<PAGE>   1
 
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                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
 
                                   Form 10-K
 
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           <C>   <S>
           [X]   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
                    OF THE SECURITIES EXCHANGE ACT OF 1934
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996

           [ ]   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
                      OF THE SECURITIES EXCHANGE ACT OF 1934
                          COMMISSION FILE NUMBER 1-8581
</TABLE>
 
                   Freeport-McMoRan Oil and Gas Royalty Trust
             (Exact Name of Registrant as Specified in Its Charter)
 
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<C>                                                         <C>
                           TEXAS                                            72-6108468
              (State or Other Jurisdiction of                            (I.R.S. Employer
              Incorporation or Organization)                           Identification No.)

     TEXAS COMMERCE BANK NATIONAL ASSOCIATION, TRUSTEE                        77002
                      712 MAIN STREET                                       (Zip Code)
                      HOUSTON, TEXAS                                        
         (Address of Principal Executive Offices)
</TABLE>
 
       Registrant's telephone number, including area code: (713) 216-5447
 
          Securities registered pursuant to Section 12(b) of the Act:
 
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                                                          NAME OF EACH EXCHANGE ON
             TITLE OF EACH CLASS                              WHICH REGISTERED
             -------------------                          ------------------------
<S>                                                       <C>
         Units of Beneficial Interest                     New York Stock Exchange
</TABLE>
 
          Securities registered pursuant to Section 12(g) of the Act:
 
                                      NONE
 
     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.  YES   X    NO 
                                                        -------
     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.   X
 
     The aggregate market value of the 14,975,390 Units of Beneficial Interest
in Freeport-McMoRan Oil and Gas Royalty Trust held by non-affiliates of the
registrant on March 7, 1997 was approximately $48,670,000 based on the closing
price of the Units on the New York Stock Exchange as reported in The Wall Street
Journal.
 
     As of March 7, 1997, 14,975,390 Units of Beneficial Interest in
Freeport-McMoRan Oil and Gas Royalty Trust were outstanding.
 
                      DOCUMENTS INCORPORATED BY REFERENCE
                                     None.
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<PAGE>   2
 
                               TABLE OF CONTENTS
 
                                     PART I
 
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                                                                        PAGE
<S>       <C>                                                           <C>
Item 1.  Business.....................................................    1
          Description of the Trust....................................    1
          Description of the Units....................................    4
          The Royalty Properties and the Royalty......................    6
          Federal Income Tax Considerations...........................   25
Item 2.   Properties..................................................   26
Item 3.   Legal Proceedings...........................................   26
Item 4.   Submission of Matters to a Vote of Unit Holders.............   26
 
                                    PART II
 
          Market for the Registrant's Units and Related Unit Holder
Item 5.   Matters.....................................................   27
Item 6.   Selected Financial Data.....................................   27
          Management's Discussion and Analysis of Financial Condition
Item 7.   and Results of
          Operations..................................................   28
Item 8.   Financial Statements and Supplementary Data.................   32
          Statements of Royalty Proceeds and Distributable Cash:
          For the years ended December 31, 1996, 1995 and 1994........   32
          Statements of Assets, Liabilities and Trust Corpus:
          As of December 31, 1996 and 1995............................   32
          Statements of Changes in Trust Corpus:
          For the years ended December 31, 1996, 1995 and 1994........   32
          Notes to Financial Statements...............................   33
          Report of Independent Public Accountants....................   38
          Changes in and Disagreements with Accountants on Accounting
Item 9.   and Financial
          Disclosure..................................................   39
 
                                    PART III
 
Item 10.  Directors and Executive Officers of the Registrant..........   39
Item 11.  Executive Compensation......................................   39
          Security Ownership of Certain Beneficial Owners and
Item 12.  Management..................................................   39
Item 13.  Certain Relationships and Related Transactions..............   39
 
                                    PART IV
 
          Exhibits, Financial Statement Schedules and Reports on Form
Item 14.  8-K.........................................................   40
Signature.............................................................   41
</TABLE>
<PAGE>   3
 
                                     PART I
 
ITEM 1. BUSINESS.
 
                            DESCRIPTION OF THE TRUST
 
     Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created under
the laws of the State of Texas. Texas Commerce Bank National Association (Texas
Commerce) serves as Trustee of the Trust.
 
     For a discussion of the (i) estimated reserves owned by the Trust as of
December 31, 1996 and the estimated future net income of the Trust, see the
report by Ryder Scott Company Petroleum Engineers contained on pages 9 through
14 hereof, (ii) financial condition and results of operations of the Trust, see
Item 7 appearing on pages 28 through 31 hereof and (iii) financial statements
and supplementary data of the Trust, see Item 8 appearing on pages 32 through
38, with special reference to Note 10 thereto appearing on pages 35 through 37
hereof.
 
     Units of beneficial interest (the Units) in the Trust are traded on the New
York Stock Exchange under the trading symbol "FMR." The term "Company," as used
herein, includes Freeport-McMoRan Inc. (FTX), its divisions, direct and indirect
subsidiaries and affiliates, except as otherwise indicated by the context. The
term "Working Interest Owner" includes Freeport-McMoRan Oil & Gas Company
(FMOG), a division of FTX, and the successors and assigns of its oil and gas
working interests to the extent the context requires.
 
     The Units are not an interest in or an obligation of the Company, the
Working Interest Owner or any successor Working Interest Owner although they
represent indirect interests in the Royalty Properties (as defined below). The
following information and the information set forth under "DESCRIPTION OF THE
UNITS" are subject to the detailed provisions of the Royalty Trust Indenture
entered into between FTX and the Trustee (the Trust Indenture) and the First
Amended and Restated Articles of General Partnership of Freeport-McMoRan Oil and
Gas Royalty Partnership (the Partnership) entered into between McMoRan Offshore
Management Co., formerly an indirect wholly owned subsidiary of FTX, and the
Trustee (the Partnership Agreement). The Trust Indenture and the Partnership
Agreement are among the exhibits to this report. The provisions governing the
Trust and the Partnership are complex and extensive, and no attempt has been
made below to describe all of such provisions. The following is a general
description of the basic framework of the Trust and the Partnership, and
reference is made to the Trust Indenture and the Partnership Agreement for
detailed provisions concerning the Trust and the Partnership.
 
CREATION AND TRANSFER OF THE ROYALTY
 
     On September 30, 1983, pursuant to the terms of the Overriding Royalty
Conveyance (the Conveyance), the Company transferred, for the benefit of FTX's
stockholders, a net overriding royalty interest (the Royalty) in what then
represented 18 productive (the Productive Properties) and 12 undeveloped (the
Undeveloped Properties) oil and gas leases offshore Louisiana, Texas and
California equal to 90 percent of the net proceeds from the Company's working
interests in such properties. See "THE ROYALTY PROPERTIES AND THE
ROYALTY -- Computation of the Royalty." The Productive Properties and the
Undeveloped Properties are referred to herein jointly as the "Royalty
Properties."
 
     FTX assigned the Royalty to the Partnership in exchange for a 99.9 percent
interest therein. Immediately thereafter, FTX assigned its 99.9 percent general
partnership interest in the Partnership to the Trust in exchange for the Units.
Units were then distributed to FTX's stockholders.
 
THE PARTNERSHIP
 
     Title to the Royalty is held by the Partnership, a general partnership
formed under the laws of the State of Texas and in which the Trustee, for the
benefit of the Unit holders, has a 99.9 percent general partnership interest and
the Managing General Partner (discussed below) has a 0.1 percent general
<PAGE>   4
 
partnership interest. The Partnership was formed and exists for the purpose of
receiving and holding the Royalty, receiving the proceeds from the Royalty,
paying the liabilities and expenses of the Partnership and disbursing remaining
revenues to the Trustee and the Managing General Partner in accordance with
their interests.
 
     The Managing General Partner of the Partnership is the American Royalty
Partnership Management Company (ARPMC), a Colorado corporation which is owned by
the Greater New Orleans Foundation, a Louisiana nonprofit corporation. FMOG
provides the staff and facilities to carry out the administrative duties for and
on behalf of ARPMC and FTX has indemnified the Partnership for the obligations
of ARPMC in connection with its duties and responsibilities as Managing General
Partner.
 
THE TRUST
 
     Under the Trust Indenture, the Trustee holds an interest in the Partnership
for the benefit of the Unit holders. The terms of the Trust Indenture provide,
among other things, that (1) the Trustee cannot engage in any business or
investment activity and cannot acquire any asset other than its interest in the
Partnership and cash being held for payment of liabilities or distribution to
Unit holders; (2) the Royalty can be sold in whole or in part upon approval of
the Unit holders or upon termination of the Trust; and (3) any cash
distributions to the Unit holders are made by the Trustee quarterly in January,
April, July and October of each year.
 
     The Trust Indenture provides that Unit holders take their Units subject to
the provisions of the Trust Indenture, which gives the Trustee only such rights
and powers as are necessary and proper for the conservation and protection of
the Royalty. Accordingly, the Trustee has no responsibility or authority with
respect to the operation of the Royalty Properties. The Trust is a passive
trust, and the Trust Indenture requires the Trustee (a) to receive all income
and proceeds of the Royalty net of other Partnership expenses and net of amounts
attributable to the Managing General Partner's 0.1 percent interest in the
Partnership, (b) to pay or provide for the payment of expenses, charges,
liabilities and obligations of the Trust and (c) to distribute to Unit holders
the remaining revenues attributable to the Royalty.
 
     Texas Commerce, which also acts as Trustee of the Trust, and its parent,
Chase Manhattan Corporation, have banking relationships with the Company.
 
     The Trust has no employees. Administrative functions of the Trust are
performed by the Trustee, which is compensated for its services and reimbursed
for specified charges for transfer agency and distribution functions out of
Trust assets. The Trustee is also entitled to reimbursement for its out-of-
pocket expenses. Because of the passive nature of the Trust assets and the
restrictions on the power of the Trustee to incur obligations, the only
liabilities which the Trustee ordinarily incurs are those for routine
administrative expenses, such as Trustee's fees and accounting, legal and other
administrative fees. The costs and expenses of the Trust (including the
Trustee's fees) are estimated to approximate $0.4 million for 1997. The Trustee,
in accordance with the Trust Indenture, established an expense reserve of
approximately $2.4 million to cover Trust expenses as discussed in Note
7 -- Establishment of an Expense Reserve. The costs and expenses of the Trust
may increase in future years, depending on the volume of trading in the Units,
the amount of revenues to the Trust and increases in accounting, legal and other
administrative fees.
 
DUTIES AND LIMITED POWERS OF THE TRUSTEE
 
     Under the Trust Indenture, the Trustee receives the Trust's share of any
distributions from the Partnership and pays all expenses, charges, liabilities
and obligations of the Trust. With respect to any liability which is contingent
or uncertain in amount or which otherwise is not currently due and payable, the
Trustee has the discretion to establish a cash reserve for the payment of such
liability. If at any time the cash on hand and to be received by the Trustee is
not, in its judgment, sufficient to pay liabilities of the Trust as they become
due, the Trustee is authorized to borrow the funds required to pay such
liabilities, in which event no further distributions will be made to Unit
holders until such
 
                                        2
<PAGE>   5
 
borrowing has been repaid. The Trustee is permitted to borrow such funds from
any bank, including itself. To secure payment of any such indebtedness, the
Trustee is authorized to mortgage, pledge, grant security interests in or
otherwise encumber assets of the Trust, or any portion thereof, to cause the
Partnership to mortgage, pledge, grant security interests in or otherwise
encumber the Royalty, and to cause the Partnership to carve out and convey
production payments. After payment of or provision for Trust expenses and
obligations, the Trustee makes quarterly distributions to the Unit holders of
all the proceeds received from the Partnership in respect of the Royalty and not
theretofore distributed. The Trustee submits periodic financial reports to the
Unit holders as described under "DESCRIPTION OF THE UNITS -- Periodic Reports."
 
     The Trust Indenture authorizes the Trustee to take such action as in its
judgment is necessary or advisable to achieve the purposes of the Trust. The
Trust Indenture provides that cash being held by the Trustee as a reserve for
liabilities or for distribution at the next distribution date will be placed in
interest-bearing accounts or certificates (which may include accounts or
certificates of the bank acting as Trustee), but the Trustee is otherwise
prohibited from acquiring any asset other than the Trust's interest in the
Partnership or engaging in any business or investment activity of any kind
whatsoever. The Trustee may sell or dispose of its interest in the Partnership,
or permit the Partnership to sell or dispose of all or any part of the Royalty,
only as authorized by a vote of the Unit holders upon termination of the Trust
and in certain other limited circumstances. However, the Trust is directed to
effect such a sale (without any such vote) if the Trust's cash receipts for each
of three successive years commencing after December 31, 1990 are less than $3
million. The Trustee must distribute the net proceeds of such sale (after
satisfaction of any outstanding liabilities) to the Unit holders.
 
     The Trustee is also authorized to agree to modifications of the terms of
the Partnership Agreement or to cause the Partnership to agree to modifications
of the terms of the Conveyance or to settle disputes with respect thereto, so
long as such modifications or settlements do not (i) alter the nature of the
Royalty as a right to receive a share of the proceeds of minerals produced from
the Royalty Properties, free of any expense or other cost and without any
operating rights, or (ii) alter the Partnership Agreement so as to change the
purposes or scope of activities of the Partnership. Furthermore, the Trustee may
not agree to any distribution from the Partnership of the Royalty, or any other
asset of the Partnership, which would cause the interest of the holders of Units
to be treated as other than an intangible personal property interest.
 
LIABILITIES OF THE TRUSTEE
 
     The Trustee may act in its discretion and will be personally or
individually liable only for fraud, gross negligence or bad faith. The Trustee
will be indemnified from the Trust assets for any liability, expense, claim,
damage or other loss incurred in performing its duties, unless resulting from
fraud, gross negligence or bad faith, and will have a lien upon the assets of
the Trust as security for such indemnification and for reimbursements and
compensation to which it is entitled. The Trustee will not be entitled to
indemnification from Unit holders.
 
TERMINATION OF THE TRUST
 
     The Trust Indenture provides generally that the Trust shall terminate upon
the first to occur of: (i) the sale of all the Trust's interest in the
Partnership, or the sale by the Partnership of all of its assets including the
Royalty, or (ii) a decision to terminate the Trust by the affirmative vote of
Unit holders representing a majority of the Units. As noted above, the Trustee
is required to sell the Trust's interest in the Partnership, or cause the
Partnership to sell the Royalty, if the Trust's cash receipts for each of three
successive years are less than $3 million, thereby terminating the Trust
pursuant to (i) above. Upon the termination of the Trust under (ii) above, the
Trustee will sell the Royalty (or will cause the Partnership to sell all of the
assets of the Partnership). The Trustee will as promptly as possible distribute
the proceeds of any such sales according to the respective interests and rights
of the Unit holders after discharging all of the liabilities of the Trust and,
if necessary, setting up reserves in such amounts as the Trustee in its
discretion deems appropriate for contingent liabilities.
 
                                        3
<PAGE>   6
 
                            DESCRIPTION OF THE UNITS
 
GENERAL
 
     Each Unit is evidenced by a transferable certificate. Each Unit evidences
an undivided interest in the Trust, which in turn owns a 99.9 percent interest
in the Partnership. A total of 14,975,390 Units are outstanding.
 
DISTRIBUTIONS AND INCOME COMPUTATIONS
 
     Each month the Trustee determines the amount available for distribution for
such month. Such amount (the Monthly Distribution Amount) is equal to the
excess, if any, of the cash distributed by the Partnership to the Trust during
such month, plus any other cash receipts of the Trust during such month (other
than interest earned on the Monthly Distribution Amount for any other month)
over the liabilities of the Trust paid during such month, subject to adjustments
for changes made by the Trustee during such month in any cash reserves
established for the payment of contingent or future obligations of the Trust.
The Monthly Distribution Amount for each month is payable to Unit holders of
record on the Monthly Record Date, which is the close of business on the last
business day of such month, or such later date as the Trustee determines is
required to comply with legal or stock exchange requirements. However, to reduce
the administrative expenses of the Trust, the Trustee does not distribute cash
monthly, but rather, during January, April, July and October of each year. The
Trustee distributes to each person who was a Unit holder of record on a Monthly
Record Date during one or more of the immediately preceding three months, the
Monthly Distribution Amount for the month or months that he was a Unit holder of
record, together with interest earned on such Monthly Distribution Amount from
the Monthly Record Date to the payment date.
 
