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                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                  FORM 10-K/A

[X]                ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000

[ ]              TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                          COMMISSION FILE NUMBER 1-8581

                   FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
             (Exact name of Registrant as Specified in Its Charter)

                 TEXAS                                           72-6108468
    (State or Other Jurisdiction of                           (I.R.S. Employer
     Incorporation or Organization)                          Identification No.)

    THE CHASE MANHATTAN BANK, TRUSTEE
          700 Lavaca 5th Floor
             Austin, Texas                                          77002
(Address of Principal Executive Offices)                         (Zip Code)

       Registrant's Telephone Number, Including Area Code: (512) 479-2562

           Securities Registered Pursuant to Section 12(b) of the Act:

                                                      NAME OF EACH EXCHANGE ON
            TITLE OF EACH CLASS                             WHICH REGISTERED

       Units of Beneficial Interest                       Over the Counter

           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. Yes [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 27, 2001 was approximately $1,347,785.10 based on the
closing price of the Units of $.0.09.

         As of March 27, 2001, 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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                                TABLE OF CONTENTS


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                                                       PART I

   ITEM 1.       Business.........................................................................................2
                 Background.......................................................................................2
                 Description Of The Trust.........................................................................4
                 Description Of The Units.........................................................................7
                 The Royalty Properties And The Royalty...........................................................9
                 Federal Income Tax Considerations...............................................................28
   ITEM 2.       Properties......................................................................................30
   ITEM 3.       Legal Proceedings...............................................................................30
   ITEM 4.       Submission of Matters to a Vote of Unit Holders.................................................30

                                                       PART II

   ITEM 5.       Market for the Registrant's Units and Related Unit Holder Matters...............................30
   ITEM 6.       Selected Financial Data.........................................................................31
   ITEM 7.       Management's Discussion and Analysis of Financial Condition and Results
                 of Operations...................................................................................31
   ITEM 7A.      Quantitative and Qualitative Disclosures about Market Risk......................................35
   ITEM 8.       Financial Statements and Supplementary Data.....................................................36
                 Statements of Royalty Proceeds and Distributable Cash: For the Years ended
                      December 31, 2000, 1999, and 1998..........................................................36
                 Statements of Assets, Liabilities and Trust Corpus: As of December 31, 2000
                      and 1999...................................................................................36
                 Statements of Changes in Trust Corpus:  For the Years ended December 31, 2000,
                      1999, and 1998.............................................................................36
                 Notes To Financial Statements...................................................................37
                 Report Of Independent Public Accountants........................................................42
   ITEM 9.       Changes in and Disagreements with Accountants on Accounting and
                 Financial Disclosure............................................................................43

                                                      PART III

   ITEM 10.      Directors and Executive Officers of the Registrant..............................................43
   ITEM 11.      Executive Compensation..........................................................................43
   ITEM 12.      Security Ownership of Certain Beneficial Owners and Management..................................43
   ITEM 13.      Certain Relationships and Related Transactions..................................................43

                                                       PART IV

   ITEM 14.      Exhibits, Financial Statement Schedules, and Reports on Form 8-K................................43
   Signature     ................................................................................................45
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                                     PART I

ITEM 1. BUSINESS.

                                   BACKGROUND

         Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created
effective September 30, 1983. On that date, Freeport-McMoRan Inc. (FTX)
transferred to a Partnership (the Partnership) a net overriding royalty interest
in certain offshore oil and gas properties 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. 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 The Chase Manhattan Bank 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. The Trust
Indenture originally stated that the Trust must also terminate if the amount of
cash per year received by the Trust for each of three successive years
commencing after December 31, 1990 is less than $3 million. The Trust's cash
receipts were less than $3 million in 1996, 1997 and 1998. However, at a special
meeting of the Unit holders held on March 12, 1999, the Unit holders approved a
shareholder proposal to amend the Trust Indenture to extend the life of the
Trust for at least two years. This extension expired on December 31, 2000, as
there were no payments in respect of the Royalty during 1999 and 2000.
Therefore, the Trust Indenture provides the Trustee must sell the Trust's
interest in the Partnership or cause the Partnership to sell the Royalty.
Pursuant to a shareholder proposal, the Trustee is working on proxy materials
and anticipates filing definitive proxy materials with a plan for distribution
of the Trust's assets.

         Early in December 2000, the Trustee was approached by representatives
of Roberson Oil Company and IMC Global, Inc. (IMC), the Working Interest Owner,
proposing a transaction whereby a to-be-formed corporation (NewCo) would
purchase the Trust assets and the working interest from IMC. Thereafter, NewCo
would conduct an exchange offer whereby Unit holders would be offered the
opportunity to exchange, on terms and conditions established by NewCo, their
Units in the Trust for shares in NewCo. The Trustee has received a shareholder
proposal that would amend the Trust Indenture to allow the transaction to
proceed if the proposal receives the requisite vote of Unitholders. The Trustee
is currently preparing proxy materials and a notice of a special meeting of the
Unit holders expected to be held in August or September of this year to
authorize the Trustee to conduct a sale of the Trust's Royalty for nominal
consideration in accordance with the plan described above. If a majority of the
Unit holders entitled to vote at that meeting in which a quorum is present vote
to authorize the Trustee to sell the Trust's assets to NewCo the Trustee will do
so. If the sale to NewCo is not approved, the Trustee will proceed to conduct an
auction of the Trust properties in accordance with the existing terms of the
Trust Indenture. Complete information concerning the vote will be provided to
the Unit holders in forthcoming proxy materials.


         o        Ryder Scott Company Petroleum Engineers conducted an
                  independent review of the oil and gas interest burdened by the
                  Royalty and prepared estimates, as of December 31, 2000, of
                  the discounted present value of future net revenues from
                  proved reserves attributable to the Royalty. The report of
                  Ryder Scott is set forth elsewhere in this report. The
                  estimates were prepared in accordance with SEC regulations,
                  which among other things require that estimated net revenues
                  be based on prices and costs as


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                  of December 31, 2000. Ryder Scott estimated that the net
                  present value (discounted at 10%) of proved reserves
                  attributable to the Royalty was $15.5 million and that the
                  undiscounted estimated future net revenues from proved
                  reserves were $18.4 million as of December 31, 2000, however,
                  the estimates do not take into account many additional factors
                  that impact the value of the Royalty, including the following:


         o        Pursuant to the Conveyance, the Working Interest Owner is
                  entitled to recoup certain costs before any payments are made
                  with respect to the Royalty. When these costs cannot be paid
                  out of current revenue, they are accrued and carried forward.
                  As of December 31, 2000, the accumulated cost carryforward was
                  approximately $19.8 million. The estimated discounted present
                  value of $15.5 million and the undiscounted estimated net
                  revenues of $18.4 million in the Ryder Scott report do not
                  take into account the cost carryforward.


