June 30, 2013, McMoRan owned or controlled (through options to lease) interests in approximately 524 oil and gas leases in the Gulf of Mexico and onshore Louisiana, covering approximately 366,000 gross acres (228,000 net acres to McMoRan's interests), associated with McMoRan's ultra-deep prospects associated with the subject interests. Approximately 21,000 net acres owned by McMoRan and associated with the subject interests are scheduled to expire in the remainder of 2013, a portion of which McMoRan expects to retain by drilling operations or other means.

The following table shows the oil and gas acreage associated with the subject interests related leases owned by McMoRan as of June 30, 2013.^(a)



	Developed		Undeveloped
	Gross	Net	Gross	Net
	Acres	Acres	Acres	Acres
Offshore (federal waters)	—	—	233,739	147,884
Onshore Louisiana	—	—	55,936	27,993
Total at June 30, 2013	—	—	289,675	175,877

(((a) In addition, McMoRan controls approximately 76,000 gross acres (52,100 net acres) by options to lease.

Ultra-Deep Exploration and Development Activities. Since 2008, McMoRan's drilling activities in the shallow waters of the Gulf of Mexico below the salt weld (i.e. listric fault) have successfully confirmed McMoRan'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.

Status of in-progress/suspended wells with current and/or near term expected activity related to the Royalty Trust's subject interests:

Lineham Creek Onshore Well

The Lineham Creek exploration prospect, which is located onshore in Cameron Parish, Louisiana, was drilled to a total vertical depth of 29,424 feet. In November 2012, the Lineham Creek well encountered pay sands above 24,000 feet, as identified by wireline logs. As of June 30, 2013, approximately 0.9 Bcfe of proved reserves were deemed attributable to the Royalty Trust's 1.8% overriding royalty interest in the Lineham Creek sands encountered above 24,000 feet. 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. During the second quarter 2013 the well encountered an operational issue and uphole side track operations commenced at approximately 22,000 feet. The uphole side track operation is currently drilling below 23,100 feet.

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 25,100 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. McMoRan controls rights to approximately 80,000 gross acres in Iberia, St. Martin, Assumption and Iberville Parishes in Louisiana.

Davy Jones

McMoRan 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.

Davy Jones No. 1 completion activities began in the fourth quarter of 2011, and initial flow testing procedures were attempted in March 2012; however, McMoRan encountered mechanical issues with the well's originally designed perforating equipment. Subsequent activities to flow the well were conducted in 2012 and 2013, and additional procedures to achieve a measurable flow are required. A large-scale hydraulic fracture treatment is being designed to penetrate the Wilcox reservoirs to facilitate hydrocarbon movement into the wellbore. 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.

Long-lead equipment required for completing and testing Davy Jones No. 2 is expected to be available early in 2014, and McMoRan plans to commence development operations at Davy Jones No. 2 prior to the current lease expiration date of January 19, 2014. Davy Jones is located on a 20,000 acre structure that has multiple additional drilling opportunities.

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. McMoRan's lease rights to South Timbalier Block 144 were scheduled to expire on August 17, 2012. Prior to the expiration, McMoRan submitted an application for Suspension of Production (SOP) to the BSEE to allow McMoRan to continue to hold its rights to the lease. In addition, McMoRan 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 McMoRan's APM for completion of the Blackbeard East well and in June 2013 McMoRan received BSEE's approval of the South Timbalier 144 Unit and the South Timbalier 144 Unit SOP to facilitate development of the Blackbeard East prospect.

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 McMoRan evaluates whether to drill deeper or complete the well to test

the existing zones. McMoRan'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.

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, McMoRan 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. Completion plans for Blackbeard West have recently been submitted to BSEE under an SOP application which holds McMoRan's rights to the Blackbeard West unit and related leases while under administrative consideration by BSEE. McMoRan's plans include commencing development operations during the fourth quarter of 2013.

RESULTS OF OPERATIONS

Currently, none of the subject interests associated with the royalty trust units have any reserves classified as proved, probable or possible (other than the Lineham Creek well) and none of such subject interests have any associated production. As a result, the Royalty Trust has received no proceeds from oil and gas production from the subject interests. During the quarter ended June 30, 2013 the Royalty Trust paid administrative expenses of $221,938, consisting of legal expenses incurred in connection with the formation of the Royalty Trust.

NEW ACCOUNTING STANDARD

We do not expect recently issued accounting standards to have a significant impact on our future financial statements and disclosures.