     Because the Trust is classified for tax purposes as a "grantor trust" and
the Partnership is classified for tax purposes as a partnership (see "FEDERAL
INCOME TAX CONSIDERATIONS") and is required to use the accrual method of
accounting, the net taxable income from the Royalty (other than interest earned
on Monthly Distribution Amounts) will be realized by the Unit holders for tax
purposes in the month accrued by the Partnership, rather than in the month
distributed by the Trust. Thus, a Unit holder may be required to report income
attributable to his Units without receiving distributions directly corresponding
to such income.
 
NATURE OF THE UNITS
 
     The Units are not an interest in or obligation of the Company, the Working
Interest Owner or any successor Working Interest Owner. However, the ultimate
value of the Royalty is dependent to a large extent upon the ability of the
Working Interest Owner to produce oil and gas from the Royalty Properties. There
is no requirement that the Working Interest Owner expend any specific amounts
with respect to the Royalty Properties. The Working Interest Owner is free to
transfer its working interest (burdened by the Royalty) to third parties. In
certain cases the Working Interest Owner is permitted to farmout interests in
the Royalty Properties and to reduce the Royalty proportionately. See "THE
ROYALTY PROPERTIES AND THE ROYALTY -- General and -- Production and Drilling
Activities." The Working Interest Owner does not have an obligation to produce
any specific amounts of oil and gas from any of the Royalty Properties. It has
the right to abandon any well or lease, and upon termination of any lease the
portion of the Royalty relating thereto will be extinguished. The amount of
revenues attributable to the Royalty may be affected by operating agreements and
unitization and pooling arrangements. The realization of the ultimate value of
the Royalty is subject to all the risks associated with exploration on and
development of oil and gas properties and to comprehensive regulation by
governmental authorities.
 
TRANSFER OF THE UNITS
 
     Units are transferable on the records of the Trustee or transfer agent upon
the surrender of any certificate representing Units in proper form for transfer
as required by the Trustee. No service charge
 
                                        4
<PAGE>   7
 
is made to the transferor or transferee for any transfer of a Unit, but the
Trustee may require payment of a sum sufficient to cover any tax or other
governmental charge that may be imposed in connection with such transfer.
 
PERIODIC REPORTS
 
     As promptly as practicable following the end of each quarter, the Trustee
is required to mail to each person who was a Unit holder of record on the
Monthly Record Date for any month during such quarter a report which shows in
reasonable detail the assets and liabilities and receipts and disbursements of
the Trust for such quarter and for each month in such quarter. As promptly as
practicable following the end of each fiscal year, the Trustee is required to
mail to Unit holders of record as of a date to be selected by the Trustee an
annual report containing audited financial statements of the Trust.
 
     The Trustee is required to file such returns for federal income tax
purposes as in its judgment are required to comply with applicable law and to
permit each Unit holder to report correctly his share of the income and
deductions of the Trust. The Trustee will treat all income and deductions
recognized during each month as reportable by Unit holders of record on the
Monthly Record Date of such month unless otherwise advised by counsel or the
Internal Revenue Service.
 
     The Conveyance provides that the Working Interest Owner maintain books and
records sufficient to determine the amounts payable to the owner of the Royalty.
On the eleventh day prior to the last business day of each month the Working
Interest Owner is required to provide the Partnership with information regarding
the amount of the Royalty payment to be made on the next Monthly Record Date.
The Working Interest Owner is also required to provide material information
regarding the Royalty Properties.
 
     The Trustee has no duty to secure, file or disseminate information to which
it is not expressly afforded access under the terms of the instruments creating
the Trust or which it is unable to obtain without unreasonable effort and
expense.
 
LIABILITY OF OWNERS OF UNITS
 
     Regarding the Unit holders, the Trust Indenture provides that the Trustee
will be fully liable if the Trustee incurs any liability, except with respect to
the income tax and oil and gas pricing matters described in the next paragraph,
without taking reasonable steps to ensure that such liability will be
satisfiable only out of the Trust assets (regardless of whether the assets are
adequate to satisfy the liability) and in no event out of amounts distributed
to, or other assets owned by, Unit holders. However, under the laws of Texas
(and perhaps California, if applicable), it is unclear whether a Unit holder
would be jointly and severally liable for any liability of the Trust in the
event that both of the following conditions were to occur: (a) the satisfaction
of such liability was not by contract limited to the assets of the Trust, and
(b) the assets of the Trust were insufficient to discharge such liability. Each
Unit holder should weigh this potential exposure in deciding whether to retain
or transfer his Units. In that connection, Unit holders should consider the
value and passive nature of the Trust assets and the restrictions on the power
of the Trustee to incur liabilities.
 
     The Trust Indenture provides that the Trustee will not be liable to Unit
holders for state or federal income taxes or for refunds, fines, penalties or
interest relating to oil or gas pricing overcharges under state or federal price
controls. With respect to gas pricing matters, the Federal Energy Regulatory
Commission (FERC) is not considered to be empowered under current judicial
decisions to compel refunds of gas price overcharges from overriding royalty
interest owners. It is possible, however, that laws on such matters may change
in the future or that other parties, such as oil or gas purchasers, might be
able to instigate legal action to compel such refunds from royalty owners and
that Unit holders might be treated for such purpose as royalty owners.
 
                                        5
<PAGE>   8
 
STATE LAW CONSIDERATIONS
 
     It is anticipated, based on the structure of the Trust and the Partnership,
that the Units will be treated for certain state law purposes essentially the
same as other securities, that is, as interests in intangible personal property
rather than as interests in real property. However, in the absence of
controlling legal precedent there is a possibility that under certain
circumstances a Unit holder could be treated as owning an interest in real
property. In that event, the tax, probate, devolution of title and
administration laws of Texas, Louisiana or California applicable to real
property may apply to the Units, even if held by a person who is not a resident
or domiciliary thereof. Application of such laws could make inheritance and
related matters with respect to the Units substantially more onerous than had
the Units been treated as interests in intangible personal property. In any
event, however, the ownership of Units and realization of income from the
Royalty by a Unit holder may subject such Unit holder to state or local income
or other taxation in the state of the Unit holder's residence or domicile. Unit
holders should consult their legal and tax advisors regarding the applicability
of these considerations to their individual circumstances.
 
POSSIBLE REQUIREMENT THAT UNITS BE DIVESTED
 
     Although the Trust Indenture imposes no restrictions based on nationality
or other status of the persons or other entities who are eligible to hold Units,
it does provide that if at any time the Trust or Trustee is named as a party in
any judicial or other proceeding which seeks the cancellation or forfeiture of
the Trust's interest in any of the Royalty Properties because of the nationality
or other status of any one or more Unit holders, such Unit holders may be
required to sell their Units according to procedures set forth in the Trust
Indenture.
 
                     THE ROYALTY PROPERTIES AND THE ROYALTY
 
EXPLANATORY NOTE
 
     The Trustee has no responsibility relating to the operations of the Royalty
Properties. The information in this report, relating to the characteristics of
and operations on the Royalty Properties and certain other matters, has been
furnished to the Trustee by the Working Interest Owner.
 
     The information in this report regarding the Royalty Properties should be
read in light of the following: The Royalty was carved out of working interests
owned by the Company at the time of creation of the Trust. References in this
report to "net" wells and acres refer to the sum of the fractional working
interests owned by the Working Interest Owner (from which the Royalty was
carved) in the "gross" wells or acres. References to the percentage of the
working interest owned by the Working Interest Owner are references to the
working interest out of which the Royalty was carved. For example, a reference
to a "50 percent working interest" in a well or lease which is included in a
Royalty Property indicates that the Partnership's net overriding royalty
interest (equal to 90 percent of the Net Proceeds, as defined, from all the
Royalty Properties) burdens half of the total working interest in the well or
lease. Such 50 percent working interest will also be subject to landowners'
royalties and may be subject to other overriding royalty interests and other
burdens which are considered prior to calculations of amounts payable to the
owner of the Royalty. Since the amounts and nature of such burdens vary from
lease to lease, the information presented herein and elsewhere regarding the
Working Interest Owner's percentage of the working interest in any well or lease
cannot be used to calculate precisely the interest attributable to the Trust in
a well or lease. In addition, (i) because operating and capital costs are taken
into consideration in calculating the amounts payable to the owner of the
Royalty and because prices for oil and gas may vary from field to field,
information regarding results of well tests of gross quantities of production
from a given well cannot be used to compute the interest attributable to the
Trust, and (ii) because the Royalty Properties consist of multiple leases in
multiple fields, the interest of the Working Interest Owner in any given well or
lease may not be indicative of the interest attributable to the Trust in the
Royalty Properties.
 
                                        6
<PAGE>   9
 
GENERAL
 
     The map on page 8 shows the location and selected information as of
December 31, 1996 for all of the productive Royalty Properties where production
or drilling operations are currently under way. Additional exploration may be
proposed for certain other Royalty Properties where geologic features have been
identified through the utilization of 3-D seismic technology. After analyzing
each proposal, the Working Interest Owner will determine whether or not to
participate in additional exploratory operations.
 
     As of December 31, 1996, there were 2 gross productive oil wells and 13
gross productive gas wells on 10 of the remaining Royalty Properties where the
Working Interest Owner retains a working interest.
 
     All remaining Royalty Properties are operated by other oil and gas
companies under joint operating agreements. Neither the Working Interest Owner
nor any operator has any contractual commitments to the Partnership or the Trust
to conduct further exploratory or development drilling on the Royalty Properties
or to maintain its ownership interest in any of the properties. See "Certain
Factors Affecting Distributions; Conflicts of Interest." However, any operator
of a Royalty Property (including the Working Interest Owner) has an obligation
to operate and develop such property in accordance with the standards of a
reasonable and prudent operator. The Working Interest Owner retains a revenue
interest in the remaining Royalty Properties and it has informed the Trustee
that it may conduct further development and exploratory activities on certain of
the Royalty Properties. See "Production and Drilling Activities" below for a
discussion of current development and exploratory activities on certain of the
Royalty Properties.
 
RESERVES
 
     A study of the proved oil and gas reserves attributable to the Royalty
Properties as of December 31, 1996, has been made by Ryder Scott Company
Petroleum Engineers, independent petroleum engineers (Ryder Scott). In
accordance with regulations of the Securities and Exchange Commission (the SEC),
such study is limited to reserves currently classified as "proved." The amount
of reserves and the timing of production attributable to the Royalty Properties
are, and in the future will continue to be, significantly affected by the level
of capital expenditures to be incurred on the individual properties and the
success of exploration and development activities. The assumptions used in
preparing the reserve study are detailed within the following letter, which
summarizes such reserve study. Such assumptions, as well as the cautionary
paragraphs following the letter, should be studied carefully together with the
estimates contained in the letter. Ryder Scott also prepared estimates of future
net cash flows attributable to the Royalty from proved oil and gas reserves and
the discounted present value of such future net cash flows. The estimates of
Ryder Scott are used in the preparation of the Trust's financial statements and
for other reporting purposes. However, as explained in the cautionary paragraphs
immediately following the letter, Ryder Scott's estimates were prepared based on
production and costs as of December 31, 1996, but the timing of inclusion of
production and costs for purposes of calculating Royalty payments during a given
period varies somewhat from the method used by Ryder Scott in preparing its
estimates. For example, the estimates do not take into account amounts received
in 1997 attributable to sales of oil and gas produced in the fourth quarter of
1996, volumes of natural gas sold by other parties pursuant to certain gas
balancing arrangements and the effect of the excess Class A cost carry-forward
at December 31, 1996. Therefore, the amounts set forth in the letter are not
necessarily indicative of actual amounts to be distributed to Unit holders,
either annually or ultimately.
 
     The estimates of future net cash flows and discounted present value of
future net cash flows were prepared using prices and costs as of December 31,
1996. Proved reserves are estimated quantities of oil and gas which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions (see Note 10 -- Supplementary Proved Oil and Gas Reserve
Information).
 
                                        7
<PAGE>   10

                           [PRODUCTIVE PROPERTY MAP]

[The map shows the fields offshore Louisiana and Texas identifying the location
of the Trust's productive properties by block number, including gross and net
acreage and working interest percentage for each block, as of December 31,
1996.] 

<TABLE>
<CAPTION>
                                Working                  
       Property                Interest       Gross Acres       Net Acres
       --------                --------       -----------       ---------
<S>                            <C>            <C>               <C>
Royalty Properties --
Offshore Louisiana:
Breton Sound Blk. 55..........   18.75           2,497              468
Vermilion Blk. 21.............    4.17           4,139              172
Vermilion Blk. 22.............    4.17           5,000              208
Vermilion Blk. 58.............   22.50           5,000            1,125
West Cameron Blk. 65..........    4.17           5,000              208
West Cameron Blk. 215.........   31.38           5,000            1,564
West Cameron Blk. 498.........   23.08           5,000            1,154
West Delta Blk. 34............   30.00           2,500              750

Offshore Texas:
High Island Blk. A-552........   35.00           3,500            1,260
</TABLE>

* The Royal Trust owns 99.9% of a 90% net profits interest in the Working
  Interest for each block.





                                       8
<PAGE>   11



                      [RIDER SCOTT COMPANY LETTERHEAD]





                               March 21, 1997




Freeport-McMoRan Oil and Gas Royalty Trust
c/o Texas Commerce Bank National Association, Trustee
600 Travis Street, Suite 1150
Houston, Texas  77002

Gentlemen:

                 At the request of Freeport-McMoRan Oil & Gas Company (FMOG), a
division of Freeport-McMoRan Inc. (FTX), we have prepared estimates of the
proved reserves and future production and income attributable to a net
overriding royalty interest in certain offshore leases as of December 31, 1996.
The future income has been calculated using Securities and Exchange Commission
(SEC) guidelines for price and cost parameters.

                 The net overriding royalty interest is equal to a 90 percent
net profits interest in leases owned by a subsidiary of FTX on September 30,
1983.  The leases are located in the Gulf of Mexico offshore of Louisiana and
Texas.  This net overriding royalty interest (Royalty) is the property that FTX
transferred to Freeport-McMoRan Oil and Gas Royalty Partnership (Partnership),
a partnership which is owned 99.9 percent by Freeport-McMoRan Oil and Gas
Royalty Trust.  The term "Working Interest Owner" includes FMOG and the
successors and assigns of its oil and gas working interests to the extent the
context requires.

                 Ten offshore leases subject to the Royalty have been
considered in this report, and the impact of these leases' reserves, revenues,
expenses, and expense accruals on the income of the Partnership has been
determined. These ten leases are hereinafter referred to as the "Subject
Properties".  All other leases originally subject to the Royalty have either
expired, or have been farmed out, with the working interest owner retaining an
overriding royalty interest burdened by the Royalty.  The Working Interest
Owner has assured us that no leases other than the ten included in our
evaluation have a material effect on the overall revenues or liabilities of the
Partnership.