         o        The Ryder Scott estimates took into account only those
                  reserves that were classified as proved reserve as of December
                  31, 2000, and only the estimated costs of developing and
                  producing those proved reserves. Thus, the estimates did not
                  take into account costs that may be incurred to discover,
                  develop or produce reserves not classified as proved as of
                  December 31, 2000, nor did they take into account future
                  revenues, if any, from such reserves.


         o        The weighted average prices used in the Ryder Scott report
                  were $23.56 per Bbl of oil and $5.83 per Mcf of gas. Gas
                  prices have declined substantially since December 31, 2000.

         o        Proceeds from gas produced but sold by other parties pursuant
                  to gas balancing arrangements are not included in estimated
                  future proceeds. As of December 31, 2000, the quantity of gas
                  sold by third parties under the gas balancing arrangements was
                  approximately .2 Bcf. Proceeds related to the underproduction
                  position could increase proceeds to the Trust or reduce the
                  cost carryforward in future periods, however, the amount and
                  timing of such proceeds are uncertain. In addition, other
                  factors, including the credit worthiness of the counterparties
                  should be considered in determining the probability and amount
                  of future proceeds. The Ryder Scott estimates did not include
                  proceeds that may be received with respect to the gas balance
                  arrangements.

         o        The Working Interest Owner has brought suit against a prior
                  gas purchaser, seeking reimbursement of excess royalty of a
                  portion of amounts paid to the Minerals Management Service.
                  The suit is in the early stages and no trial date has been
                  set. The amount of any recovery is presently indeterminable.
                  Furthermore, the Working Interest Owner may not be successful
                  in this suit, the result of which would be no recovery for the
                  Working Interest Owner. The Trust will not receive any
                  recovery as a result of this suit. However, a successful
                  outcome for the Working Interest Owner could result in
                  additional gross proceeds to the Working Interest Owner. This
                  would in turn reduce the cost carryforward or, if the recovery
                  were large enough, eliminate the cost carryforward and result
                  in the payment of royalties. The Ryder Scott estimates did not
                  include proceeds, if any, from this lawsuit.


         o        The reserve for future abandonment costs for the Trust's
                  properties totals $4.2 million. This amount is included in the
                  cost carryforward of $19.8 million, as of December 31, 2000.
                  Such costs are by their nature imprecise and can be expected
                  to be revised over time due to changes in general and specific
                  cost levels, government regulation, operations or technology.
                  The Ryder Scott estimates did not take into account any
                  changes in such costs.



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<PAGE>   5


         o        In December 1997, the Working Interest Owner entered into a
                  crude oil agreement with an oil pipeline company which
                  included an annual minimum delivery volume. Since the
                  agreement's inception, the Trust has been assessed a
                  deficiency payment ranging from $.5 million to $.7 million on
                  an annual basis. There are no assurances that the annual
                  minimum delivery volume will be met in the future. For further
                  information on this matter see the Ryder Scott report.


         Accordingly, the estimated discounted net present value of future net
         revenues should not be construed as the current market value of the
         estimated oil and gas reserves, since a market value determination
         would include these and other additional factors. The Ryder Scott
         report is included elsewhere in this report and includes additional
         information regarding the estimates.

                            DESCRIPTION OF THE TRUST

         Units of beneficial interest (the Units) in the Trust are traded on the
over the counter market under the trading symbol "FMOLS."

         The Units are not an interest in or an obligation of the Working
Interest Owner, IMC. The Units 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 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 incorporated by reference 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

         As described above, on September 30, 1983, pursuant to the terms of the
Overriding Royalty Conveyance (the Conveyance), FTX transferred to the
Partnership 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 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
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.



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         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. IMC
provides the staff and facilities to carry out the administrative duties for and
on behalf of ARPMC, and IMC 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 has not made any cash
distributions since 1995.

         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.

         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 $600,000 for 2001. The Trustee, in
accordance with the Trust Indenture, established an expense reserve to cover
Trust expenses as discussed in Note 6--Establishment of an Expense Reserve, of
which $615,459 remained as of December 31, 2000. The costs and expenses of the
Trust may vary 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 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



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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 Indenture states
that the Trustee must effect such a sale (without any such vote) because the
Trust has had no cash receipts from the Royalty for each of the past five years.
Depending on the outcome of the Unit holders' meeting described above and under
"Business--Background," the Trust assets will be sold in some manner in the near
future.

         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 Trust Indenture states that the Trustee may act in its discretion
and will be personally or individually liable only for fraud, gross negligence
or bad faith. It is possible that a court could find the Trustee liable under a
different standard than that set forth in the Trust Indenture. The Trust
Agreement states that 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. It is possible
that a court could find that the Trustee's ability to be indemnified will be
governed by a different standard from that set forth in the Trust Indenture. The
Trustee will not be entitled to indemnification from Unit holders.


TERMINATION OF THE TRUST

         The conditions precedent to termination of the Trust have occurred and
absence further changes to the Trust Indenture approved by the Unit holders, in
accordance with the terms of the Trust Indenture, and as may be approved by the
Trustee in its discretion, the Trustee will sell the assets of the Trust and
distribute any proceeds to the Unit holders.



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<PAGE>   8

                            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. As of December 31, 2000, a total of 14,975,390
Units are outstanding.

DISTRIBUTIONS AND INCOME COMPUTATIONS

         Each month the Trustee is required to determine the amount, if any,
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, if any, 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 if amounts are available for distribution. The
Trustee is required to distribute 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, any 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, any 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, and the Working Interest Owner
is entitled to go, and in the past has gone, "non-consent" with respect to
operations, in which case its participation will be significantly reduced. See
"Operating Agreements." The Working Interest Owner is free to transfer the
working interests (burdened by the Royalty) to third parties such as NewCo. In
certain cases the Working Interest Owner is permitted to farm out 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.



                                       7
<PAGE>   9

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 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
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



                                       8
<PAGE>   10

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.

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, or Louisiana 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 FTX 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



                                       9
<PAGE>   11

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.

GENERAL

         As of December 31, 2000, there were 14 gross productive oil wells and
14 gross productive gas wells on the 3 remaining Royalty Properties where the
Working Interest Owner retains a working interest.

         All Royalty Properties are operated under joint operating agreements by
other oil and gas companies other than the Working Interest Owner. 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 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 is reviewing all options relating to its ownership interest in the
remaining properties, including discussions with several Unit holders. 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, 2000, has been made by Ryder Scott Company L.P.,
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, 2000, 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 2000
attributable to sales of oil and gas produced in the fourth quarter of 2000,
volumes of natural gas sold by other parties pursuant to certain gas balancing
arrangements and the effect of the excess cost carryforward at December 31,
2000. Therefore, the amounts set forth in the letter are not 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,
2000. 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).