CAUTIONARY STATEMENT

Trustee's Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements in which we discuss certain of our expectations regarding future operational and financial performance. Forward-looking statements are all statements other than statements of historical facts, such as any statements regarding future financial condition 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 subject interests covered by the royalty interests will not produce hydrocarbons, general economic and business conditions, variations in the market demand for, and prices of, oil and natural gas, drilling results, changes in oil and natural gas reserve expectations, the potential adoption of new governmental regulations, decisions by FCX not to develop the subject interests, any inability of FCX to develop the subject interests, damages to facilities resulting from natural disasters or accidents and other factors described herein.

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 more frequently than quarterly, notwithstanding any changes in assumptions, changes in business plans, actual experience, or other changes, and we undertake no obligation to update any forward-looking statements except as required by law.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Commodity Price Risk. The Royalty Trust's most significant market risk relates to the prices received for oil and natural gas production, if and when such production commences with respect to the subject interests. The revenues, if any, will be derived from the subject interests and will depend substantially on prevailing natural gas

prices and to a lesser extent oil prices. As a result, commodity prices also will affect the amount of cash flow available for distribution to the RoyaltyTrust unitholders. Lower prices may also reduce the amount of oil and natural gas that McMoRan or the third-party operators will be able to economically produce.

Credit Risk. The Royalty Trust's most significant credit risk is adverse changes in FCX's financial condition or results of operations. Because none of the subject interests currently have any associated production, 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 Royalty Trust lacks sufficient funds to pay such expenses and to lend additional funds to the Royalty Trust if necessary. 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.

Item 4. Controls and Procedures.

(a) Evaluation of disclosure controls and procedures. The Trustee has evaluated the effectiveness of the Royalty Trust's “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, the Trustee has concluded that the Royalty Trust's disclosure controls and procedures are effective as of the end of the period covered by this report.

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

(b) Changes in internal control over financial reporting. In accordance with the terms of the amended and restated royalty trust agreement, effective June 3, 2013, the Trustee, on behalf of the Trust, was granted the power and authority to, among other things, establish, evaluate and maintain the Royalty Trust’s internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act. Accordingly, during the quarter ended June 30, 2013, FCX, as depositor, maintained the Royalty Trust's internal control over financial reporting until June 3, 2013, after which time the Trustee maintained the Royalty Trust's internal control over financial reporting. During the quarter ended June 30, 2013, there has been no change in the Royalty Trust's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Royalty Trust's internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of FCX.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

The following information includes a discussion of updates to previously reported legal proceedings included in our quarterly report on Form 10-Q for the quarter ended March 31, 2013.

Item 1A. Risk Factors.

The value of the royalty trust units is uncertain.

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

While data from the seven ultra-deep wells drilled on the subject interests thus far (including one well on the Lafitte prospect where lease rights have been relinquished) 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 June 30, 2013, 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 will be derived from the subject interests in the future, the result of which would be that the Royalty Trust would never receive any income from the subject interests.

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.

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.

McMoRan'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 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 McMoRan 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. The continuing commercial development and exploitation of the Davy Jones prospect will require significant additional capital expenditures.

There is a limited public market for the royalty trust units, which could have an adverse effect on the resale price of the royalty trust units.

The royalty trust units are not currently listed on a national securities exchange, but trade over the counter. We intend to list the royalty trust units on the OTCQX. The over the counter market is characterized by low trading volume, which might make it difficult or impossible to resell the royalty trust units, and could 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 is a limited 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 Form 10-Q;


•	the inability of the subject interests to achieve production of hydrocarbons;


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


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


•	general economic, securities markets and industry conditions.

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 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 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.

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 future 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, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals increased 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, 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.

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 2014 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 subject interests 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.

In the event McMoRan is unable to procure or maintain the suspension of operations (SOO) granted by the BSEE with respect to certain of its ultra-deep gas play acreage associated with the subject interests, McMoRan's ability to fully realize value associated with such acreage could be adversely affected.

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

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

At June 30, 2013, approximately 21,000 net acres owned by McMoRan and associated with the subject interests of the 366,000 gross acres associated with McMoRan's ultra-deep prospects and the subject interests are scheduled to expire in 2013.

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

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

These risks include:

•tropical storms and hurricanes, which are common in the Gulf of Mexico and the Gulf Coast area during the summer and early fall of each year, and which can damage or destroy drilling, production and treatment facilities, which can result in the interruption or cessation of production from associated wells;

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

•interruption or termination of operations by governmental authorities based on environmental, safety or other considerations.