                 The estimated reserve quantities and future income quantities
presented in this report are related to hydrocarbon prices.  December 1996
hydrocarbon prices were used in the preparation of this report as required by
SEC guidelines; however, actual future prices may vary significantly from
December 1996 prices.  Therefore, volumes of reserves actually recovered and
amounts of income actually received may differ significantly from the estimated
quantities presented in this report.  The results of this study are summarized
as follows:




                                      9



<PAGE>   12
Freeport-McMoRan Oil and Gas Royalty Trust
March 21, 1997
Page 2


                                 SEC PARAMETERS
                     Estimated Net Reserve and Income Data
                Freeport-McMoRan Oil and Gas Royalty Partnership
                            As of December 31, 1996

<TABLE>
<CAPTION>
                                                     Proved                Proved                 Total
                                                   Developed            Undeveloped               Proved
                                                  ------------         ---------------         --------------
        <S>                                         <C>                 <C>                    <C>
        Remaining Reserves
           Oil/Condensate - Barrels                     80,668                759,548                840,216
           Gas - MMCF                                      794                  4,229                  5,023
        
        Future Net Income (FNI)
           1997                                     $2,051,941          -$  8,039,494          -$  5,987,553
           1998                                      1,523,521              9,101,591             10,625,112
           1999                                        548,655              3,915,758              4,464,413
                                                  ------------          -------------          -------------
           Sub-Total (1997-1999)                    $4,124,117           $  4,977,855           $  9,101,972
           Remaining                                 3,550,339             30,146,220             33,696,559
                                                   -----------           ------------           ------------
           Total                                    $7,674,456            $35,124,075            $42,798,531
        
        Discounted FNI @ 10%                        $5,142,047            $19,855,934            $24,997,981
        (Compounded Annually)
</TABLE>

                 Liquid hydrocarbons are expressed in standard 42 gallon
barrels.  All gas volumes are sales gas expressed in millions of cubic feet
(MMCF) at 60 degrees Fahrenheit and 15.025 pounds per square inch absolute.

                 The reserve volumes and income values shown above for the
properties transferred to the Partnership were estimated from projections of
reserves and income attributable to the combined interests consisting of the
Royalty and the interest of the Working Interest Owner in the Subject
Properties.  Interests related to non-consent operations and interests acquired
subsequent to the conveyance of the Royalty to the Partnership are excluded
from the calculation of Partnership income.

                 The future net income attributable to the Royalty was
estimated on a yearly basis from a projection of the combined Working Interest
Owner and Partnership future net income.  Combined future net income values
were calculated by deducting operating expenses and capital costs from the
future gross revenue of the combined interests.  Only those expenses and
capital costs necessary for the development and production of proved reserves
were taken into consideration.  The annual income values for each property were
further reduced by an overhead charge furnished by the Working Interest Owner.
The adjusted annual income resulting from subtracting the overhead charge was
multiplied by a factor of 90 percent to arrive at the annual future net income
of the Partnership.

                 More than a sufficient amount of income has been accrued as of
December 31, 1996 to pay for the unescalated estimated abandonment costs
attributable to the Royalty; therefore, using SEC pricing and cost parameters,
it is anticipated that no future accruals will be necessary.  Furthermore, a
reimbursement is included as Partnership income in the year after depletion and
abandonment of the Subject Properties.  This reimbursement is equal to the
amount by which current unspent accruals exceed anticipated unescalated future
abandonment costs.

                 The future net income calculated for the Partnership is before
the deduction of state and federal income taxes and does not include any
adjustment for cash on hand or undistributed income.  No attempt has been made
to quantify or otherwise account for any accumulated gas




                                      10
<PAGE>   13
Freeport-McMoRan Oil and Gas Royalty Trust
March 21, 1997
Page 3


imbalances that may exist.  In accordance with Securities and Exchange
Commission regulations, discounted future net income values shown above were
calculated by discounting the future net income at the rate of 10 percent per
year; however, such rate is not necessarily the most appropriate discount rate.
At the request of the Working Interest Owner, annual compounding was used in
the computation of discounted future net income.  Discounted future net income
should not be construed as Ryder Scott Company's estimate of fair market value
since no consideration was given to the additional factors that influence the
prices at which oil and gas properties are bought and sold, such as taxes on
income, allowance for return on investments and business risks.

                 It should be noted that, although the Partnership will not be
directly subject to the aforementioned deductions (operating costs, capital
costs, and overhead charges), these deductions will affect the future net
income of the Partnership as described above.  Therefore, the estimated net
income attributable to the Partnership will change if actual costs differ from
those used in our estimates.

                 Estimates of reserves attributable to the Partnership are
shown above as required by the Securities and Exchange Commission; however,
there is no precise method of allocating estimates of physical quantities of
reserves between the Working Interest Owner and the Partnership, since the
Royalty is a net profits interest, and the Partnership does not own, and is not
entitled to receive, any specific volume of reserves.  Net reserves
attributable to the Royalty were estimated by allocating to the Partnership a
portion of the estimated combined net reserves of the Subject Properties using
a formula based on future income.  The quantities of reserves indicated by such
formula will be affected by future changes in various economic factors utilized
in estimating future gross revenues and net income from the Subject Properties.
Therefore, the estimates of reserves set forth above are to a large extent
hypothetical and are not comparable to estimates of reserves attributable to a
working interest.  At the request of the Working Interest Owner, the following
formula was used on a yearly basis to estimate the required net reserves
attributable to the Royalty of each property:

                                             Royalty Future Net Income
         Partnership Interest Net Reserves = ------------------------------
                                             Price per Unit of Reserves

The price per unit of reserves was calculated by dividing combined future gross
revenues by combined net reserves.

RESERVE DEFINITIONS

                 The proved reserves presented in this report comply with the
Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission's Staff Accounting Bulletins, and are based
on the following definitions and criteria:

             Proved reserves of crude oil, condensate, natural gas, and natural
      gas liquids are estimated quantities that geological and engineering data
      demonstrate with reasonable certainty to be recoverable in the future
      from known reservoirs under existing operating conditions using the cost
      and price parameters discussed in other sections of this report.
      Reservoirs are considered proved if economic producibility is supported
      by actual production or formation tests.  In certain instances, proved
      reserves are assigned on the basis of a combination of core analysis and
      electrical and other type logs which indicate the reservoirs are
      analogous to reservoirs in the same field which are producing or have
      demonstrated the ability to produce on a formation test.  The area of a
      reservoir considered proved includes (1) that portion delineated by
      drilling and defined by fluid contacts, if any, and (2) the adjoining
      portions not yet drilled that can be reasonably judged as economically
      productive on the basis of available geological and



                                      11

<PAGE>   14
Freeport-McMoRan Oil and Gas Royalty Trust
March 21, 1997
Page 4


      engineering data.  In the absence of data on fluid contacts, the lowest
      known structural occurrence of hydrocarbons controls the lower proved
      limit of the reservoir.  Proved reserves are estimates of hydrocarbons to
      be recovered from a given date forward.  They may be revised as
      hydrocarbons are produced and additional data become available.  Proved
      natural gas reserves are comprised of non-associated, associated and
      dissolved gas.  An appropriate reduction in gas reserves has been made
      for the expected removal of natural gas liquids, for lease and plant
      fuel, and for the exclusion of non-hydrocarbon gases if they occur in
      significant quantities and are removed prior to sale.

             Reserves that can be produced economically through the application
      of improved recovery techniques are included in the proved classification
      when these qualifications are met:  (1) successful testing by a pilot
      project or the operation of an installed program in the reservoir
      provides support for the engineering analysis on which the project or
      program was based, and (2) it is reasonably certain the project will
      proceed.  Improved recovery includes all methods for supplementing
      natural reservoir forces and energy, or otherwise increasing ultimate
      recovery from a reservoir, including (1) pressure maintenance, (2)
      cycling, and (3) secondary recovery in its original sense.  Improved
      recovery also includes the enhanced recovery methods of thermal, chemical
      flooding, and the use of miscible and immiscible displacement fluids.

             Estimates of proved reserves do not include crude oil, natural
      gas, or natural gas liquids being held in underground or surface storage.

             Depending on the status of development, these proved reserves are
      further subdivided into:

             (i)  "developed reserves" which are those proved reserves
             reasonably expected to be recovered through existing wells with
             existing equipment and operating methods, including (a) "developed
             producing reserves" which are those proved developed reserves
             reasonably expected to be produced from existing completion
             intervals now open for production in existing wells, and (b)
             "developed non-producing reserves" which are those proved
             developed reserves which exist behind the casing of existing wells
             which are reasonably expected to be produced through these wells
             in the predictable future where the cost of making such
             hydrocarbons available for production should be relatively small
             compared to the cost of a new well; and

             (ii) "undeveloped reserves" which are those proved reserves
             reasonably expected to be recovered from new wells on undrilled
             acreage, from existing wells where a relatively large expenditure
             is required, and from acreage for which an application of fluid
             injection or other improved recovery technique is contemplated
             where the technique has been proved effective by actual tests in
             the area in the same reservoir.  Reserves from undrilled acreage
             are limited to those drilling units offsetting productive units
             that are reasonably certain of production when drilled.  Proved
             reserves for other undrilled units are included only where it can
             be demonstrated with reasonable certainty that there is continuity
             of production from the existing productive formation.

ESTIMATES OF RESERVES

                 In general, the reserves included herein were estimated by
performance methods or the volumetric method; however, other methods were used
in certain cases where characteristics of the data indicated such other methods
were more appropriate in our opinion.  The reserves estimated by the
performance method utilized extrapolations of various historical data in those
cases where


                                      12

<PAGE>   15
Freeport-McMoRan Oil and Gas Royalty Trust
March 21, 1997
Page 5


such data were definitive in our opinion.  Reserves were estimated by the
volumetric method in those cases where there were inadequate historical
performance data to establish a definitive trend or where the use of production
performance data as a basis for the reserve estimates was considered to be
inappropriate.

                 The reserves included in this report are estimates only and
should not be construed as being exact quantities.  They may or may not be
actually recovered, and if recovered, the revenues therefrom and the actual
costs related thereto could be more or less than the estimated amounts.
Moreover, estimates of reserves may increase or decrease as a result of future
operations.

FUTURE PRODUCTION RATES

                 Initial production rates are based on the current producing
rates for those wells now on production.  Test data and other related
information were used to estimate the anticipated initial production rates for
those wells or locations which are not currently producing.  If no production
decline trend has been established, future production rates were held constant,
or adjusted for the effects of curtailment where appropriate, until a decline
in ability to produce was anticipated.  An estimated rate of decline was then
applied to depletion of the reserves.  If a decline trend has been established,
this trend was used as the basis for estimating future production rates.  For
reserves not yet on production, sales were estimated to commence at an
anticipated date furnished by the Working Interest Owner.

                 The future production rates from wells now on production may
be more or less than estimated because of changes in market demand or
allowables set by regulatory bodies.  Wells or locations which are not
currently producing may start producing earlier or later than anticipated in
our estimates of their future production rates.

HYDROCARBON PRICES

                 The Working Interest Owner furnished us with prices in effect
at December 31, 1996 and these prices were held constant except for known and
determinable escalations.  In accordance with Securities and Exchange
Commission guidelines, changes in liquid and gas prices subsequent to December
31, 1996 were not taken into account in this report.

Oil and Condensate

                 The Working Interest Owner furnished us with initial oil and
condensate prices for the properties in this report.  These initial liquid
prices were based on actual prices received in December 1996, and were held
constant throughout the depletion of the reserves.  In accordance with
Securities and Exchange Commission guidelines, changes in liquid prices
subsequent to December 31, 1996 were not considered in this study.

Gas

                 The Working Interest Owner has furnished us with gas prices in
effect at December 1996 and with its forecasts of future gas prices which take
into account SEC guidelines and current market prices.  In accordance with SEC
guidelines, the future gas prices used in this report make no allowance for
future gas price increases which may occur as a result of inflation nor do they
allow any allowance for seasonal variations in gas prices which are likely to
cause future yearly average gas prices to be somewhat lower than December gas
prices.  At the request of the Working Interest Owner, a market price of $3.591
per MMBTU was used in this study for all uncontracted gas.



                                      13
<PAGE>   16
Freeport-McMoRan Oil and Gas Royalty Trust
March 21, 1997
Page 6


COSTS

                 The current operating, development, abandonment, and overhead
costs were held constant throughout the life of the properties.  The estimated
net cost of abandonment after salvage was used in our estimates of future
revenue from the Subject Properties since these costs are relatively large in
offshore areas.  The estimates of the net abandonment costs for the Subject
Properties were furnished by the Working Interest Owner and were accepted
without independent verification.

                 All operating, development, abandonment, and overhead costs
used in this study were furnished by the Working Interest Owner.  The operating
costs are based on the operating expense reports of the Working Interest Owner,
or on operating expense estimates furnished by the Working Interest Owner for
properties not yet on production.  The development costs are based on
authorizations for expenditure for the proposed work, or on actual costs for
similar projects.

GENERAL

                 The reserve estimates presented herein are based upon a
detailed study of the Subject Properties; however, Ryder Scott has not made any
field examination of the properties.  No consideration was given in this report
to potential environmental liabilities which may exist nor were any costs
included for potential liability to restore and clean up damages, if any,
caused by past operating practices.  The Working Interest Owner has represented
that it has given Ryder Scott access to its accounts, records, geological and
engineering data and reports and other data as were required for this
investigation.  The ownership interests, prices, and other factual data
furnished to Ryder Scott by the Working Interest Owner in connection with this
investigation were accepted without verification.  The estimates presented in
this report are based on such furnished data available through December 1996.

                 The future prices received for the sale of production may be
higher or lower than the prices used in this report as described above, and the
operating costs and other costs related to such production may also increase or
decrease from existing levels; however, such possible changes in prices and
costs were, in accordance with rules adopted by the Securities and Exchange
Commission, omitted from consideration in preparing our report.

                 Neither Ryder Scott Company nor any of its employees has any
interest in the Subject Properties and neither the employment to make this
study nor the compensation is contingent on our estimates of reserves and
future income for the Subject Properties.

                                        Very truly yours,

                                        RYDER SCOTT COMPANY
                                        PETROLEUM  ENGINEERS

                                        /s/ KENT A. WILLIAMSON, P.E.

                                        Kent A. Williamson, P.E.
                                        Group Vice President


                                       14
<PAGE>   17
 
     Of the total discounted present value of future net cash flows attributable
to the Royalty estimated by Ryder Scott, approximately 77 percent was accounted
for by West Cameron Block 498 and 8 percent by West Cameron Block 215.
 
     Because the Royalty is a "net" overriding interest (often referred to as a
net profits interest), estimates of future net cash flows to the Trust are
affected by a number of factors in addition to the engineering, well performance
and other data taken into consideration by petroleum engineers in estimating the
quantity and nature of gross oil and gas reserves in the ground. Such other
factors include projections of operating and capital costs, oil and gas prices
and the Working Interest Owner's evaluation of the economic feasibility of
conducting additional operations. In addition, because oil and gas reserve
quantities are calculated pursuant to the formula described in Ryder Scott's
letter, these other factors will affect the quantities shown as estimated oil
and gas reserves attributable to the Trust.
 
     There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production and timing of
development expenditures. The preceding reserve data represent estimates only.
Oil and gas reserve engineering must be recognized as a subjective process which
involves, among other things, estimating underground accumulations of oil and
gas that cannot be measured in an exact way, and estimates of other engineers
might differ materially from those of Ryder Scott. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing and
production subsequent to the date of the estimate may justify revision of such
estimate. Accordingly, reserve estimates are inherently different from the
quantities of oil and gas that are ultimately recovered.
 
     Moreover, the discounted present values shown above should not be construed
as the current market value of the estimated oil and gas reserves attributable
to the Royalty. In accordance with applicable requirements of the SEC, future
net cash flows were based, generally, on current prices and costs, whereas
actual future prices or costs may be materially greater or less. Actual future
net cash flows will also be affected by subsequent reserve revisions, supply and
demand for oil and gas, curtailments by gas purchasers and changes in
governmental regulations or taxation. Also, the 10 percent discount factor used
to calculate present value, as required by the SEC, is not necessarily the most
appropriate risk-adjusted rate of return, and present value, no matter what
discount rate is used, is materially affected by assumptions as to timing of
future production, which may prove to have been inaccurate.
 