                                       10
<PAGE>   12

             [RYDER SCOTT COMPANY PETROLEUM CONSULTANTS LETTERHEAD]





                                 March 27, 2001



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

Gentlemen:

         At the request of IMC Global Inc. (IMC), successor to 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, 2000. 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
originally 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 IMC and the
successors and assigns of its oil and gas working interests to the extent the
context requires.

         All offshore leases currently 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 leases are hereinafter referred to as the "Subject
Properties." All other leases originally subject to the Royalty have either
expired, or the leasehold interest subject to the Royalty has been sold. The
Working Interest Owner has assured us that no leases other than those 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 2000 hydrocarbon
prices were used in the preparation of this report as required by SEC
guidelines; however, actual future prices may vary significantly from December
2000 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:



                                       11
<PAGE>   13

Freeport-McMoRan Oil and Gas Royalty Trust
March 27, 2001
Page 2


                                 SEC PARAMETERS
                      Estimated Net Reserve and Income Data
                Freeport-McMoRan Oil and Gas Royalty Partnership
                             As of December 31, 2000

<Table>
<Caption>
                                                         TOTAL
                                                         PROVED
                                                      ------------
<S>                                                   <C>

         Remaining Reserves
                 Oil/Condensate -- Barrels ......          291,058
                 Gas -- MMCF ....................            2,138

         Future Net Income (FNI) 2001 ...........     $  8,252,199
         2002 ...................................        3,467,325
         2003 ...................................        2,440,681
                                                      ------------
                 Sub-Total (2001-2003) ..........     $ 14,160,205
                 Remaining ......................        4,288,838
                                                      ------------
                      Total .....................     $ 18,449,043

         Discounted FNI @ 10% ...................     $ 15,541,586
         (Compounded Annually)
</Table>

         The amounts shown above are all attributable to proved developed
reserves.

         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 14.73 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.
A portion of the expenses at West Cameron Block 498 Field are associated with
oil transportation tariffs. The tariffs included in the expenses amount to a
total of $1,167,458 net to the combined interests of the Working Interest Owner
and Partnership for the oil produced from the West Cameron Block 498 Field. In
that regard, annual deductions were made to represent future deficiency payments
for which the Working Interest Owner or the Partnership may be liable in
accordance with Exhibit A of the Crude Oil Buy/Sell Agreement between Coastal
States Trading, Inc. and the Working Interest Owner for oil produced from the
West Cameron Block 498 field.



                                       12
<PAGE>   14

Freeport-McMoRan Oil and Gas Royalty Trust
March 27, 2001
Page 3



         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 has been accrued as of December 31, 2000
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 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, transportation
tariffs, 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




                                       13
<PAGE>   15

Freeport-McMoRan Oil and Gas Royalty Trust
March 27, 2001
Page 4



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

RESERVES INCLUDED IN THIS REPORT

         The proved reserves presented in this report comply with SEC
definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10
paragraph (a) defines proved reserves as follows:

PROVED OIL AND GAS RESERVES. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.

                  (i) Reservoirs are considered proved if economic producibility
         is supported by either actual production or conclusive formation test.
         The area of a reservoir considered proved includes:

                           (A) that portion delineated by drilling and defined
                  by gas-oil and/or oil-water contacts, if any; and

                           (B) the immediately adjoining portions not yet
                  drilled, but which can be reasonably judged as economically
                  productive on the basis of available geological and
                  engineering data. In the absence of information on fluid
                  contacts, the lowest known structural occurrence of
                  hydrocarbons controls the lower proved limit of the reservoir.

                  (ii) Reserves which can be produced economically through
         application of improved recovery techniques (such as fluid injection)
         are included in the "proved" classification when 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.

                  (iii) Estimates of proved reserves do not include the
         following-

                           (A) oil that may become available from known
                  reservoirs but is classified separately as "indicated
                  additional reserves";

                           (B) crude oil, natural gas, and natural gas liquids,
                  the recovery of which is subject to reasonable doubt because
                  of uncertainty as to geology, reservoir characteristics, or
                  economic factors;

                           (C) crude oil, natural gas, and natural gas liquids,
                  that may occur in undrilled prospects; and

                           (D) crude oil, natural gas and natural gas liquids,
                  that may be recovered from oil shales, coal, gilsonite and
                  other such sources.




                                       14
<PAGE>   16

Freeport-McMoRan Oil and Gas Royalty Trust
March 27, 2001
Page 5



PROVED DEVELOPED OIL AND GAS RESERVES. Proved developed oil and gas reserves are
reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary
recovery should be included as "proved developed reserves" only after testing
by a pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.

PROVED UNDEVELOPED RESERVES. Proved undeveloped oil and gas reserves are
reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for
recompletion. Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.

         Certain Staff Accounting Bulletins published subsequent to the
promulgation of Regulation S-X have dealt with matters relating to the
application of financial accounting and disclosure rules for oil and gas
producing activities. In particular, the following interpretations extracted
from Staff Accounting Bulletins set forth the Commission staff's view on
specific questions pertaining to proved oil and gas reserves.

         Economic producibility of estimated proved reserves can be supported to
the satisfaction of the Office of Engineering if geological and engineering data
demonstrate with reasonable certainty that those reserves can be recovered in
future years under existing economic and operating conditions. The relative
importance of the many pieces of geological and engineering data which should be
evaluated when classifying reserves cannot be identified in advance. In certain
instances, proved reserves may be assigned to reservoirs on the basis of a
combination of electrical and other type logs and core analyses which indicate
the reservoirs are analogous to similar reservoirs in the same field which are
producing or have demonstrated the ability to produce on a formation test.
(extracted from SAB-35)


         In determining whether "proved undeveloped reserves" encompass acreage
on which fluid injection (or other improved recovery technique) is contemplated,
is it appropriate to distinguish between (i) fluid injection used for pressure
maintenance during the early life of afield and (ii) fluid injection used to
effect secondary recovery when afield is in the late stages of depletion? ...
The Office of Engineering believes that the distinction identified in the above
question may be appropriate in a few limited circumstances, such as in the case
of certain fields in the North Sea. The staff will review estimates of proved
reserves attributable to fluid injection in the light of the strength of the
evidence presented by the registrant in support of a contention that enhanced
recovery will be achieved. (extracted from SAB-35)




                                       15
<PAGE>   17

Freeport-McMoRan Oil and Gas Royalty Trust
March 27, 2001
Page 6



         Companies should report reserves of natural gas liquids which are net
to their leasehold interest, i.e., that portion recovered in a processing plant
and allocated to the leasehold interest. It may be appropriate in the case of
natural gas liquids not clearly attributable to leasehold interests ownership to
follow instruction (b) of Item 2 (b) (3) of Regulation S-K and report such
reserves separately and describe the nature of the ownership. (extracted from
SAB-35)

         The staff believes that since coalbed methane gas can be recovered from
coal in its natural and original location, it should be included in proved
reserves, provided that it complies in all other respects with the definition of
proved oil and gas reserves as specified in Rule 4-10(a) (2) including the
requirement that methane production be economical at current prices, costs, (net
of the tax credit) and existing operating conditions. (extracted from SAB-85)

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 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.