These exposures in the Gulf of Mexico and the Gulf Coast area could have a material adverse effect on the subject interests and on the Royalty Trust's results of operations and financial condition.

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

Oil and gas prices fluctuate widely in response to relatively minor changes in supply, market uncertainty and a variety of additional factors that are beyond the control of FCX, McMoRan and the Royalty Trust. To the extent there is production of oil and gas associated with the royalty interests, the royalties that the Royalty Trust may receive from its share of production will be affected by changes in the prices of oil and gas. As a result, future distributions 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 subject interests will be developed or that any oil and gas discovered will be economic to produce. The volatility of energy prices reduces the accuracy of estimates of future cash distributions to the Royalty Trust unitholders and the value of the royalty trust units.

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

Because none of the subject interests 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. FCX has agreed to lend money to the Royalty Trust to fund the Royalty Trust's ordinary administrative expenses in excess of its funds available to pay such expenses, such amount to be paid by FCX, on an unsecured, interest-free basis, as set forth in the amended and restated royalty trust agreement. If the Trustee borrows funds to cover expenses or liabilities, the Royalty Trust unitholders will not receive distributions until the borrowed funds are repaid. 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 subject interests, 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 subject interests, FCX may make decisions that could adversely affect future production from the subject interests. Moreover, FCX could decide to sell or abandon some or all of the subject interests, and that decision may not be in the best interests of the holders of the royalty trust units.

FCX may transfer or abandon the subject interests.

FCX may at any time transfer all or part of the subject interests. The Royalty Trust unitholders are not entitled to vote on any transfer, and the Royalty Trust will not receive any proceeds of the transfer of the subject interests. Following any such transfer, the subject interests will continue to be subject to the royalty interests, but the net proceeds from the transferred subject interests would be calculated separately and paid by the transferee. The transferee would be responsible for all of FCX's obligations relating to the royalty interests on the portion of the subject interests transferred, and FCX would have no continuing obligation to the Royalty Trust for those subject interests.

The Royalty Trust is limited in duration, may be dissolved upon certain events and the royalty trust units are subject to 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 royalty trust agreement), (iv) upon a vote of the holders of 80% (which after June 3, 2018, shall be reduced to 66⅔%) 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 royalty trust agreement (in which case the royalty interests may extend through June 3, 2033).

Item 6. Exhibits.

The exhibits to this report are listed in the Exhibit Index appearing on page E-1 hereof.

GLOSSARY

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

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

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

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

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

Completion. The installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

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

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres. The total acres or wells, as the case may be, in which a working interest and/or operating right is owned.

Net acres. Gross acres or gross wells multiplied by the percentage working interest and/or operating right owned.

Net feet of pay. The thickness of reservoir rock estimated to both contain hydrocarbons and be capable of contributing to producing rates.

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

Pay. Reservoir rock containing oil or gas.

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

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

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

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

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

Sands. Sandstone or other sedimentary rocks.

SEC. Securities and Exchange Commission.

Working interest. The lessee's interest created by the execution of an oil and gas lease that gives the lessee the right to exploit the minerals on the property.

For additional information regarding the definitions contained in this Glossary, or for other Oil & Gas definitions, please see Rule 4-10 of Regulation S-X.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	Gulf Coast Ultra Deep Royalty Trust
	By: The Bank of New York Mellon
	Trust Company, N.A., as Trustee

	By: /s/ Michael J. Ulrich
	Michael J. Ulrich
	Vice President






Date: August 14, 2013

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

Gulf Coast Ultra Deep Royalty Trust

Exhibit Index



		Filed
Exhibit		with this	Incorporated by Reference
Number	Exhibit Title	Form 10-Q	Form	File No.	Date Filed
3.1	Composite Certificate of Trust of Gulf Coast Ultra Deep Royalty Trust	X
10.1	Amended and Restated Trust Agreement of Gulf Coast Ultra Deep Royalty Trust, dated as of June 3, 2013		S-1	333-189043	6/3/2013
10.2	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		S-1	333-189043	6/3/2013
31	Certification pursuant to Rule 13a-14(a)/15d-14(a)	X
32	Certification pursuant to 18 U.S.C. Section 1350	X

Attached files

Gulf Coast Ultra Deep Royalty Trust Reports

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