     The timing of realization of future net cash flows estimated in the above
report is based on estimates of the future timing of actual production and sales
of quantities of oil and gas. Because of payment practices followed in the oil
and gas industry, there is a one or two month lag between the month in which a
quantity of oil or gas is actually produced and the month in which revenue
attributable to such production is actually received by the Working Interest
Owner. The payment procedures in the Conveyance provide that amounts received by
the Working Interest Owner in any given month are included in Gross Proceeds (as
defined in the Conveyance) for purposes of computation of amounts payable on the
last business day of the following month. See "Computation of the Royalty."
Thereafter, distributions are made to Unit holders in accordance with the
quarterly distribution procedures set forth in the Trust Indenture and described
elsewhere herein. Furthermore, as described under "Computation of the Royalty"
below, although revenues are reflected only after they are actually received,
Costs (as defined in the Conveyance) accrued in a given month are taken into
consideration in computing the amount of the Royalty payable on the last
business day of the month following the month in which the Costs are incurred,
even if they are not actually paid until later. Thus, for example, amounts
payable on the last business day in January are computed based on Gross Proceeds
received and Costs accrued during December. Generally, such Costs would include
any excess of Costs over Gross Proceeds carried forward from the previous month,
together with interest on such excess.
 
                                       15
<PAGE>   18
 
     The Ryder Scott estimates were prepared on the basis of estimated
production and Costs accrued after December 31, 1996. Thus, amounts received by
the Working Interest Owner after November 30, 1996 attributable to production
during 1996 have not been taken into account by Ryder Scott in making its
estimates, even though these amounts will be included in Gross Proceeds for
purposes of calculating amounts payable pursuant to the Royalty subsequent to
1996. The Working Interest Owner has estimated that if Ryder Scott had taken
into account the 1997 Gross Proceeds from 1996 production, the total estimated
future net cash flow and the discounted present value of such estimate in the
Ryder Scott letter would have been approximately $0.7 million higher (net to the
Trust's interest). In addition, because Ryder Scott's estimates for the
remaining period are based on estimated production and Costs accrued during each
such period and because actual Gross Proceeds and Costs will not be based on
production and Costs during the same period, the estimates for various time
periods will not in any event correspond to the amount of payments pursuant to
the Royalty during such periods.
 
     Ryder Scott gave no effect in its estimates to amounts to which the Working
Interest Owner is entitled as a result of gas imbalances for certain production
(see Note 5 -- Gas Balancing Arrangements and Note 10 -- Supplementary Proved
Oil and Gas Reserve Information). Pursuant to the Conveyance, proceeds from gas
produced from the Royalty Properties but sold by other parties pursuant to gas
balancing arrangements between the Working Interest Owner and others
(underproduction) are not included in Gross Proceeds for purposes of calculating
the Royalty. In the future the Working Interest Owner will be entitled to sell
volumes equal to such underproduction or receive cash settlements. The amounts
the Working Interest Owner will receive from the future sale of such
underproduction may be more or less than those amounts received by third parties
because of price fluctuations.
 
     The estimated future net cash flows shown in Ryder Scott's letter have not
been reduced for any capital expenditures on Productive Properties in excess of
amounts estimated to be necessary to develop proved reserves attributed thereto.
See "Computation of the Royalty" below. Similarly, such future net cash flows
have also not been reduced for costs and expenses of the Trust, which are
estimated at approximately $0.4 million per year, or of the Partnership, which
are expected to be minimal. Additionally, Ryder Scott did not take into account
the Class A cost carry-forward of $2.5 million net to the Trust, as of December
31, 1996.
 
COMPUTATION OF THE ROYALTY
 
     The following information is subject to the detailed provisions of the
Conveyance that created the Royalty. The definitions, formulas, accounting
procedures and other terms governing the computation of the Royalty are complex
and extensive, and no attempt has been made below to describe all of such
provisions. The following is a general description of the computation of the
Royalty, and reference is made to the Conveyance, which is an exhibit to this
report and is available from the Trustee upon request, for detailed provisions
concerning such computation.
 
     The Royalty is a property interest which was carved out of working
interests in leases or portions thereof owned by the Company immediately prior
to the creation of the Royalty. Therefore, the obligation to calculate and pay
amounts attributable to the Royalty under the Conveyance is the obligation of
the owner of the working interest out of which the Royalty was carved. The
Working Interest Owner is free to transfer any portion of its working interest,
burdened by the Royalty, and in the case of such transfer, the transferred
interest will be treated as a separate property for purposes of computation of
amounts payable pursuant to the Royalty. Until such transfer takes place, all of
the Royalty Properties will be treated as one property for purposes of
computation of amounts payable under the Conveyance.
 
     The Royalty entitles the holder thereof to 90 percent of the Net Proceeds
realized from the sale of oil, gas and other hydrocarbons, as, if, and when
produced from the working interests subject to the Royalty. Under the
Conveyance, "Net Proceeds" generally means the excess of Gross Proceeds
 
                                       16
<PAGE>   19
 
received (on a cash basis) during a particular month over Costs incurred (on an
accrual basis) during such month. Generally, such Costs include any excess of
Costs over Gross Proceeds carried forward from the previous month, together with
interest on such excess. Amounts equal to 90 percent of the Net Proceeds for any
month are payable by the Working Interest Owner to the Partnership on the last
business day of the following month.
 
     "Gross Proceeds" means the amount received from sales of hydrocarbons
produced from the Royalty Properties that are attributable to the working
interests subject to the Royalty, net of lessor royalties and production
payments existing at the time of the creation of the Trust which burdened the
Royalty Properties prior to the effective date of the Conveyance, and subject to
farmouts and certain other adjustments.
 
     "Costs" means, generally, (i) all costs incurred by the Working Interest
Owner in producing and operating the Royalty Properties (lease operating
expenses), (ii) all capital costs incurred, or projected to be incurred, by the
Working Interest Owner in drilling and completing exploratory and development
wells and in connection with the installation of platforms, pipelines and other
production facilities, (iii) an overhead charge and (iv) amounts recovered by
the Working Interest Owner as estimated Abandonment Costs ("Abandonment Costs"
means, generally, the future costs to be incurred by the Working Interest Owner
to plug and abandon wells and dismantle and remove platforms, pipelines and
other production facilities from the Royalty Properties).
 
     The Working Interest Owner is entitled to accrue certain estimated future
costs in accordance with a formula set forth in the Conveyance. The accrual
formula provides that, for any month and with respect to a specific item of
future costs, the Working Interest Owner may include in its costs an amount
calculated by multiplying (a) the excess of (i) the total estimated amount of
such item of future cost over (ii) the aggregate amount accrued in previous
months with respect to such item, by (b) a fraction, the numerator of which is
Adjusted Gross Proceeds for such month and the denominator of which is total
estimated future Adjusted Gross Proceeds for such month and all future months.
For this purpose, "Adjusted Gross Proceeds" means Gross Proceeds for a month
less all Class A Costs for such month, such costs that were not covered in the
previous month and interest thereon. Class A Costs are all costs that are not
Class B Costs. Class B Costs for a month are (a) costs incurred to discover or
develop minerals on certain leases, (b) any monthly future cost accruals, (c)
such costs that were not covered by proceeds in the previous month and (d)
interest thereon.
 
     If Costs exceed Gross Proceeds for any month, the excess will be recovered
by the Working Interest Owner, with interest at the prime rate (as defined in
the Conveyance), compounded monthly, out of future Gross Proceeds prior to the
making of further payments to the Partnership, but the Partnership and the
Trustee are not liable for any operating, capital or other costs or liabilities
attributable to the Royalty Properties or hydrocarbons produced therefrom. Such
recovery will apply to Class B Costs as well. The Partnership and the Trustee
are not obligated to return any Royalty income received in any period, but
overpayments made by the Working Interest Owner would reduce future amounts
payable.
 
     The Working Interest Owner is required to maintain books and records
sufficient to determine the amounts payable under the Conveyance. Additionally,
in the event of a controversy between the Working Interest Owner and any
purchaser as to the correct sales price of any production, amounts received by
the Working Interest Owner and promptly deposited by it with an escrow agent
shall not be considered as having been received by the Working Interest Owner,
and therefore shall not be included as Gross Proceeds, until the controversy is
resolved, but all amounts thereafter paid to the Working Interest Owner by the
escrow agent shall be considered Gross Proceeds. Similarly, Costs will include
any amounts the Working Interest Owner is required to pay as a refund, interest
or penalty because the amount received by it as a sales price was in excess of
that permitted by the terms of any applicable contract, statute, regulation,
order, decree or other obligation. Because the Units are publicly traded,
purchasers of Units in the market may, as a result of such procedures, receive
distributions of amounts that would have been distributed to former holders if
such amounts had not
 
                                       17
<PAGE>   20
 
been held in escrow or, conversely, may have their distributions reduced or
eliminated as a result of controversies about amounts which may have been
collected. Within 30 days following the close of each calendar quarter, the
Working Interest Owner is required to deliver to the Partnership a statement of
the computation of Net Proceeds attributable to the quarter.
 
     If a default occurs under the Conveyance, the holder of the Royalty may
pursue any legal or equitable remedies available to it, including seeking
specific performance of any covenant that has been breached. Defaults under the
Conveyance include (1) failure on the part of the Company to observe or perform
any covenant contained in the Conveyance, which failure materially adversely
affects the interests of the holder of the Royalty, and (2) certain events of
bankruptcy or insolvency relating to the Working Interest Owner.
 
CERTAIN FACTORS AFFECTING DISTRIBUTIONS; CONFLICTS OF INTEREST
 
     The amount of cash payable on account of the Royalty, and thus the amount
of cash available for distribution to Unit holders, depends upon numerous
factors and may vary substantially from month to month. In addition, conflicts
of interest may arise between the Working Interest Owner and the Trust. These
factors and potential conflicts include the following:
 
          Timing of Collections by the Working Interest Owner. An alteration in
     the timing of the receipt of payment for proceeds of production from the
     Royalty Properties from the collection pattern normally anticipated can
     occur for a number of reasons beyond the Working Interest Owner's control.
     Such altered timing can result in: (1) wide swings in Monthly Distribution
     Amounts, and (2) delays from one quarter to the next in the timing of the
     actual cash distribution by the Trust to the Unit holders of amounts
     attributable to such delayed receipts. Accordingly, the Monthly
     Distribution Amount for any particular month is not necessarily indicative
     of future Monthly Distribution Amounts which will depend on future costs
     incurred and revenues received.
 
          Capital Expenditures.  Although the Working Interest Owner's
     management believes that the Royalty Properties have potential for reserve
     additions from future exploration and development activities, the success
     of such activities cannot be assured. The value of the Royalty, and thus of
     the Units, will depend in part upon the level of, and the degree of success
     of, such activities. In the event a decision is made to explore for or
     develop hydrocarbons on the Royalty Properties, subsequent capital
     expenditures required to explore for, develop and produce the reserves
     could be of such magnitude that they would result in the elimination or
     reduction of distributions to Unit holders for a substantial period of
     time. See "Production and Drilling Activities" below.
 
          Oil and Gas Surplus and Other Marketing Factors.  The prices of crude
     oil have fluctuated significantly in recent years as a result of an
     oversupply of crude oil on world markets and other factors beyond the
     Working Interest Owner's control. Such factors may adversely affect both
     the availability of a ready market for production from the Royalty
     Properties and the sales prices received for such production. Gas market
     conditions are affected by gas price competition, competition from
     alternative fuels, energy conservation and a variety of other factors.
 
          Variation of Partnership's Interest.  Although the Royalty conveyed to
     the Partnership is set forth in the Conveyance, the actual amount of
     revenues from the Royalty Properties may be increased or reduced as a
     result of future farmouts, unit agreements and unit operating agreements.
     Certain portions of the Royalty have been and other portions of the Royalty
     may be extinguished as leases expire as a result of the failure to
     establish or maintain commercial production or to pay annual rentals. In
     addition, the Working Interest Owner's right to revenues from a well to be
     drilled in the future may be extinguished or suspended as a result of "non-
     consent" provisions of present or future operating agreements with other
     working interest owners. See "Operating Agreements" below. Since the
     Royalty was conveyed out of working interests, distributions to the Trust
     will be reduced, extinguished or suspended as, when and to the extent the
     Working Interest Owner's right to revenues from a well is reduced,
     extinguished or suspended.
 
                                       18
<PAGE>   21
 
          Operating Hazards.  Operation of the Royalty Properties is subject to
     all the risks incident to offshore exploration for and production of oil
     and gas, including blowouts, cratering, fires and marine perils such as
     capsizing, collision and adverse weather and seas. Any of these events
     could result in damage to or destruction of oil and gas wells or producing
     facilities, suspension of operations and pollution damage. Although losses
     and liabilities arising from such events would not require payment by the
     Trust of funds previously received, they would reduce the proceeds payable
     thereafter with respect to the Royalty.
 
          Ownership of Adjacent Properties. The Working Interest Owner may own
     interests in offshore tracts that are adjacent to or in the vicinity of,
     but not included in, the Royalty Properties, and it may in the future
     acquire additional such tracts. Drilling conducted on the Royalty
     Properties may provide the Working Interest Owner or any successor with
     valuable information regarding such other tracts, which it would then be
     free to develop unburdened by the Royalty and which in some cases could
     drain oil and gas from the Royalty Properties. In the second quarter of
     1995, McMoRan Oil & Gas Co. (MOXY), a former affiliate of the Working
     Interest Owner, acquired a 25% undivided interest in West Cameron Block
     519, a tract which is adjacent to West Cameron Block 498. The Royalty will
     not apply to this tract just as it would not have applied had it been
     purchased by the Working Interest Owner. The Working Interest Owner is not
     the operator of West Cameron 498 and MOXY is not the operator of West
     Cameron 519, and neither has the voting interest necessary to determine the
     nature or timing of operations on either of these tracts.
 
          Negotiation and Amendment of Contracts. The Working Interest Owner and
     the purchasers of gas from the Royalty Properties have the right to enter
     into and amend contracts for the sale of production without the consent of
     the Trustee. In addition, the Working Interest Owner is responsible for the
     marketing of its working interest share of any commercial quantities of oil
     or gas produced from the Royalty Properties. Although the Working Interest
     Owner is generally expected to seek the highest prices obtainable for the
     production, its negotiations regarding future contracts and possible
     revisions to existing contracts may be affected by factors which are of
     economic significance to it but not to the Unit holders, such as the
     existence or anticipation of other contractual arrangements between the
     Working Interest Owner and the purchaser. The Working Interest Owner is
     entitled to make arrangements for the marketing of its share of production
     from the Royalty Properties independently of other working interest owners.
 
          Transfer of Working Interest; Abandonment. The Working Interest Owner
     is free to transfer all or a portion of its working interest in any Royalty
     Property (burdened by the Royalty) to any third party in sound financial
     condition. The Working Interest Owner is also free to enter into farmouts
     on the Royalty Properties, whereby it would transfer a portion of its
     interest (unburdened by the Royalty) while retaining a lesser interest
     (burdened by the Royalty) in return for the transferee's obligation to
     drill a well on the Royalty Property; however, it may not enter into such
     farmouts on the Productive Properties except with respect to exploratory
     wells. The Working Interest Owner has the right to abandon any well or
     lease if, in its opinion, such well or lease ceases to produce or is not
     capable of producing in paying quantities, and upon termination of any
     lease, the portion of the Royalty relating thereto will be extinguished.
     Should a lease on one of the Royalty Properties expire, the Working
     Interest Owner would thereafter be free to acquire a new lease on the same
     block, unburdened by the Royalty.
 
PRODUCTION AND DRILLING ACTIVITIES
 
     Of the 10 remaining Royalty Properties, 6 are currently producing. For a
discussion concerning the oil and gas production from such properties in 1996 as
well as information concerning drilling activities on such properties during
1996, see Item 7 -- Management's Discussion and Analysis of Financial Condition
and Results of Operations beginning on page 28 and Note 10 -- Supplementary
Proved Oil and Gas Reserve Information.
 