                                       16

<PAGE>   18

Freeport-McMoRan Oil and Gas Royalty Trust
March 27, 2001
Page 7



HYDROCARBON PRICES

         The Working Interest Owner furnished us with prices in effect at
December 31, 2000 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, 2000
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 2000, 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, 20000
were not considered in this study.

GAS

         The Working Interest Owner has furnished us with gas prices in effect
at December 2000 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.

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 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 and
abandonment costs are based on authorizations for expenditure for the proposed
work, or on actual costs for similar projects.

         When applicable, the operating costs attributable to the Working
Interest Owner and the Partnership include a portion of general and
administrative costs allocated directly to the leases and wells under operating
agreements. No deduction was made for indirect costs such as loan repayments,
deficiency payments related to transportation agreements, interest expenses, and
exploration and development prepayments that are not charged directly to the
leases or wells.




                                       17
<PAGE>   19

Freeport-McMoRan Oil and Gas Royalty Trust
March 27, 2001
Page 8



GENERAL

         Tables 1 through 4 present summaries of estimated annual production and
income beginning January 1, 2001 for the total Partnership. Tables 5 through 12
present our annual projection of production and income for each individual
field.

         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 2000.

         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, L.P.


                                        /s/ FREDERICK W. EMMERICH
                                        ----------------------------------------
                                        Frederick W. Emmerich
                                        Petroleum Engineer
FWE/sw


Approved:

/s/ JOHN R. WARNER
--------------------------------------
John R. Warner, P.E.
Senior Vice President




                                       18
<PAGE>   20

                FREEPORT-MCMORAN OIL AND GAS ROYALTY PARTNERSHIP







                                    Estimated

                           Future Reserves and Income

                                Attributable to a

                         Net Overriding Royalty Interest

                           In Certain Offshore Leases





                                   (SEC Case)



                             As of December 31, 2000






                                       19
<PAGE>   21

         All of the discounted present value of future net cash flows
attributable to the Royalty estimated by Ryder Scott was accounted for by West
Cameron Block 498 and by West Delta 34.

         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.


         The Ryder Scott estimates were prepared on the basis of estimated
production and costs accrued through December 31, 2000. Thus, amounts received
by the Working Interest Owner after November 30,




                                       20
<PAGE>   22


2000 attributable to production during 2000 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 2000. The Working Interest Owner has estimated that if
Ryder Scott had taken into account the 2001 Gross Proceeds from 2000 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 $1.1
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 4 - 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
expected to be minimal and are estimated at approximately $.5 million, or for
the Partnership. Additionally, Ryder Scott did not take into account the cost
carryforward of $19.8 million net to the Trust, as of December 31, 2000, nor did
it take into account the oil transportation deficiency of $.5 million applicable
to 2000 production.


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 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




                                       21
<PAGE>   23


month, together with interest on such excess. This carryforward amount includes
the cost carryforward, which was $19.8 million to the Trust at December 31,
2000. 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 (referred to
as a cost-carryforward) 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.

         Although the Royalty is a limited liability interest that gives the
owner of the Royalty the 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, the amounts payable in respect of the Royalty are,
as explained above, measured by the net profits of the Working Interest Owner
attributable to the oil and gas properties burdened by the Royalty. Therefore,
costs incurred by the Working Interest Owner directly impact the Royalty
calculations. The cost-carryforward, which has existed for more than five years,
is the result of the fact that the costs included in the Royalty calculation
formula have exceeded Gross Proceeds during the period.




                                       22
<PAGE>   24

         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 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


         The amount of cash payable on account of the Royalty, and thus the
amount of cash available for distribution to Unit holders, depends upon future
sale of oil and gas and the prices received. The sale of crude oil on West
Cameron 498 depends not only on oil prices but also on transportation and
operating costs. In December 1997, the Working Interest Owner entered into a
crude oil agreement with an oil pipeline company to deliver on a daily basis
specified quantities of crude oil from West Cameron 498. Under the terms of the
agreement, the Working Interest Owner agreed to pay a transportation fee
calculated at a sliding monthly rate based upon the total average dally volumes
delivered from West Cameron 498 during the month. Should the annual minimum
delivery volume not be met, a deficiency payment is assessed by the pipeline.
During 2000, the Working Interest Owner did not deliver the minimum volume under
the agreement; therefore, in February 2001, the pipeline company billed the
Working Interest Owner approximately $.5 million for the 2000 deficiency. This
amount is not included in the cost carryforward of $19.8 million as of December
31, 2000. Based on 2001 projected production, the minimum delivery volumes will
not be met in 2001.


PRODUCTION AND DRILLING ACTIVITIES

         There are 3 remaining Royalty Properties, all of which are currently
producing. For a discussion concerning the oil and gas production from such
properties in 2000 as well as information concerning other activities on such
properties during 2000, see Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operations and Note 10-Supplementary Proved
Oil and Gas Reserve Information.

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



                                       23
<PAGE>   25

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, 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. 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.

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 2000 was 2.2 times higher than the
average price received during 1999 and 2.1 times higher than that during 1998.
Although current oil prices are up from year end prices, 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.



                                       24
<PAGE>   26

         The Working Interest Owner currently sells gas at spot market prices
from blocks that were previously subject to long-term contracts with
Transcontinental Gas Pipe Line Corporation, 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.


         In December 1997, the Working Interest Owner entered into a crude oil
agreement with an oil pipeline company to deliver on a daily basis specified
quantities of crude oil from West Cameron 498. Under the terms of the agreement,
the Working Interest Owner agreed to pay a transportation fee calculated at a
sliding monthly rate based upon the total average daily volumes delivered from
West Cameron 498 during the month. Should the annual minimum delivery volume not
be met, a deficiency payment is assessed by the pipeline. During 2000, the
Working Interest Owner did not deliver the minimum volume under the agreement;
therefore, in February 2001, the pipeline company billed the Working Interest
Owner approximately $.5 million for the 2000 deficiency. This amount will be
included in the cost carryforward in 2001. The minimum proved oil reserves to be
produced, based on Ryder Scott's reserve evaluation, net to the Working Interest
Owner, for 2001 will be $178,081, declining to $74,070 in 2002. Based on 2001
projected production the minimum delivery volumes will not be met in 2001.
However should production exceed the 2001 minimum, the Working Interest Owner is
entitled to receive transportation without pay up to the cumulative prior
undelivered volumes.