                                       19
<PAGE>   22
 
OPERATING AGREEMENTS
 
     All of the remaining Royalty Properties are operated by oil and gas
companies that are not affiliated with the Company. Costs attributable to the
Royalty Properties generally will be computed based on the costs charged to the
Working Interest Owner's account under the terms of existing joint operating
agreements.
 
     Besides general provisions for proposing, conducting and sharing costs for
joint operations on the Royalty Properties, the existing operating agreements
contain provisions which can significantly affect the amount of capital and
operating expenditures and vary the receipt of revenues from the sale of
production. For example, the "non-consent" provisions of the operating
agreements allow other joint interest owners to propose the drilling of wells
and thereby require the Working Interest Owner to elect either to pay its share
of the cost of drilling such wells or suffer a "non-consent" penalty. The
particulars of non-consent penalties on the Royalty Properties vary somewhat
between operating agreements, but generally require the forfeiture to the
participating parties of a significant interest if the party elects not to
participate in the drilling of certain exploratory wells. If a party elects not
to participate in a development well on any of the Royalty Properties (other
than Vermilion Block 21/22 and West Cameron Block 65), that party's right to
receive a share of production from such development well is suspended until such
time as the participating parties have recovered an amount ranging from
approximately 400 percent to approximately 600 percent of the cost of drilling,
testing, completing and equipping the development well. With respect to
Vermilion Block 21/22 and West Cameron Block 65, the non-consenting party must
assign all its working interest in the previously designated development area,
subject to retention by that party of its interest in wells previously drilled
in such area and an overriding royalty interest in all subsequent wells drilled
in such area. The loss of revenues from any failure by the Working Interest
Owner to participate in a development well would reduce the aggregate proceeds
from the Royalty in the event such development well produced in paying
quantities in excess of the cost of drilling, testing, completing and equipping
such well. Neither the Partnership nor the Trustee is entitled to compel the
Working Interest Owner to participate in any operation on a Royalty Property if
the Working Interest Owner makes a "non-consent" election with respect thereto.
 
     The Working Interest Owner may choose to conduct exploration and
development operations on one or more of the Royalty Properties without the
participation of some, or all, of the other joint interest owners by assuming
the obligations of non-consenting parties. If the Working Interest Owner elects
to assume a share of the costs associated with any non-consenting party's
interest, such costs and the production, if any, attributable to the assumption
of such interest will not be taken into account in the computation of the Net
Proceeds.
 
     The receipt of revenues from the sale of gas production could be delayed
for extended periods of time by gas balancing arrangements which allow other
joint interest owners to take gas production in excess of their ownership
percentage if the Working Interest Owner is unable to take all or a part of its
share of production. On the other hand, if the Working Interest Owner takes gas
production in excess of its ownership percentage, the revenues attributable to
the excess production will not be included in Gross Proceeds except to the
extent such excess is offset by prior or subsequent deficits created after
October 1, 1983 by the Working Interest Owner taking less than its ownership
percentage share of gas production. If a source of gas supply depletes before
the Working Interest Owner has balanced all deficits created after October 1,
1983 with excess production volumes, the Working Interest Owner will be entitled
to receive a cash settlement for such deficits from those joint interest owners
with excess production totals. All such settlement receipts will be included in
Gross Proceeds. See "Reserves" above.
 
                                       20
<PAGE>   23
 
SALES CONTRACTS AND PRICES
 
     Oil production from the Royalty Properties is sold under short-term
contracts at current market prices. Oil prices received by the Working Interest
Owner have fluctuated widely. The average oil price that the Working Interest
Owner received for crude oil sales during 1996 was 11 percent higher than the
average price received during 1995. Oil prices can be expected to continue to
exhibit volatility as a result of such factors as the unstable situation in the
Middle East, future actions of OPEC and future changes in worldwide economic
conditions.
 
     The Working Interest Owner currently sells gas at spot market prices from
blocks that were previously subject to long-term contracts with Transco, but
which contracts were terminated by the Working Interest Owner at the end of 1987
and the beginning of 1988 pursuant to the provisions of such contracts.
 
REGULATION
 
     The production, sale and transportation of oil and gas from the Royalty
Properties are subject to various forms of regulation by federal and state
authorities, and are affected from time to time in varying degrees by political
developments.
 
     Energy Regulation. The Working Interest Owner is subject to regulation by
the FERC with respect to various aspects of its natural gas operations under the
Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act (NGPA). The Natural
Gas Wellhead Decontrol Act of 1989 amended both the price and non-price control
provisions of the NGPA for the purpose of providing complete decontrol of first
sales of natural gas by January 1, 1993. Consequently, the Working Interest
Owner believes the Trust's gas may be sold at market prices, subject to
applicable contract provisions.
 
     Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and
636-C (Order No. 636), which require interstate pipelines to provide
transportation separate, or "unbundled", from the pipelines' sales of gas. Also,
Order No. 636 requires pipelines to provide open-access transportation on a
basis that is equal for all gas supplies. Although Order No. 636 does not
directly regulate the Working Interest Owner's activities, the FERC has stated
that Order No. 636 is intended to foster increased competition within all phases
of the natural gas industry. Although Order No. 636 could provide the Working
Interest Owner with additional market access and more fairly applied
transportation service rates, Order No. 636 could also subject the Working
Interest Owner to more restrictive pipeline imbalance tolerances and greater
penalties for violation of those tolerances. Order No. 636 and subsequent FERC
orders issued in individual pipeline restructuring proceedings have been the
subject of appeals, the results of which have generally supported the FERC's
open-access policy. Last year, the United States Court of Appeals for the
District of Columbia Circuit largely upheld Order No. 636. Because further
review of certain of these orders is still possible and other appeals remain
pending, it is difficult to predict the ultimate impact of the orders on the
Working Interest Owner's activities.
 
     The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in which
interstate pipelines release capacity under Order No. 636 and, more recently,
the price which shippers can charge for their released capacity. In addition, in
1995, FERC issued a policy statement on how interstate natural gas pipelines can
recover the costs of new pipeline facilities. In January 1996, the FERC issued a
policy statement and a request for comments concerning alternatives to its
traditional cost-of-service ratemaking methodology. A number of pipelines have
obtained FERC authorization to charge negotiated rates as one such alternative.
While any additional FERC action on these matters would affect the Working
Interest Owner only indirectly, these policy statements and proposed rule
changes are intended to further enhance competition in natural gas markets. The
Working Interest Owner cannot predict what action the FERC will take on these
matters, nor can it predict whether the FERC's actions will achieve its stated
goal of increasing competition in natural gas markets. However, the Working
Interest Owner
 
                                       21
<PAGE>   24
 
does not believe that it will be treated materially different than other natural
gas producers and marketers with which it competes.
 
     Commencing in October 1993, the FERC issued a series of rules (Order Nos.
561 and 561-A) establishing an indexing system under which oil pipelines will be
able to change their transportation rates, subject to prescribed ceiling levels.
The indexing system, which allows, or may require, pipelines to make rate
changes to track changes in the Producer Price Index for Finished Goods, minus
one percent, became effective January 1, 1995. The Working Interest Owner is not
able at this time to predict the effects of Order Nos. 561 and 561-A, if any, on
the transportation costs associated with oil production from the interests
burdened by the Royalty, or the effect of such rules on the Trust.
 
     The Outer Continental Shelf Lands Act (OCSLA) requires that all pipelines
operating on or across the Outer Continental Shelf (OCS) provide open-access,
non-discriminatory service. Although the FERC has opted not to impose the
regulations of Order No. 509, which implements the OCSLA, on gatherers and other
non-jurisdictional entities, the FERC has retained the authority to exercise
jurisdiction over those entities if necessary to permit non-discriminatory
access to service on the OCS.
 
     Operations the Working Interest Owner conducts relating to the Royalty
Properties are on federal oil and gas leases, which the Minerals Management
Service (MMS) administers. The MMS issues such leases through competitive
bidding. These leases contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the OCSLA (which
are subject to change by the MMS). For offshore operations, lessees must obtain
MMS approval for exploration plans and development and production plans prior to
the commencement of such operations. In addition to permits required from other
agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has promulgated regulations
requiring offshore production facilities located on the OCS to meet stringent
engineering and construction specifications. The MMS has promulgated other
regulations governing the plugging and abandonment of wells located offshore and
the removal of all production facilities. To cover the various obligations of
lessees on the OCS, the MMS generally requires that lessees post substantial
bonds or other acceptable assurances that such obligations will be met. The cost
of such bonds or other surety can be substantial and there is no assurance that
the Working Interest Owner can obtain bonds or other surety in all cases.
Additional financial responsibility requirements may be imposed under the Oil
Pollution Act of 1990, as discussed under "Environmental Regulation."
 
     Under certain circumstances, the MMS may require any Working Interest Owner
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially and adversely affect the Working Interest
Owner's financial condition and operations. In addition, the MMS is conducting
an inquiry into certain contract agreements from which producers on MMS leases
have received settlement proceeds that are royalty bearing and the extent to
which producers have paid the appropriate royalties on these proceeds. The
Working Interest Owner believes that this inquiry will not have a material
impact on its financial condition, liquidity or results of operations.
 
     The MMS has issued a notice of proposed rulemaking in which it proposes to
amend its regulations governing the calculation of royalties and the valuation
of natural gas produced from federal leases. The principle feature in the
amendments, as proposed, would establish an alternative market-index based
method to calculate royalties on certain natural gas production sold to
affiliates or pursuant to non-arm's length sales contracts. The MMS has proposed
this rulemaking to facilitate royalty valuation in light of changes in the gas
marketing environment. The Working Interest Owner cannot predict what action the
MMS will take on this matter, nor can it predict at this stage of the rulemaking
proceeding how the Working Interest Owner might be affected by this amendment to
the MMS' regulations.
 
     The MMS has also issued a notice of proposed rulemaking in which it
proposes to amend its regulations governing the calculation of royalties and the
valuation of crude oil produced from federal leases. This proposed rule would
modify the valuation procedures for both arm's length and non-arm's
 
                                       22
<PAGE>   25
 
length crude oil transactions to decrease reliance on oil posted prices and
assign a value to crude oil that better reflects market value, establish a new
MMS form for collecting value differential data, and amend the valuation
procedure for the sale of federal royalty oil. The Working Interest Owner cannot
predict what action the MMS will take on this matter, nor can it predict at this
stage of the rulemaking proceeding how the Working Interest Owner might be
affected by this amendment to the MMS' regulations.
 
     From 1986 through 1992, the Working Interest Owner entered into several gas
contract settlements with a gas purchaser related to the Royalty Properties
which involved payments of cash by the gas purchaser to the Working Interest
Owner. The Working Interest Owner included in Gross Proceeds the payments
received in connection with these settlements, net of amounts retained in a
suspense account representing settlement proceeds that were subject to possible
royalty obligations to the MMS. In December 1994, the Working Interest Owner
entered into an agreement with the MMS relating to these gas contract
settlements, resulting in a payment by the Working Interest Owner to the MMS.
After the settlement, approximately $4 million of the funds initially retained
for possible royalty obligations remained. The Working Interest Owner informed
the Trustee that it anticipated expenditures for the development operations on
the Royalty Properties in excess of $4 million and, accordingly, proposed to
retain the funds remaining in the suspense account for use as payments of these
anticipated expenditures, as sufficient funds may not be otherwise available.
The Trustee and the Working Interest Owner evaluated the legal, tax and other
issues relating to retaining such amounts for use in the exploratory and
development operations on the Royalty Properties and concluded that the funds
should be paid to the Trust. Such funds, including interest, were included in
the April 1995 Net Proceeds as a special payment resulting in a distribution of
$0.28794 per Unit.
 
     Additional proposals and proceedings that might affect the natural gas
industry are considered from time-to-time by Congress, the FERC, state
regulatory bodies, and the courts. The Working Interest Owner cannot predict
when or if any such proposals might become effective, or their effect, if any,
on the Trust. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.
 
     Environmental Regulation. The Working Interest Owner's oil and gas
activities on the Royalty Properties are subject to existing federal, state and
local laws and regulations relating to health, safety, environmental quality and
pollution control. The Working Interest Owner has advised the Trustee that it
believes that its operations and facilities are in general compliance with
applicable health, safety, and environmental laws and regulations. Events in
recent years have, however, heightened environmental concerns about the oil and
gas industry generally, and about offshore operations in particular. As a
consequence, offshore oil and gas leases are subject to extensive governmental
regulation, including regulations that may in certain circumstances impose
absolute liability upon lessees for cost of removal of pollution and for
pollution damages resulting from their operations, and that may require lessees
to pay penalties, or even to suspend or cease operations in the affected areas.
Although the Working Interest Owner has advised the Trustee that current
environmental regulation has not had a material adverse effect on the Working
Interest Owner's present method of operations, the impact of changes in
environmental laws, such as stricter environmental regulation and enforcement
policies, cannot be predicted at this time.
 
     The Oil Pollution Act of 1990 (OPA) and regulations promulgated pursuant
thereto impose a variety of obligations on "responsible parties" with respect to
the prevention of oil spills and liability for damages resulting from such
spills. A "responsible party" includes the owner or operator of a facility or
vessel. For offshore facilities, the responsible party is the lessee or
permittee or holder of a right of use and easement (granted under applicable
state law or OCSLA) of the area in which the offshore facility is located. The
OPA assigns liability to each responsible party for oil removal costs and a
variety of public and private damages, including natural resource damages. While
liability limits apply in some circumstances, a responsible party for an Outer
Continental Shelf facility must pay all spill removal costs incurred by a
federal, state or local government. The OPA establishes a liability
 
                                       23
<PAGE>   26
 
limit (subject to indexing) for offshore facilities of all removal costs plus
$75,000,000. A party cannot take advantage of liability limits if the spill was
caused by gross negligence or willful misconduct or resulted from violation of a
federal safety, construction, or operating regulation. If the party fails to
report a spill or to cooperate fully in the cleanup, liability limits likewise
do not apply. Few defenses exist to the liability imposed by OPA.
 
     The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover a substantial portion of
environmental clean-up and restoration costs that could be incurred by
governmental entities in connection with an oil spill. Other requirements
imposed by the OPA include the preparation of an oil spill contingency plan. A
failure to comply with ongoing requirements or inadequate cooperation in a spill
event may subject a responsible party to civil or criminal enforcement action.
In short, the OPA places a burden on offshore lease holders to conduct safe
operations and take other measures to prevent oil spills; if one occurs, the OPA
then imposes liability for resulting damages.
 
     In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating on the
OCS. Specific design and operational standards may apply to OCS vessels, rigs,
platforms, vehicles and structures. Violations of environmental related lease
conditions or regulations issued pursuant to the OCSLA can result in substantial
civil and criminal penalties as well as potential court injunctions curtailing
operations and the cancellation of leases. Such enforcement liabilities can
result from either governmental prosecution or citizen initiated legal action.
 
     The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of person
that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site where the release occurred and companies that disposed or
arranged for disposal of hazardous substances found at the site. Persons who are
or were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances released into the environment and for damages to natural
resources, and it is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage allegedly caused
by the hazardous substances released into the environment.
 
     Over the last four years at least three courts have ruled that certain
waste products associated with the production of crude oil may be classified as
"hazardous substances" subject to regulation and liability under CERCLA,
depending on the characteristics of the waste products and circumstances under
which they were created. In addition, legislation has been proposed in Congress
from time to time that would reclassify certain oil and gas exploration and
production wastes as "hazardous wastes," which would make the reclassified
wastes subject to much more stringent handling, disposal and clean-up
requirements under the Resource Conservation and Recovery Act. Any
reclassification of oil and gas exploration and production wastes from
non-hazardous to hazardous could have a significant impact on the operating
costs of the Working Interest Owner, as well as the oil and gas industry in
general. Initiatives to further regulate the disposal of oil and gas wastes are
also pending in certain states, and these various initiatives could have a
similar impact on the Working Interest Owner.
 