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. Sales of crude oil, condensate and gas liquids are
not currently regulated and are made at market prices. Prior to 1993, the sale
of certain categories of domestic natural gas by the Working Interest Owner was
subject to regulation 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 nonprice control provisions of the NGPA for the purpose of
providing complete decontrol of first sales of natural gas by January 1, 1993.
While sales of the Trust's gas can currently be made at uncontrolled market
prices, subject to applicable contract provisions, Congress could reenact price
controls in the future.

         The Trust's sales of natural gas are affected by the availability,
terms and cost of transportation. The price and terms for access to pipeline
transportation remain subject to extensive federal and state regulation. Several
major regulatory changes have been implemented by Congress and the FERC from
1985 to the present that affect the economics of natural gas production,
transportation and sales. In addition, the FERC continues to promulgate
revisions to various aspects of the rules and regulations affecting those
segments of the natural gas industry, most notably interstate natural gas
transmission companies, that remain subject to the FERC's jurisdiction. These
initiatives may also affect the intrastate transportation of gas under certain
circumstances. The stated purpose of many of these regulatory changes is to
promote competition among the various sectors of the natural gas industry and
these initiatives generally reflect more light-handed regulation of the natural
gas industry. The ultimate impact of the complex rules and regulations issued by
the FERC since 1985 cannot be predicted. In addition, many aspects of these
regulatory developments have not become final but are still pending judicial and
FERC final decisions. 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 does not believe that it will be treated
materially different than other natural gas producers and marketers with which
it competes.



                                       25
<PAGE>   27

         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 also has regulations
restricting the flaring or venting of natural gas and has recently proposed to
amend such regulations to prohibit the flaring of liquid hydrocarbons and oil
without prior authorization. Similarly, 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 crude oil produced from federal leases. This proposed rule would
modify the valuation procedures for both arm's length and non-arm's 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.



                                       26
<PAGE>   28

         In April 1997, after two years of study, the MMS withdrew proposed
changes to the way it values natural gas for royalty payments. These proposed
changes would have established an alternative market-based method to calculate
royalties on certain natural gas sold to affiliates or pursuant to non-arm's
length sales contracts. Informal discussions among the MMS and industry
officials are continuing, although it is uncertain whether, and what changes may
be proposed regarding gas royalty valuation. In addition, MMS has recently
announced its intention to issue a proposed rule that would require all but the
smallest producers to be capable of reporting production information
electronically by the end of 1998.

         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 have become subject to more extensive
governmental regulation, including regulations that may in certain circumstances
impose absolute liability upon lessees for cost of removal of pollution and for
pollution and natural resource damages resulting from their operations, and that
may result in assessment of civil or criminal penalties against lessees, or even
suspension or cessation of 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,
pipeline 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 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. The
Working Interest Owner has advised the Trustee that it has in place appropriate
spill contingency plans and has established adequate proof of financial
responsibility for its offshore facilities. A failure to comply with ongoing
requirements or



                                       27
<PAGE>   29

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.

         In recent 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
farm out, 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.

                        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 was
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



                                       28
<PAGE>   30

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 interpretation 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



                                       29
<PAGE>   31

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.

         The Trust is not currently subject to any legal proceedings.

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 2000.

                                     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 over
the counter market under the symbol "FMOLS." As of March 20, 2001, 14,975,390
Units were outstanding and held of record by, Unit holders.

         The high and low sales prices of the Units as reported on the New York
Stock Exchange and the over the counter Bulletin Board and distributable cash
per Unit for each quarterly period of 2000 and 1999 were:



                                       30
<PAGE>   32

<Table>
<Caption>
                                                UNITS OF
                                               BENEFICIAL
                                                INTEREST                    DISTRIBUTABLE
         QUARTER                               -----------                    CASH PER
         ENDED                                    HIGH           LOW             UNIT
         -------                               ----------     ----------    -------------
<S>                                            <C>            <C>           <C>

         March 31, 1999 .......................     1.125            .56             --
         June 30, 1999 ........................      .638            .25             --
         September 30, 1999 ...................      .886            .06             --
         December 31, 1999 ....................       .31            .04             --
         March 31, 2000 .......................        .5            .07             --
         June 30, 2000 ........................       .25            .11             --
         September 30, 2000 ...................       .13            .05             --
         December 31, 2000 ....................       .07            .03             --
</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 securities in 2000.

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,
                                               ----------------------------------------------------------------------
                                                  2000           1999           1998           1997           1996
                                               ----------     ----------     ----------     ----------     ----------
<S>                                            <C>            <C>            <C>            <C>            <C>
         Royalty proceeds ................     $       --     $       --     $       --     $       --     $       --
         Distributable cash ..............             --             --             --             --             --
         Distributable cash per Unit .....             --             --             --             --             --
</Table>

<Table>
<Caption>
                                                                            DECEMBER 31,
                                               ----------------------------------------------------------------------
                                                  2000           1999           1998           1997           1996
                                               ----------     ----------     ----------     ----------     ----------
<S>                                            <C>            <C>            <C>            <C>            <C>
         Cash ............................     $  615,459     $  896,620     $1,406,603     $1,705,582     $1,983,571
         Total assets ....................        615,459        896,620      1,406,603      1,705,582      2,166,784
         Distributions payable ...........             --             --             --             --             --
         Trust corpus ....................             --             --             --             --        183,213
</Table>

         The Trust has not reported estimates of total proved net oil or gas
reserves to any federal authority or agency other than the SEC.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.


         The cost carryforward decreased by $2.6 million, from $22.4 million at
December 31, 1999 to $19.8 million at December 31, 2000. Ryder Scott made
estimates of future net cash flows as of December 31, 2000 as set forth in their
letter appearing elsewhere in this report. Such proved reserve estimates are
based on various assumptions, many of which are subject to uncertainties, as
more fully discussed in Note 10 to the financial statements. These estimates do
not consider changes in prices and costs subsequent to December 31, 2000, or the
possibility of additional potentially recoverable reserves not currently
classified as proved, and therefore should not be considered to be a prediction
of actual amounts to be paid to the trustee or an estimate of fair market value.
The Working Interest Owner has advised the Trustee that, based on an independent
review of the oil and gas interests burdened by the Royalty, the net present
value of the reserves contained therein is less than the cumulative excess cost
carryforward. See Note 1 to the Financial Statements. The information from the
Working Interest Owner indicates that the Royalty may have little or no value,
based on the net present value of reserves determined as a result of the
independent review.




                                       31
<PAGE>   33

RESULTS OF OPERATIONS


         No cash distributions were made during 2000, 1999 and 1998, because of
the cost carryforward due to capital expenditures and lower gas and oil revenues
in 1999, 1998 and 1997. During 2000, Gross Proceeds exceeded total costs by
approximately $2.9 million, primarily because of increased oil revenue from West
Cameron Block 498. As a result, the cost carryforward decreased to $19.8 million
net to the Trust as of December 31, 2000. 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,
                                                  ----------------------------------------------------
                                                      2000                1999                 1998
                                                  ------------        ------------        ------------
<S>                                               <C>                 <C>                 <C>
Gross Proceeds(1) ..........................      $ 11,065,185        $  5,997,857        $ 11,247,539
Total costs(2) .............................        (8,094,021)         (2,438,992)        (20,381,222)
Excess cost carryforward(3) ................         2,971,164)         (3,558,865)          9,133,683
Net Proceeds ...............................                --                  --                  --
Percentage attributable to Royalty .........              90.0%               90.0%               90.0%
Amounts payable attributable to Royalty ....                --                  --                  --
Percentage attributable to the Trust .......              99.9%               99.9%               99.9%
Royalty Proceeds ...........................                --                  --                  --
Trust administrative expenses ..............          (322,575)           (559,995)           (371,133)
                                                      (322,575)           (559,995)           (371,133)
Interest earned ............................            41,414              50,013              72,154
Reserve for future Trust expenses(4) .......           281,161             509,982             298,979
Distributable Cash .........................      $         --        $         --        $         --
                                                  ============        ============        ============
</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
                $2,082,725, $2,292,141 and $1,954,000 respectively. Total costs
                for 1999 also includes a credit of $4,636,212 for the reversal
                of plug and abandonment costs.

         (3)    Represents Class A costs incurred (recouped) in the applicable
                periods that remained outstanding as of the end of such period.

         (4)    Represents the net amount withdrawn from the Trust
                administrative expense reserve during the respective period.

         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,
                                                        ------------------------------------------------
                                                            2000             1999               1998
                                                        ------------      ------------      ------------
<S>                                                     <C>               <C>               <C>
Natural Gas
     Revenues (in millions) ......................      $        2.5      $        3.7      $        4.9
     Sales volumes (in billion cubic feet) .......                .7               2.3               2.1
Average realization (per thousand cubic feet) ....      $       3.26      $       1.65      $       2.28
Oil
     Revenues (in millions) ......................      $        8.6      $        2.3      $        6.3
Sales volumes (in thousands of barrels) ..........             287.0             166.0             449.0
Average realization (per barrel) .................      $      30.00      $      13.82      $      14.13
</Table>

                                       32

<PAGE>   34



         There was a decrease in gas volumes and revenues during 2000 as
compared to 1999 primarily as a result of the Working Interest Owner assigning
its ownership interest in West Cameron Block 215, Breton Sound Block 55 and
Vermilion Block 58 to the operator during 1999.

         There was a slight increase in gas volumes for 1999 as compared to the
1998 period, however, the 1999 volume included a settlement for gas imbalance of
1.2 bcf. This gas imbalance settlement also affected the calculated average
price received for gas during 1999. Gas volume and revenue, excluding the
settlement for gas imbalances, decreased during 1999 as compared to 1998 due to
normal production declines and to the Working Interest Owner assigning its
interests in several properties to the operators. Gas revenue for 1999 included
$1.5 million net to the Trust, for the settlement of gas imbalances on West
Cameron Block 215.

         Oil volume and revenue increased significantly during 2000 as compared
to 1999 as a result of the workovers performed during 2000 and because of the
increase in oil prices.

         Oil volume for 1999 decreased by 63% from 1998. This decrease in oil
volume coupled with a slight decrease in average oil prices resulted in a 63%
decrease in oil revenues for 1999. The decrease in oil volume was a direct
result of mechanical problems and well performance occurring during the last
quarter of 1998 at West Cameron Block 498 extending into the first quarter of
1999. The operator began a workover program during the second quarter of 1999
and production increased during the fourth quarter of 1999. Production rates at
West Cameron Block 498 field fluctuated during 1998 as production rates from
individual wells fluctuated. During the second, third, and fourth quarters of
1999, the operator performed workovers on individual wells that offset the field
decline and in some months increased production. Some of those workovers were
designed to increase recoveries from existing producing intervals and others
were designed to recover oil and gas from different intervals that were expected
to be productive.

         Costs consist of the following (in millions):

<Table>
<Caption>


                                                              YEARS ENDED DECEMBER 31,
                                                   -------------------------------------------------
                                                      2000               1999               1998
                                                   ------------      ------------       ------------
<S>                                                <C>               <C>                <C>
Lease operating expenses ....................      $        1.6      $        3.3       $        3.7
Exploration and development costs ...........               4.2               1.4               14.2
Interest ....................................               2.1               2.3                2.0
Abandonment costs withheld and other ........                 2              (4.6)               0.4
                                                   $        8.1      $        2.4       $       20.3
                                                   ============      ============       ============
</Table>

         Lease operating expenses for the 2000 periods decreased over the 1999
period because the Working Interest Owner assigned its interest in West Cameron
Block 215, Vermilion Block 58 and Breton Sound Block 55 to the operator, thereby
reducing expenses. The Working Interest Owner believed the costs charged for
High Island 552 to be excessive and conducted an audit of High Island Block 552
in the fourth quarter of 1999. This audit resulted in a credit issued by the
operator of $1.5 million net to the Working Interest Owner. This credit was
issued during the first quarter of 2000 and is offset by amounts owed the
operator of approximately $544,000. In addition, the Working Interest Owner is
entitled to operating and processing fees attributable to production from
offsetting blocks being processed on the High Island A552 platform. The Working
Interest Owner began suspending payments of operating expenses to the operator
in early 1999.

         Lease operating expenses for 1999 increased from 1998 primarily because
of the increasing production costs associated with West Cameron Block 498, as
well as, $.02 million being recorded during the third quarter to settle a
disputed liability at Vermilion Block 310 offset by a $.4 million insurance
adjustment credit. Exploration and development costs for both 1998 and 1997
reflects the drilling and


                                       33
<PAGE>   35

development activity at West Cameron Block 498. Lease operating expenses were
lower in 1997 as a result of declining production. Exploration and development
costs primarily consist of costs incurred to explore and develop West Cameron
Blocks 498 and 215 in 1997. Abandonment costs were accrued each year based on
the estimate of costs required to abandon the Trust's properties - see Note 8.
During 1999, a credit of $4.6 million for accrued abandonment cost is included
in total costs as the result of reversing previously accrued abandonment cost
associated with the assigned properties.


         In December 1997, the Working Interest Owner entered into a crude oil
agreement with an oil pipeline company to deliver on a daily basis specified
quantities of crude oil from West Cameron 498. Under the terms of the agreement,
the Working Interest Owner agreed to pay a transportation fee calculated at a
sliding monthly rate based upon the total average daily volumes delivered from
West Cameron 498 during the month. Should the annual minimum delivery volume not
be met a deficiency payment is assessed by the pipeline. During 2000 the Working
Interest Owner did not deliver the minimum volume under the agreement;
therefore, in February 2001, the pipeline company billed the Working Interest
Owner approximately $502,000 for the 2000 deficiency. Deficiency payments of
approximately $724,000 for 1999 and $687,000 for 1998 were paid by the Working
Interest Owner and are included in the cost carryforward of $19.8 million at
December 31, 2001. However, should production exceed the 2000 minimum the
Working Interest Owner is entitled to receive transportation without pay up to
the cumulative prior undelivered volumes.