TITLE TO PROPERTIES
 
     The Conveyance is subject to customary interests and burdens, to the terms
and provisions of the underlying leases, to liens and other provisions of
farmout, operating, pooling and unitization agreements and to minor
encumbrances, easements and restrictions. The Royalty Properties are also
subject to the OCSLA, the regulations promulgated thereunder and possibly
certain provisions of the laws of the adjacent states. The Conveyance contains a
special warranty of title in which the Company warranted title to the Royalty
against persons claiming by, through or under the Company, but not otherwise.
 
                                       24
<PAGE>   27
 
                       FEDERAL INCOME TAX CONSIDERATIONS
 
     All Unit holders are urged to consult their own tax advisors regarding the
effects of acquisition, ownership and disposition of Units on their personal tax
positions.
 
INTERNAL REVENUE SERVICE RULINGS
 
     The following information regarding FTX's private letter rulings has been
supplied to the Trustee by FTX. In connection with the creation of the Trust and
the distribution of Units to FTX's stockholders (the Distribution) FTX requested
and received favorable private letter rulings from the Internal Revenue Service
(Service) regarding certain tax matters. Among the principal rulings requested
and received were the following:
 
          1.  For Federal income tax purposes, the Trust and the Partnership
     will be classified as a trust and a partnership, respectively, and not as
     associations taxable as corporations.
 
          2.  For Federal income tax purposes, the Trust will be characterized
     as a "grantor" trust as to the Unit holders and their transferees.
 
          3.  For federal income tax purposes, the Distribution will be treated
     as a distribution of the Royalty by FTX to the stockholders, followed by
     the contribution of the Royalty by the stockholders to the Partnership in
     exchange for interests therein, followed in turn by the contribution by the
     stockholders of the interests in the Partnership to the Trust in exchange
     for the Units.
 
          4.  FTX will recognize no gain or loss upon the transfer of the
     Royalty to its stockholders.
 
          5.  Each Unit holder will be entitled to deduct cost depletion with
     respect to its pro-rata interest in the Royalty computed with reference to
     the Unit holder's basis in the Units.
 
          6.  The Royalty will be considered an economic interest in oil and gas
     in place, and the Royalty will constitute a single property within the
     meaning of Section 614(a) of the Internal Revenue Code of 1954, as amended,
     as in effect when the transaction was consummated.
 
AREAS OF POTENTIAL TAX CONTROVERSY
 
     Information Return Filing Requirements. Under the Internal Revenue Code of
1986, as amended (the Code), any partner who sells or exchanges (other than
through a broker) an interest in a partnership holding "unrealized receivables"
within the meaning of Section 751 of the Code is required to notify the
partnership of such transaction in accordance with Treasury regulations. Any
such partner who fails to so notify the partnership may be subject to a $50
penalty for each such failure. Furthermore, on a sale or exchange of Units,
other than through a broker, the partnership is required to notify the Service
of any such sale or exchange (of which it has notice) of a partnership interest
after December 31, 1984, and to report the name and address of the transferee
and the transferor who were parties to such transaction, along with all other
information required by applicable Treasury Regulations. The partnership must
also provide this information to the transferor and the transferee. If the
partnership fails to furnish any such notification, it may be subjected to a
penalty of $50 per failure, up to an annual maximum of $100,000. Final Treasury
regulations exempt partnerships from the requirement to report any sales which
are reported by a broker on Form 1099-B.
 
     The Code provides that depletion deductions subject to recapture under
Section 1254 of the Code constitute "unrealized receivables" within the meaning
of Section 751 of the Code. Section 1254 of the Code provides that for property
placed in service by a taxpayer after December 31, 1986, depletion deductions
which reduce the adjusted basis of such property must be recaptured as ordinary
income upon a disposition of the property (to the extent gain is recognized on
such disposition). It is unclear whether this recapture provision applies to any
portion of the depletion claimed with respect to the Royalty (placed in service
in 1983 by the Partnership) in the case of Units acquired after December 31,
1986. The Service has not issued any regulations or other pronouncements to
indicate its interpreta-
 
                                       25
<PAGE>   28
 
tion of these recapture provisions as they might affect the transfer of
partnership interests. Accordingly, Unit holders disposing of Units acquired
after December 31, 1986 (other than through a broker) may be required to notify
the Trustee in writing of such disposition and provide the Trustee with the Unit
holder's name, address, taxpayer identification number and the date of the
disposition. Failure to so notify the Trustee may subject such a Unit holder, as
well as the Trust and the Partnership, to the above-described penalties. Without
notification from Unit holders, the Trust and Partnership cannot comply with
these reporting requirements because they have no other means of determining
which Units disposed of during the year were acquired by the transferring Unit
holder subsequent to December 31, 1986.
 
     Other Possible Penalties. An owner of a security who receives income in
respect of such interest must report the character and amount of such income,
for federal tax purposes, in a manner which is consistent with the federal tax
reports of the entity which was the source of the income. The consistency
requirement is deemed to be waived if the taxpayer files a statement with the
Service identifying the inconsistency. Because of the presence of "street name"
investors and the possible existence of transfer record inaccuracies, holders of
interests which are actively traded in the securities markets may encounter
situations in which it is difficult to fully and accurately comply with the
consistency requirement and other federal tax reporting requirements. Certain
penalties could be assessed against a taxpayer that fails to comply with such
requirements. Because of the complexity of the federal tax reporting
requirements applicable to trusts (such as the Trust) which own interests in
partnerships (such as the Partnership) and because all of the tax attributes of
the Royalty flow through the Partnership and the Trust to the Unit holders,
there is an increased likelihood that Unit holders will violate the consistency
requirement and other reporting requirements regarding their individual federal
income tax returns and the information returns of the Trust and the Partnership.
Any violations of the consistency requirements could lead to imposition of
certain penalties on the Unit holders or other adverse results. Furthermore, the
Trust or the Partnership might be subject to certain penalties in connection
with their furnishing of statements and information to Unit holders or the
government if such statements or information prove to be inaccurate due, for
example, to differences between the transfer agent's records and actual
ownership data. The Code provides reporting requirements designed to facilitate
the transfer of information between partnerships and trusts and owners of
interests therein held by nominees.
 
ITEM 2. PROPERTIES.
 
     Reference is made to Item 1 of this report.
 
ITEM 3.  LEGAL PROCEEDINGS.
 
     None.
 
ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS.
 
     No matters were submitted to a vote of Unit holders during the fourth
quarter of 1996.
 
                                       26
<PAGE>   29
 
                                    PART II
 
ITEM 5.  MARKET FOR THE REGISTRANT'S UNITS AND RELATED UNIT HOLDER MATTERS.
 
     Freeport-McMoRan Oil and Gas Royalty Trust Units are traded on the New York
Stock Exchange under the symbol "FMR". At March 7, 1997, 14,975,390 Units were
outstanding and held of record by 11,716 Unit holders.
 
     The high and low sales prices of the Units as reported on the New York
Stock Exchange and distributable cash per Unit for each quarterly period of 1995
and 1996 were:
 
<TABLE>
<CAPTION>
                                                               UNITS OF
                                                          BENEFICIAL INTEREST
                                                         ---------------------     DISTRIBUTABLE
QUARTER                                                    HIGH         LOW        CASH PER UNIT
ENDED                                                    --------     --------     -------------
<S>                                                      <C>          <C>          <C>
Mar. 31, 1995..........................................   $5.00        $3.63            $     --
Jun. 30, 1995..........................................    4.88         3.63             0.30365
Sept. 30, 1995.........................................    6.25         4.50             0.00765
Dec. 31, 1995..........................................    5.50         3.63                  --
Mar. 31, 1996..........................................    4.75         3.50                  --
Jun. 30, 1996..........................................    4.00         2.38                  --
Sept. 30, 1996.........................................    3.00         1.38                  --
Dec. 31, 1996..........................................    3.63         2.50                  --
</TABLE>
 
     Distributable cash for any quarter is distributed to Unit holders in the
month following the close of the quarter.
 
     The Trust did not sell any unregistered securities in 1996.
 
ITEM 6.  SELECTED FINANCIAL DATA.
 
     The following table sets forth in summary form selected financial data
regarding the Trust. Such information should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Financial Statements and the notes thereto included
elsewhere herein. Reference is also made to Item 1 of this Form 10-K.
 
<TABLE>
<CAPTION>
                                                 YEARS ENDED DECEMBER 31,
                              ---------------------------------------------------------------
                                 1996         1995         1994         1993         1992
                              ----------   ----------   ----------   ----------   -----------
<S>                           <C>          <C>          <C>          <C>          <C>
Royalty proceeds(1).........  $       --   $5,235,068   $2,551,586   $6,797,931   $16,760,989
Distributable cash(1).......          --    4,662,081           --    6,334,690    16,068,705
Distributable cash per
  Unit......................          --      0.31130           --      0.42295       1.07296
</TABLE>
 
<TABLE>
<CAPTION>
                                                       DECEMBER 31,
                              ---------------------------------------------------------------
                                 1996         1995         1994         1993         1992
                              ----------   ----------   ----------   ----------   -----------
<S>                           <C>          <C>          <C>          <C>          <C>
Cash........................  $1,983,571   $2,300,979   $1,977,583   $       --   $ 1,475,861
Total assets................   2,166,784    2,484,192    2,190,501      260,059     1,834,623
Distributions payable.......          --           --           --           --     1,475,861
Trust corpus................     183,213      183,213      212,918      260,059       358,762
</TABLE>
 
------------
 
(1) Includes $4.3 million, $2.4 million, $2.3 million, and $9.3 million in 1995
    through 1992, respectively, related to various gas contract settlements (See
    Note 6 -- Gas Contract Settlement).
 
     The Trust has not reported estimates of total proved net oil or gas
reserves to any federal authority or agency other than the SEC.
 
                                       27
<PAGE>   30
 
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
 
RESULTS OF OPERATIONS
 
     There were no cash distributions to Unit holders during 1996 and 1994. Cash
distributions to Unit holders totaled $4.7 million ($0.31130 per Unit) during
1995. No cash distributions were made during 1996 because of lower gas and oil
revenues and additional capital expenditures. Cash distributions during 1995
benefited from $4.3 million included in Gross Proceeds resulting from the
settlement of amounts owed the Minerals Management Service (MMS), discussed in
Note 6. During 1996, total costs exceeded Gross Proceeds by approximately $0.7
million, primarily because of the capital costs incurred to drill and evaluate
Breton Sound Block 55 and Vermilion Block 58. As a result, the Class A cost
carry-forward increased to $2.5 million net to the Trust as of December 31,
1996. Since mid-1995, trust administrative expenses have been paid from the
expense reserve. The calculation of distributable cash for each year follows:
 
<TABLE>
<CAPTION>
                                                     YEARS ENDED DECEMBER 31,
                                               -------------------------------------
                                                  1996         1995          1994
                                               ----------   -----------   ----------
<S>                                            <C>          <C>           <C>
Gross Proceeds(1)............................  $3,810,791   $ 9,807,120   $12,308,657
Total costs(2)...............................  (4,489,202)   (6,070,921)  (10,000,626)
Excess Class A cost carry-forward(3).........     678,411     2,086,366      529,902
                                               ----------   -----------   ----------
Net Proceeds.................................          --     5,822,565    2,837,933
Percentage attributable to Royalty...........        90.0%        90.0%        90.0%
                                               ----------   -----------   ----------
Amounts payable attributable to Royalty......          --     5,240,309    2,554,140
Percentage attributable to the Trust.........        99.9%        99.9%        99.9%
                                               ----------   -----------   ----------
Royalty Proceeds.............................          --     5,235,068    2,551,586
Trust administrative expenses................    (398,134)     (369,101)    (472,944)
Trust administrative expense recovery(4).....          --            --     (153,257)
                                               ----------   -----------   ----------
                                                 (398,134)    4,865,967    1,925,385
Interest earned..............................      80,727       119,510       52,198
Reserve for future Trust expenses(5).........     317,407      (323,396)  (1,977,583)
                                               ----------   -----------   ----------
Distributable Cash...........................  $       --   $ 4,662,081   $       --
                                               ==========   ===========   ==========
</TABLE>
 
---------------
 
(1) Gross proceeds represent amounts received by the Working Interest Owner
    during the twelve month period ended November 30 of such year.
 
(2) Total costs represent amounts accrued by the Working Interest Owner during
    the twelve month period ended November 30 of such year. Includes interest to
    the Working Interest Owner of $207,662, $26,592 and $10,979, respectively.
 
(3) Represents Class A costs incurred in the applicable periods that remained
    outstanding as of the end of such period.
 
(4) Represents Trust administrative expenses incurred in a prior period and
    recovered in the current period.
 
(5) Represents the net amount withdrawn from (added to) the Trust administrative
    expense reserve during the respective period.
 
                                       28
<PAGE>   31
 
     Gross proceeds, which include gas and oil revenues, are calculated based on
amounts received by the Working Interest Owner. Operating information follows:
 
<TABLE>
<CAPTION>
                                                               YEARS ENDED DECEMBER 31,
                                                           --------------------------------
                                                             1996        1995        1994
                                                           --------    --------    --------
<S>                                                        <C>         <C>         <C>
Natural Gas
  Revenues (in millions).................................  $  2.4      $  3.5      $  7.0
  Sales volumes (in billion cubic feet)..................     1.0         1.8         2.8
  Average realization (per thousand cubic feet)..........  $ 2.42      $ 1.94      $ 2.46
Oil
  Revenues (in millions).................................  $  1.4      $  1.5      $  2.2
  Sales volumes (in thousands of barrels)................    74.0        88.7       145.8
  Average realization (per barrel).......................  $18.80      $16.96      $14.97
</TABLE>
 
     The decline in gas volumes over the three-year period is caused primarily
by the depletion of the Eugene Island Block 10 and Vermilion Block 310 fields in
1995 and the West Cameron Block 498 field and wells at West Delta Block 34 and
East Cameron Block 336 in 1994. The decrease in oil volumes is caused primarily
by the depletion at West Cameron Block 215. Additionally, oil and gas volumes
for 1996 were impacted by normal production declines. Revenues during 1996
benefited from an increase in average realizations reflecting the rise in
natural gas and oil market prices during the year. Gas volumes include make-up
of gas sold under balancing agreements totaling 0.1 bcf, 0.3 bcf and 0.7 bcf,
respectively.
 
     Costs consist of the following (in millions):
 
<TABLE>
<CAPTION>
                                                                   YEARS ENDED DECEMBER 31,
                                                              ----------------------------------
                                                                1996         1995         1994
                                                              --------     --------     --------
<S>                                                           <C>          <C>          <C>
Lease operating expenses....................................   $2.2         $2.4         $ 2.4
Exploration and development costs...........................    1.6          2.5           5.5
Abandonment costs withheld and other........................    0.7          1.2           2.1
                                                                ---          ---          ----
                                                               $4.5         $6.1         $10.0
                                                                ===          ===          ====
</TABLE>
 
     Lease operating expenses were consistent between years. Exploration and
development costs for 1996 consist of costs incurred to explore and develop
Breton Sound Block 55 and Vermilion Block 58. Exploration and development costs
in 1995 included the drilling of two exploratory wells at West Cameron Block
498, while 1994 costs consisted of the drilling of two exploratory wells at West
Cameron Block 498, one exploratory well at West Cameron Block 65 and drilling
and plugging and abandonment operations at West Delta Block 34. Abandonment
costs are accrued each year based on the estimate of costs required to abandon
the Trust's properties.
 
CAPITAL RESOURCES AND LIQUIDITY
 
     All revenues received by the Trust, net of Trust administrative expenses
and liabilities, are distributed to the Unit holders in accordance with
provisions of the Trust Indenture. As a result of the cumulative excess Class A
cost carry-forward of $2.5 million net to the Trust at December 31, 1996, the
additional development activities scheduled at West Cameron Block 498 and Breton
Sound Block 55 and the potential for exploratory drilling on other Royalty
Properties, the amount and timing of future distributions to Unit holders is
presently indeterminable. The cost carry-forward, with interest at the prime
rate, must be recouped from future Net Proceeds before any distributions may be
made to Unit holders.
 