         Exploration and development costs for 2000 relate primarily to the
workovers and facility modifications made during 2000 at West Cameron Block 498.
Development costs for 1999 also related to the development of West Cameron Block
498.

CAPITAL RESOURCES AND LIQUIDITY


         All revenues received by the Trust, net of Trust administrative
expenses and received for liabilities, are required to be distributed to the
Unit holders in accordance with provisions of the Trust Indenture. The cost
carryforward, with interest at the prime rate, must be recouped from future
Gross Proceeds before any distributions may be made to Unit holders.

         At December 31, 2000, West Cameron Block 498 had 13 producing
development wells, this compares to 10 and 9 development wells producing at
December 31, 1999 and 1998, respectively. The average daily production relating
to revenue received by the Trust from this field during 2000 was approximately
785.8 barrels of oil and 2.1 Mmcf of gas. The average daily production relating
to revenue received by the Trust from this field during 1999 and 1998 was
approximately 595.6 barrels and 1,486.5 barrels of oil, respectively, and 1.3
Mmcf and 4.8 Mmcf of gas, respectively. The average gross daily production
figures may vary throughout the life of the field. These variations may be
attributable to a number of factors, including the number of wells on production
at a given point in time, natural depletion of wells, production techniques, and
adjustments to flow rates in order to optimally produce the related reserves. At
year end 2000, the field was producing approximately 4.2 mmcf per day and 955.51
barrels per day net to the Working Interest Owner. The Working Interest Owner
owns a 23.1 percent working interest and a 19.2 net revenue interest prior to
taking into account the Trust's Royalty interest.


         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.

         There are no exploration and development costs budgeted by the Working
Interest Owner for 2001.

         Estimated future abandonment costs, based on current laws and
regulations, are accrued over the life of the Trust's properties (see Note 8).
On May 19, 1999 the Working Interest Owner assigned its



                                       34
<PAGE>   36


ownership interest in West Cameron Block 215, Breton Sound Block 55 and
Vermilion Block 58 to the operator in exchange for the operator assuming all
duties and obligations with respect to the assigned interest and existing wells
and platforms. The assignment was effective January 1, 1999. As a result of this
transaction the Working Interest Owner reversed the plug and abandonment accrual
associated with the assigned properties, which reduced the cost carryforward by
$3,989,615, net to the Trust. On August 30, 1999 the Working Interest Owner
assigned its ownership interest in Vermilion Blocks 21/22 and paid $297,500 to
the operator in exchange for the operator assuming all duties and obligations
with respect to the assigned interest and existing wells and platforms. The
assignment was effective April 1, 1999. As of December 31, 2000, the estimated
remaining aggregate abandonment costs to be incurred for all of the Trust's
properties totaled $4.2 million net to the Trust, all of which has been taken
into account in computing the cost-carryforward. Such 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 or
technology. Any further adjustments to estimated abandonment costs or variances
to actual costs will reduce or increase future distributable cash accordingly.

         The Working Interest Owner has brought suit against a prior gas
purchaser seeking reimbursement as excess royalty of a portion of amounts paid
to the Minerals Management Service (MMS) by the Working Interest Owner to settle
claims made by the MMS for additional royalty resulting from the Working
Interest Owner's compromise of claims against the gas purchaser. The Trust's
interest in the proceeds of the gas contract settlement were included in Gross
Proceeds and the funds paid to the MMS reduced Gross Proceeds. The Trust will
not receive any recovery as a result of this suit. However, if the Working
Interest Owner receives any amount in this litigation, a major portion of it
will be treated as Gross Proceeds. This would in turn reduce the cost
carryforward or, if the recovery were large enough, eliminate the cost
carryforward and result in the payment of royalties. The suit is in the early
stages, and no trial date has been set. The amount of any recovery with respect
to this claim is presently indeterminable. Furthermore, the Working Interest
Owner may not be successful in this suit, the result of which would be no
recovery for the Working Interest Owner.


         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 Trust
administrative expense reserve to pay such expenses (see Note 6 - Establishment
of an Expense Reserve), of which $0.6 million remained at December 31, 2000.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK





         The Trust does not utilize market risk sensitive instruments. Market
risk relating to oil and gas commodity prices will impact the calculation of the
Royalty, because amounts received by the Working Interest Owner for production
from properties burdened by the Royalty are included in the calculation of Gross
Proceeds. The Trust holds short-term investments (certificates of deposits) for
funds held in its expense reserve. Because of the short-term nature of these
investments, the Trustee believes that the Trust is not subject to any material
interest rate risk.




                                       35
<PAGE>   37

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,
                                              --------------------------------------------------
                                                  2000               1999               1998
                                              ------------       ------------       ------------
<S>                                           <C>                <C>                <C>
Royalty proceeds .......................      $         --       $         --       $         --
Trust administrative expenses ..........          (322,575)          (559,996)          (371,133)
Interest income ........................            41,414             50,013             72,154
Reserve for future Trust expenses ......           281,161            509,983            298,979
                                              ------------       ------------       ------------
Distributable cash .....................      $         --       $         --       $         --
                                              ============       ============       ============
Distributable cash per Unit ............      $         --       $         --       $         --
                                              ============       ============       ============
Units outstanding ......................        14,975,390         14,975,390         14,975,390
                                              ============       ============       ============
</Table>


               STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS


<Table>
<Caption>

                                                                                               DECEMBER 31,
                                                                                    ---------------------------------
                                                                                        2000                 1999
                                                                                    -------------       -------------
<S>                                                                                 <C>                 <C>
                                       ASSETS

Cash and cash equivalents ....................................................      $     615,459       $     896,620
Net overriding royalty interest in oil and gas properties ....................        189,875,741         189,875,741
Less, accumulated amortization of net overriding royalty interest ............       (189,875,741)       (189,875,741)
                                                                                    -------------       -------------
Total assets .................................................................      $     615,459       $     896,620
                                                                                    =============       =============

                          LIABILITIES AND TRUST CORPUS

Reserve for future Trust expenses ............................................      $     615,459       $     896,620
Trust corpus (14,975,390 Units of Beneficial Interest authorized, issued
   and outstanding) ..........................................................                 --                  --
                                                                                    -------------       -------------
Total liabilities and trust corpus ...........................................      $      15,459       $     896,620
                                                                                    =============       =============
</Table>