     Drilling operations were completed on an exploratory well on Breton Sound
Block 55 during the second quarter of 1996. The well is currently being
completed and production is expected to commence during mid-1997. The Working
Interest Owner owns an 18.75% working interest in Breton Sound Block 55 and a
9.375% working interest in this well pursuant to a codevelopment agreement with
the owner of the adjacent block. Costs and ownership of production resulting
from this activity will be retroactively adjusted based upon the location of
reserves discovered following further development of the area. The Vermilion
Block 58 No. 10 well was drilled during 1996 and, based on the
 
                                       29
<PAGE>   32
 
results, the Working Interest Owner concluded that it would not pursue any
further development of this well.
 
     Exploratory drilling on West Cameron Block 498 began in June 1994 and
resulted in four successful wells to date which have been saved for future
development. Construction of the platforms and production facilities began in
January 1997 and the operator is currently finalizing the development plans for
the block. Production is expected to commence during the fourth quarter of 1997.
The Working Interest Owner owns a 23.08% working interest in this block.
 
     Additional exploration may be proposed by the operators of certain other
Royalty Properties. After analyzing each proposal, the Working Interest Owner
will determine whether or not to participate in additional exploratory
operations.
 
     Total exploration and development costs for 1997 are presently budgeted at
approximately $11.8 million for the Working Interest Owner, including the
development of West Cameron Block 498 and Breton Sound Block 55. This estimate
is derived from cost estimates provided by the operators of the Royalty
Properties and may vary from actual costs depending on the success of drilling,
particular circumstances encountered during drilling and many other factors
outside the control of the operator. These expenditures can be expected to
reduce and could further delay resumption of distributions to Unit holders.
 
     Estimated future abandonment costs, based on current laws and regulations,
are accrued over the life of the Trust's properties (Note 9). During the third
quarter of 1996, the Working Interest Owner assigned its interest in East
Cameron Block 336 to a co-owner, free and clear of the Royalty, subject to the
conditions contained in the agreement. The Working Interest Owner paid $0.2
million for abandonment costs to the co-owner and the co-owner assumed all
additional abandonment obligations under the lease. The completion of this
assignment resulted in a reduction of estimated future abandonment costs
totaling approximately $0.7 million, net to the Trust. As of December 31, 1996,
the estimated remaining aggregate abandonment costs to be incurred for all of
the Trust's properties totaled $11.8 million net to the Trust, of which $10.9
million has been withheld from distributions to Unit holders. Based on these
amounts, future distributions to Unit holders will be reduced by approximately
$0.06 per Unit over the remaining productive lives of the properties, subject to
future revisions of such costs because of changes in general and specific cost
levels, government regulations, operations and technology.
 
     From 1986 through 1992, the Working Interest Owner entered into several gas
contract settlements with a gas purchaser related to the Royalty Properties
which involved payments of cash by the gas purchaser to the Working Interest
Owner. The Working Interest Owner included in Gross Proceeds the payments
received in connection with these settlements, net of amounts retained in a
suspense account representing settlement proceeds that were subject to possible
royalty obligations to the MMS. In December 1994, the Working Interest Owner
entered into an agreement with the MMS relating to these gas contract
settlements, resulting in a payment by the Working Interest Owner. After the
settlement, approximately $4 million of the funds initially retained for
possible royalty obligations remained. The Working Interest Owner informed the
Trustee that it anticipated expenditures for the development operations on the
Royalty Properties in excess of $4 million and, accordingly, proposed to retain
the funds remaining in the suspense account for use as payments of these
anticipated expenditures, as sufficient funds may not be otherwise available.
The Trustee and the Working Interest Owner evaluated the legal, tax and other
issues relating to retaining such amounts for use in the exploratory and
development operations on the Royalty Properties and concluded that the funds
should be paid to the Trust. Such funds, including interest, were included in
the April 1995 Net Proceeds as a special payment resulting in a distribution of
$0.28794 per Unit.
 
     At certain times since late 1993, the Trust has been unable to pay its
ongoing administrative expenses. To permit the Trust to pay its administrative
expenses during the time the Trust incurs a Class A cost deficit, the Trustee,
in accordance with the Trust Indenture, established a $2.4 million
 
                                       30
<PAGE>   33
 
Trust administrative expense reserve to pay such expenses (see Note
7 -- Establishment of an Expense Reserve), of which $2.0 million remained at
December 31, 1996.
 
     The Trustee may sell or dispose of its interest in the Partnership, or
permit the Partnership to sell or dispose of all or any part of the Royalty,
only as authorized by a vote of Unit holders, upon termination of the Trust and
in certain other limited circumstances. However, the Trust is directed to effect
such a sale (without any such vote) if the Trust's cash receipts for each of
three successive years are less than $3 million. The Trustee must distribute the
net proceeds of such sale (after satisfaction of any outstanding liabilities) to
the Unit holders. There were no cash receipts to the Trust in 1996. In light of
the future development costs related to West Cameron Block 498 and Breton Sound
Block 55 and the unknown timing and extent of production from these fields, the
remaining abandonment costs to be withheld and the outstanding Class A cost
carry-forward which existed at December 31, 1996, Gross Proceeds generated by
the Royalty properties may be insufficient to generate Trust cash receipts over
$3 million during 1997 or 1998.
 
                                       31
<PAGE>   34
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
 
                   FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
 
             STATEMENTS OF ROYALTY PROCEEDS AND DISTRIBUTABLE CASH
 
<TABLE>
<CAPTION>
                                                            YEARS ENDED DECEMBER 31,
                                                     --------------------------------------
                                                        1996          1995          1994
                                                     ----------    ----------    ----------
<S>                                                  <C>           <C>           <C>
Royalty proceeds...................................  $       --    $5,235,068    $2,551,586
Trust administrative expenses......................    (398,134)     (369,101)     (626,201)
Interest income....................................      80,727       119,510        52,198
Reserve for future Trust expenses..................     317,407      (323,396)   (1,977,583)
                                                     ----------    ----------    ----------
Distributable cash.................................  $       --    $4,662,081    $       --
                                                     ==========    ==========    ==========
Distributable cash per Unit........................  $       --    $  0.31130    $       --
                                                     ==========    ==========    ==========
Units outstanding..................................  14,975,390    14,975,390    14,975,390
                                                     ==========    ==========    ==========
</TABLE>
 
               STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
 
<TABLE>
<CAPTION>
                                                                     DECEMBER 31,
                                                              ---------------------------
                                                                  1996           1995
                                                              ------------   ------------
<S>                                                           <C>            <C>
                           ASSETS
Cash........................................................  $  1,983,571   $  2,300,979
Net overriding royalty interest in oil and gas properties...   189,875,741    189,875,741
Less, adjustment to recorded cost of net overriding royalty
  interest in oil and gas properties........................   (25,431,543)   (25,431,543)
Less, accumulated amortization of net overriding royalty
  interest..................................................  (164,260,985)  (164,260,985)
                                                              ------------   ------------
Total assets................................................  $  2,166,784   $  2,484,192
                                                              ============   ============
 
                LIABILITIES AND TRUST CORPUS
 
Reserve for future Trust expenses...........................  $  1,983,571   $  2,300,979
Trust corpus (14,975,390 Units of Beneficial Interest
  authorized, issued and outstanding).......................       183,213        183,213
                                                              ------------   ------------
Total liabilities and trust corpus..........................  $  2,166,784   $  2,484,192
                                                              ============   ============
</TABLE>
 
                     STATEMENTS OF CHANGES IN TRUST CORPUS
 
<TABLE>
<CAPTION>
                                                            YEARS ENDED DECEMBER 31,
                                                     --------------------------------------
                                                       1996         1995           1994
                                                     --------    -----------    -----------
<S>                                                  <C>         <C>            <C>
Trust corpus, beginning of year....................  $183,213    $   212,918    $   260,059
Royalty proceeds and interest earned, net of trust
  administrative expenses and reserve for future
  Trust expenses...................................        --      4,662,081             --
Distributions payable to Unit holders..............        --     (4,662,081)            --
Amortization of net overriding royalty interest....        --        (29,705)       (47,141)
                                                     --------    -----------    -----------
Trust corpus, end of year..........................  $183,213    $   183,213    $   212,918
                                                     ========    ===========    ===========
</TABLE>
 
   The accompanying notes are an integral part of these financial statements.
 
                                       32
<PAGE>   35
 
                   FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
 
                         NOTES TO FINANCIAL STATEMENTS
 
1. THE TRUST
 
     Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created
effective September 30, 1983. On that date, Freeport-McMoRan Inc. (FTX)
transferred a net overriding royalty interest in certain offshore oil and gas
properties to a Partnership (Partnership) equal to 90 percent of the Net
Proceeds (as defined in the Conveyance referred to below) from FTX's working
interests in such properties and conveyed a 99.9 percent general partnership
interest in the Partnership to the Trust. See "The Royalty Properties and the
Royalty -- Computation of the Royalty." Such net overriding royalty interest is
referred to herein as the "Royalty." The Overriding Royalty Conveyance which
created the Royalty is referred to herein as the "Conveyance." The Trust is
passive, with Texas Commerce Bank National Association as Trustee. The Trustee
has only such powers as are necessary for the collection and distribution of
revenues attributable to the Royalty, the payment of Trust liabilities and the
protection of Trust assets.
 
     The Trust Indenture provides generally that the Trust shall terminate upon
the first to occur of: (i) the sale of all the Trust's interest in the
Partnership, or the sale by the Partnership of all the assets of the Partnership
including the Royalty, or (ii) a decision to terminate the Trust by the
affirmative vote of Unit holders representing a majority of the Units. As noted
above, the Trustee is required to sell the Trust's interest in the Partnership,
or cause the Partnership to sell the Royalty, if the Trust's cash receipts for
each of three successive years are less than $3 million, thereby terminating the
Trust pursuant to (i) above. Upon the termination of the Trust under (ii) above,
the Trustee will sell the Royalty (or will cause the Partnership to sell all of
the assets of the Partnership). The Trustee will as promptly as possible
distribute the proceeds of any such sales according to the respective interests
and rights of the Unit holders after discharging all of the liabilities of the
Trust and, if necessary, setting up reserves in such amounts as the Trustee in
its discretion deems appropriate for contingent liabilities.
 
     There were no cash receipts to the Trust in 1996. In light of the future
development costs related to West Cameron Block 498 and Breton Sound Block 55
and the unknown timing and extent of production from these fields, the remaining
abandonment costs to be withheld and the outstanding Class A cost carry-forward
which existed at December 31, 1996, Gross Proceeds generated by the Royalty
properties may be insufficient to generate Trust cash receipts over $3 million
during 1997 or 1998.
 
2. THE ROYALTY
 
     Freeport-McMoRan Oil & Gas Company (FMOG), a division of FTX (the Working
Interest Owner), presently owns the oil and gas interests burdened by the
Royalty. The Conveyance provides that the owner of the interests burdened by the
Royalty will calculate and pay monthly to the Partnership an amount equal to 90
percent of the net proceeds for the preceding month. Net proceeds generally
consist of the excess of gross revenues received from the Royalty Properties
(Gross Proceeds), on a cash basis, over operating costs, capital expenditures
and other charges, on an accrual basis (Net Proceeds).
 
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
     The Trust's financial statements, which reflect the Trust's 99.9 percent
interest in the Partnership as though the Partnership did not exist, are
prepared on the cash basis of accounting for reporting revenues and expenses.
Therefore, revenues and expenses are recognized only as cash is received or paid
and the associated receivables, payables and accrued expenses are not reflected
in the accompanying financial statements. Under generally accepted accounting
principles, revenues and expenses would be recognized on an accrual basis.
 
                                       33
<PAGE>   36
 
                   FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
     The initial carrying amount of the Royalty represents FTX's net book value
applicable to the interest in the properties conveyed to the Trust on the date
of creation of the Trust. Amortization of the Royalty is charged directly
against trust corpus using the future net revenue method. This method provides
for calculating amortization by dividing the unamortized portion of the Royalty
by estimated future net revenues from proved reserves and applying the resulting
rate to the Trust's share of royalty proceeds.
 
     The carrying value of the Royalty is limited to the discounted present
value (at 10 percent) of estimated future net cash flows (as set forth in Note
10). Any excess carrying value is reduced and the adjustment is charged directly
against trust corpus. Neither the initial carrying value nor the remaining
unamortized balance at December 31, 1996 is necessarily indicative of the fair
market value of the Royalty held by the Trust.
 
     Because the Trust is a grantor trust which is not a taxable entity, no
income taxes are reported in the Trust's financial statements. The tax
consequences of owning Units are included in the federal, state and local income
tax returns of the individual Unit holders.
 
4. DISTRIBUTIONS TO UNIT HOLDERS
 
     As a result of the capital costs incurred during 1995 and 1996, a
cumulative excess Class A cost carry-forward of $2,485,811 existed as of
December 31, 1996. The cost carry-forward is subject to and includes interest
due the Working Interest Owner at the prime rate, which totaled $207,662 net to
the Trust for 1996. This excess Class A cost carry-forward must be recouped out
of future Net Proceeds before distributions to the Unit holders can be resumed.
 
5. GAS BALANCING ARRANGEMENTS
 
     As a result of past curtailments in gas takes by the principal purchaser of
production from the Royalty Properties, certain quantities of gas have been sold
by other parties with interests in the Royalty Properties pursuant to gas
balancing arrangements. Proceeds from gas produced from the Royalty Properties
but sold by other parties pursuant to such balancing arrangements
(underproduction) are not included in Adjusted Gross Proceeds for purposes of
calculating the Royalty. In the future, the Working Interest Owner will be
entitled to sell volumes equal to such underproduction or receive cash
settlements. On certain of the Royalty Properties, a cash settlement may be
required, depending on future results, due to the lack of sufficient remaining
reserves from which to makeup any underproduction. As of December 31, 1996, the
unrecovered quantity of gas sold by third parties pursuant to such gas balancing
arrangements since inception of the Trust through September 30, 1996 was
approximately 1.6 billion cubic feet (bcf), net to the Trust. Adjusted Gross
Proceeds will be increased in future periods when the Working Interest Owner is
compensated either through the sale of gas or through cash settlements, the
amount and timing of which is uncertain.
 
6. GAS CONTRACT SETTLEMENT
 
     From 1986 through 1992, the Working Interest Owner entered into several gas
contract settlements with a gas purchaser related to the Royalty Properties
which involved payments of cash by the gas purchaser to the Working Interest
Owner. The Working Interest Owner included in Gross Proceeds the payments
received in connection with these settlements, net of amounts retained in a
suspense account representing settlement proceeds that were subject to possible
royalty obligations to the Minerals Management Service (the MMS). In December
1994, the Working Interest Owner entered into an agreement with the MMS relating
to these gas contract settlements, resulting in a payment by the Working
Interest Owner. After the settlement, approximately $4 million of the funds
initially retained for possible royalty obligations remained. The Working
Interest Owner informed the
 
                                       34
<PAGE>   37
 
                   FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
Trustee that it anticipated expenditures for the development operations on the
Royalty Properties in excess of $4 million and, accordingly, proposed to retain
the funds remaining in the suspense account for use as payments of these
anticipated expenditures, as sufficient funds may not be otherwise available.
The Trustee and the Working Interest Owner evaluated the legal, tax and other
issues relating to retaining such amounts for use in the exploratory and
development operations on the Royalty Properties and concluded that the funds
should be paid to the Trust. Such funds, including interest, were included in
the April 1995 Net Proceeds as a special payment resulting in a distribution of
$0.28794 per Unit.
 
7. ESTABLISHMENT OF AN EXPENSE RESERVE
 
     Because of the decline in Royalty income, at certain times since late 1993
the Trust has been unable to pay its ongoing administrative expenses. To permit
the Trust to pay its routine administrative expenses during the time the Trust
incurs a Class A cost deficit, the Trustee, in accordance with the Trust
Indenture, established an expense reserve of $2.4 million of which $1,983,571
remained as of December 31, 1996. Because of the cumulative excess Class A cost
carry-forward, $317,407 was withdrawn from the expense reserve during 1996 to
pay Trust administrative expenses. There will be tax consequences to the Unit
holders for such reserve as described in Note 8 below.
 
     The funding for this reserve is deposited with Texas Commerce Bank and
invested in Texas Commerce Bank collateralized certificates of deposit. The
average interest rate earned on these funds was 3.7 percent for 1996, 3.7
percent for 1995 and 2.8 percent for 1994.
 
8. FEDERAL INCOME TAX MATTERS
 
     Unit holders will be required to report taxable income for Royalty income
received by the Trust and deposited to the expense reserve even if no
distributions were received by the Unit holders. The expense reserve established
for Trust administrative expenses described in Note 7 above, however, gives rise
to tax deductions as additional administrative expenses are incurred and paid
with funds deposited in the reserve.
 
9. RESERVE FOR FUTURE ESTIMATED ABANDONMENT COSTS
 
     Estimated future abandonment costs, based on current laws and regulations,
are accrued over the life of the Trust's properties. During the third quarter of
1996, the Working Interest Owner assigned its interest in East Cameron Block 336
to a co-owner, free and clear of the Royalty, subject to the conditions
contained in the agreement. The Working Interest Owner paid $0.2 million for
abandonment costs to the co-owner and the co-owner assumed all additional
abandonment obligations under the lease. The completion of this assignment
resulted in a reduction of estimated future abandonment costs totaling
approximately $0.7 million, net to the Trust. As of December 31, 1996, the
estimated remaining aggregate abandonment costs to be incurred for all of the
Trust's properties totaled $11.8 million net to the Trust, of which $10.9
million has been withheld from distributions to Unit holders. Estimated future
abandonment costs are by their nature imprecise and can be expected to be
revised over time because of changes in general and specific cost levels,
government regulations, operations and technology. Any adjustments to estimated
abandonment costs or variances to actual costs will reduce or increase future
distributable cash accordingly.
 
10. SUPPLEMENTARY PROVED OIL AND GAS RESERVE INFORMATION (UNAUDITED)
 
     Pursuant to the Financial Accounting Standards Board's (FASB) disclosure
standards for oil and gas producing activities, the Trust is required to include
as supplementary information estimates of quantities of proved oil and gas
reserves attributable to the Trust. Since the Royalty is a net profits
 
                                       35
<PAGE>   38
 
                   FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
interest, the Partnership does not own and is not entitled to receive any
specific volume of reserves. Reserves attributable to the Partnership have been
estimated based on projections of reserves and future net cash flows
attributable to the combined interests of the Working Interest Owner and the
Partnership, and a formula based upon estimates of future net cash flows. As a
result of estimating reserve volumes by using a formula based upon estimates of
future net cash flows, such reserves are necessarily affected by changes in
various economic factors including prices, costs and the level and timing of
capital expenditures on the properties. Therefore, the reserve volume estimates
set forth below are hypothetical and are not comparable to estimates of reserves
attributable to a working interest.
 
     The reserve volume and cash flow amounts set forth below are for the
interest in the Royalty attributable to the Trust, based on the Trust's 99.9
percent interest in the Partnership. Estimates of proved oil and gas reserves
attributable to the Trust's interest are based on reports of Ryder Scott Company
Petroleum Engineers (Ryder Scott). In preparing its estimates, Ryder Scott did
not take into account (a) revenues received after November 30 attributable to
production during the fourth quarter of the respective year, (b) as of December
31, 1996, 1995 and 1994, approximately 1.6 bcf, 1.7 bcf, and 2.0 bcf sold by
other parties pursuant to certain gas balancing arrangements and (c) an excess
Class A cost carry-forward of $2.5 million, $1.9 million and $0.5 million at
December 31, 1996, 1995 and 1994, respectively. For purposes of the reserve
volume and cash flow amounts set forth below, the Trustee adjusted the estimates
of Ryder Scott to take into account the foregoing factors, based on calculations
supplied by the Working Interest Owner. In accordance with the requirements of
the FASB, the reserve disclosures below were calculated using year-end oil and
gas prices being received and current operating and abandonment cost levels.
 
     As discussed in Note 9, based on escalated estimates of costs to abandon
the Trust properties, approximately $0.9 million remains to be deducted from
future distributions to cover abandonment costs. For purposes of the reserve
volume and cash flow amount set forth below, Ryder Scott has not considered
these future deductions based on escalated estimates, nor has the Trustee
adjusted Ryder Scott's estimates, as the Trust is required to present the
supplementary information assuming no escalation in costs.
 
     Proved Oil and Gas Reserves. The following table sets forth estimates of
the interest attributable to the Trust in proved oil and gas reserves and
changes in such estimates. Oil, including crude oil, condensate and natural gas
liquids, is stated in thousands of barrels; gas is stated in millions of cubic
feet.
 
<TABLE>
<CAPTION>
                                                1996                  1995                  1994
                                         -------------------   -------------------   -------------------
                                           OIL        GAS        OIL        GAS        OIL        GAS
                                         --------   --------   --------   --------   --------   --------
<S>                                      <C>        <C>        <C>        <C>        <C>        <C>
Proved reserves, beginning of year.....    603        5,241       79        3,243       116       8,258
  Changes in prices and other revisions
     to previous estimates(1)..........    220        1,788      (24)         430        (3)     (4,464)
  Extensions and discoveries(2)........     47          360      616        2,950         3         160
  Production...........................    (66)        (899)     (68)      (1,382)      (37)       (711)
                                           ---       ------      ---       ------      ----     -------
Proved reserves, end of year...........    804        6,490      603        5,241        79       3,243
                                           ===       ======      ===       ======      ====     =======
</TABLE>
 
------------
 
(1) Estimates of proved reserves are subject to possible change, either upward
    or downward, as additional information becomes available. Because the
    Royalty is a net profits interest and reserve quantities are estimated
    pursuant to a formula based in part on the estimated future net cash flows,
    factors other than changes in estimates of gross quantities of reserves
    (such as changes in prices and costs) can result in changes in estimates of
    reserve quantities attributable to the Trust. The positive revisions in 1996
    primarily reflect the impact of higher oil and gas prices.
 
(2) Includes reserves related to West Cameron Block 215 and the Breton Sound
    Block 55 No. 4 well in 1996, West Cameron Block 498 in 1995 and the West
    Cameron Block 65 No. 7 well in 1994.
 
                                       36
<PAGE>   39
 
                   FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
 
                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
 
     Standardized Measure of Discounted Future Net Cash Flows from Proved Oil
and Gas Reserves. The supplementary information presented below reflects
estimates of discounted future net cash flows from proved oil and gas reserves
and changes in such estimates prepared in accordance with requirements
prescribed by the FASB.
 
     Future cash flows are determined by multiplying the estimated future net
cash flows attributable to the combined interests of the Partnership and the
Working Interest Owner by a factor of 90 percent (the Partnership's Royalty).
The resulting amount is then multiplied by a factor of 99.9 percent reflecting
the Trust's interest in the Partnership. Future net cash flows also include the
proceeds to be received from underdelivered gas (see Note 5 above).
 
     It is emphasized that this supplementary information represents estimates
which may be imprecise, and extreme caution should accompany its use and
interpretation. The estimates were based on various assumptions, many of which
are subject to uncertainties, and therefore, the estimates should not be
considered to be a prediction of actual amounts to be paid to the Trustee.
 
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED OIL AND GAS
RESERVES:
 
<TABLE>
<CAPTION>
                                                                DECEMBER 31,
                                                 ------------------------------------------
                                                     1996           1995           1994
                                                 ------------   ------------   ------------
<S>                                              <C>            <C>            <C>
Future cash flows..............................  $44,031,000    $21,753,000    $ 8,693,000
Discount for estimated timing of cash flows (10
  percent discount rate).......................  (18,834,000)    (9,457,000)    (1,624,000)
                                                 -----------    -----------    -----------
Standardized measure of discounted future net
  cash flows from proved oil and gas
  reserves.....................................  $25,197,000    $12,296,000    $ 7,069,000
                                                 ===========    ===========    ===========
</TABLE>
 
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM
PROVED OIL AND GAS RESERVES:
 
<TABLE>
<CAPTION>
                                                          YEARS ENDED DECEMBER 31,
                                                 ------------------------------------------
                                                     1996           1995           1994
                                                 ------------   ------------   ------------
<S>                                              <C>            <C>            <C>
Discounted future net cash flows,
  beginning of year............................  $12,296,000    $ 7,069,000    $ 26,143,000
  Royalty proceeds.............................           --     (5,235,000)     (2,552,000)
  Changes in prices and other revisions to
     previous estimates(1).....................    9,911,000        164,000     (19,594,000)
  Extensions and discoveries(2)................    1,760,000      9,591,000         458,000
  Accretion of discount........................    1,230,000        707,000       2,614,000
                                                 -----------    -----------    ------------
Discounted future net cash flows, end of
  year.........................................  $25,197,000    $12,296,000    $  7,069,000
                                                 ===========    ===========    ============
</TABLE>
 
------------
 
(1) 1995 includes $4.3 million related to the special payment (Note 6) and 1994
    includes the effect of unsuccessful attempts to complete the West Delta
    Block 34 No. 10 well.
 
(2) Includes increased reserves at West Cameron Block 215 and the addition of
    the Breton Sound Block 55 No. 4 well in 1996, the discounted future net cash
    flow related to West Cameron Block 498 in 1995 and the West Cameron Block 65
    No. 7 well in 1994.
 
                                       37
<PAGE>   40
 
                   FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
 
                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
 
To Texas Commerce Bank National Association (Trustee)
  and the Unit Holders of Freeport-McMoRan
  Oil and Gas Royalty Trust:
 
     We have audited the statements of assets, liabilities and trust corpus of
Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 1996 and 1995, and
the related statements of royalty proceeds and distributable cash, and changes
in trust corpus for each of the three years in the period ended December 31,
1996. These financial statements are the responsibility of the Trustee and the
General Partner of the Royalty Partnership. Our responsibility is to express an
opinion on these financial statements based on our audits.
 
     We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
 
     As discussed in Note 3, these financial statements were prepared on the
cash basis of accounting which is a comprehensive basis of accounting other than
generally accepted accounting principles.
 
     In our opinion, the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of
Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 1996 and 1995, and
the royalty proceeds and distributable cash, and changes in trust corpus for
each of the three years in the period ended December 31, 1996, on the cash basis
of accounting described in Note 3.
 
                                          ARTHUR ANDERSEN LLP
 
New Orleans, Louisiana,
March 7, 1997
 
                                       38
<PAGE>   41
 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE.
 
     None.
 
                                    PART III
 
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
 
     There are no directors or executive officers of the Registrant, and to the
Trustee's knowledge no person beneficially owns more than 5 percent of the
outstanding Units. The Trustee is a corporate trustee which may be removed by
the majority vote of the of the Unit holders .
 
ITEM 11. EXECUTIVE COMPENSATION.
 
     Not applicable.
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
 
     (a) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
 
        No person is known by the Trustee to own beneficially more than 5
        percent of the Units.
 
     (b) SECURITY OWNERSHIP OF MANAGEMENT
 
        Texas Commerce Bank National Association, as Trustee of the Trust, owns
        no Units. Texas Commerce Bank National Association in its individual
        capacity also owns no Units.
 
     (c) CHANGE IN CONTROL
 
        The Trust knows of no arrangements, including the pledge of Units of the
        Trust, the operation of which may at a subsequent date result in a
        change in control of the Trust.
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
 
     Texas Commerce Bank National Association, which also acts as Trustee of the
Trust, and its parent, Chase Manhattan Corporation, have banking relationships
with the Company.
 
                                       39
<PAGE>   42
 
                                    PART IV
 
ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
 
     (a)1. FINANCIAL STATEMENTS
 
     Reference is made to Item 8 of this Form 10-K.
 
     (a)2.  SCHEDULES
 
     Schedules have been omitted because they are not required, not applicable
or the information required has been included elsewhere herein.
 
     (a)3. EXHIBITS
 
<TABLE>
<CAPTION>
  EXHIBIT
    NO.
  -------
<C>          <C>  <S>                                                         
    4.1*      --  Overriding Royalty Conveyance from McMoRan-Freeport Oil
                  Company to McMoRan Oil & Gas Co. (attached as Annex I to
                  Exhibit 4.4).
    4.2*      --  Royalty Trust Indenture for Freeport-McMoRan Oil and Gas
                  Royalty Trust between Freeport-McMoRan Inc. ("FTX") and
                  First City National Bank of Houston, as Trustee.
    4.3*      --  First Amended and Restated Articles of General
                  Partnership of Freeport-McMoRan Oil and Gas Royalty
                  Partnership between McMoRan Offshore Management Co. and
                  First City National Bank of Houston, as Trustee.
    4.4*      --  Act of Assignment and Assumption and Mortgage from
                  McMoRan Oil & Gas Co. to FTX.
    4.5*      --  Act of Assignment and Assumption and Mortgage from FTX
                  to Freeport-McMoRan Oil and Gas Royalty Partnership (for
                  omitted attachments see Exhibit 4.4).
     27       --  Financial Data Schedule.
</TABLE>
 
------------
 
* Incorporated by reference to Exhibits of like designation to the registrant's
  Annual Report on Form 10-K for the period ended December 31, 1983.
 
(b) REPORTS ON FORM 8-K
 
     No reports on Form 8-K were filed by the registrant during the fourth
quarter of 1996.
 
                                       40
<PAGE>   43
 
                                   SIGNATURE
 
     PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
 
                                          FREEPORT-McMoRan OIL AND GAS
                                            ROYALTY TRUST
 
                                          By: TEXAS COMMERCE BANK
                                                NATIONAL ASSOCIATION, Trustee
 
                                          By:         /s/ PETE FOSTER
                                            ------------------------------------
                                                        Pete Foster
                                              Senior Vice President and Trust
                                                           Officer
 
March 27, 1997
 
     The Registrant, Freeport-McMoRan Oil and Gas Royalty Trust, has no
principal executive officer, principal financial officer, principal accounting
officer, board of directors or persons performing similar functions.
Accordingly, no additional signatures are required.
 
                                       41
<PAGE>   44
 
                               INDEX TO EXHIBITS
 
<TABLE>
<CAPTION>
  EXHIBIT
    NO.
  -------
<S>          <C>  <C>                                                         
    4.1*      --  Overriding Royalty Conveyance from McMoRan-Freeport Oil
                  Company to McMoRan Oil & Gas Co. (attached as Annex I to
                  Exhibit 4.4).

    4.2*      --  Royalty Trust Indenture for Freeport-McMoRan Oil and Gas
                  Royalty Trust between Freeport-McMoRan Inc. ("FTX") and
                  First City National Bank of Houston, as Trustee.

    4.3*      --  First Amended and Restated Articles of General
                  Partnership of Freeport-McMoRan Oil and Gas Royalty
                  Partnership between McMoRan Offshore Management Co. and
                  First City National Bank of Houston, as Trustee.

    4.4*      --  Act of Assignment and Assumption and Mortgage from
                  McMoRan Oil & Gas Co. to FTX.

    4.5*      --  Act of Assignment and Assumption and Mortgage from FTX
                  to Freeport-McMoRan Oil and Gas Royalty Partnership (for
                  omitted attachments see Exhibit 4.4).

     27       --  Financial Data Schedule.
</TABLE>
 
------------
 
* Incorporated by reference to Exhibits of like designation to the registrant's
  Annual Report on Form 10-K for the period ended December 31, 1983.