                      STATEMENTS OF CHANGES IN TRUST CORPUS

<Table>
<Caption>


                                                                                        YEARS ENDED DECEMBER 31,
                                                                            ------------------------------------------------
                                                                               2000               1999              1998
                                                                            ------------      ------------      ------------
<S>                                                                         <C>               <C>               <C>
Trust corpus, beginning of year ......................................      $         --      $         --      $         --
Royalty proceeds and interest earned, net of trust administrative
expenses and reserve for future Trust expenses .......................                --                --                --
Distributions payable to Unit holders ................................                --                --                --
                                                                            ------------      ------------      ------------
Trust corpus, end of year ............................................      $                 $                 $         --
                                                                            ============      ============      ============
</Table>

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


                                       36
<PAGE>   38







                   FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST

                          NOTES TO FINANCIAL STATEMENTS

1. BACKGROUND AND STATUS

         Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created
effective September 30, 1983. On that date, Freeport-McMoRan Inc. (FTX)
transferred to a Partnership (the Partnership) a net overriding royalty interest
in certain offshore oil and gas properties 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. 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." IMC Global Inc.
("IMC") succeeded to FTX effective December 22, 1997, following the merger of
FTX into IMC. Accordingly, IMC is now the Working Interest Owner and 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). The Trust is passive, with The Chase Manhattan Bank 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. The Trust
Indenture originally stated that the Trust must also terminate if the amount of
cash per year received by the Trust for each of three successive years
commencing after December 31, 1990 is less than $3 million. The Trust's cash
receipts were less than $3 million in 1996, 1997 and 1998. However, at a special
meeting of the Unit holders held on March 12, 1999, the Unit holders approved a
shareholder proposal to amend the Trust Indenture to extend the life of the
Trust for at least two years. This extension expired on December 31, 2000, as
there were no payments in respect of the Royalty during 1999 and 2000.
Therefore, the Trust Indenture provides the Trustee must sell the Trust's
interest in the Partnership or cause the Partnership to sell the Royalty.
Pursuant to a shareholder proposal, the Trustee is working on proxy materials
and anticipates filing definitive proxy materials with a plan for distribution
of the Trust's assets.





2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

         The Trust's financial statements, which reflect the Trust's 99.9
percent interest in the Partnership, 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 accounting principles generally accepted in the United States,
revenues and expenses would be recognized on an accrual basis.

         The initial carrying amount of the Royalty represented the Working
Interest Owner'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 has been 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.


                                       37

<PAGE>   39


         The Trust considers all highly liquid investments purchased with a
maturity of three months or less to be cash equivalents. The Trust's expense
reserve is invested in certificates of deposits which mature every thirty days.


         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. The carrying value of the Royalty was $0 at December 31,
2000 and 1999.

         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.

3. COST CARRYFORWARD


         As a result of the capital costs incurred in recent years, a cumulative
excess cost carryforward of $19.8 million existed as of December 31, 2000. The
cost carryforward was $22.4 million at December 31, 1999. The cost carryforward
is subject to and includes an interest amount at the prime rate, which totaled
$6.8 million net to the Trust at December 31, 2000. This excess cost
carryforward must be recouped by the Working Interest Owner out of future Gross
Proceeds before distributions to the Unit holders can be resumed. See Note 1.


4. 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 Gross Proceeds. 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, 2000, the unrecovered quantity of gas sold
by third parties pursuant to such gas balancing arrangements since inception of
the Trust was approximately .2 billion cubic feet (bcf), net to the Trust. Gross
Proceeds may 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 are uncertain. In addition, other factors, including
the credit worthiness of the counterparties should be considered in determining
the probability and the amount of future proceeds.

         On May 19, 1999 the Working Interest Owner assigned its ownership
interest, to include gas imbalances, in West Cameron Block 215, Breton Sound
Block 55 and Vermilion Block 58 to the operator in exchange for the operator
assuming all duties and obligations with respect to the assigned interest and
existing wells and platforms. The assignment was effective January 1, 1999. As a
result of this transaction, the Working Interest Owner received approximately
$1.5 million, net to the Trust, from the operator in settlement for the gas
imbalances. On August 30, 1999 the Working Interest Owner assigned its ownership
interest, to include gas imbalances in Vermilion Blocks 21/22 and paid $.3
million to the operator in exchange for the operator assuming all duties and
obligations with respect to the assigned interest and existing wells and
platforms. The assignment was effective April 1, 1999.



                                       38

<PAGE>   40

5. GAS CONTRACT SETTLEMENT

         The Working Interest Owner has brought suit against a prior gas
purchaser, seeking reimbursement as excess royalty of a portion of amounts paid
to the Minerals Management Service (MMS) by the Working Interest Owner to settle
claims made by the MMS for additional royalty resulting from the Working
Interest Owner's compromise of claims against the gas purchaser. The Trust's
interest in the proceeds of the gas contract settlement were included in the
Trust's Gross Proceeds and the funds paid to the MMS reduced the Trust's Gross
Proceeds. The suit is in the early stages, and no trial date has been set. The
amount of any recovery with respect to this claim is presently indeterminable.
However, if the Working Interest Owner receives any amount in this litigation, a
major portion of it will be treated as Gross Proceeds.

6. ESTABLISHMENT OF AN EXPENSE RESERVE


         Because of the decline in Royalty income, at certain times since late
1993 the Trust was unable to pay its ongoing administrative expenses. To permit
the Trust to pay its routine administrative expenses, the Trustee, in accordance
with the Trust Indenture, established an expense reserve of $2.4 million of
which $.6 million remained as of December 31, 2000. Because the Trust had no
cash receipts, $.3 million was withdrawn from the expense reserve during 2000 to
pay Trust administrative expenses.


         The funding for this reserve is deposited with Chase Bank of Texas and
invested in Chase Bank of Texas collateralized certificates of deposit. The
average interest rate earned on these funds was 5.5 percent for 2000, 4.4
percent for 1999, and 4.5 percent for 1998.





         The expense reserve is established at the Trust level and is unrelated
to the items, including the cost carryforward, that are taken into account by
the Working Interest Owner in determining whether amounts are payable pursuant
to the Royalty.


7. FEDERAL INCOME TAX MATTERS

         The Trustee reports on the basis that the Trust is a grantor trust. As
a grantor trust, the Trust will incur no federal income tax liability. In
addition, it will incur little or no federal income tax liability if it is held
to be a non-grantor trust. If the Trust was held to be taxable as a corporation,
it would have to pay tax on its net taxable income at the corporate rate.

8. RESERVE FOR FUTURE ESTIMATED ABANDONMENT COSTS


         Estimated future abandonment costs are accrued over the life of the
Trust's properties based on current laws and regulations. Such 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
or technology. As of December 31, 2000, the estimated remaining aggregate
abandonment costs to be incurred for all of the Trust's properties totaled $4.2
million net to the Trust, all of which has been taken into account in computing
the cost carryforward.

         On May 19, 1999 the Working Interest Owner assigned its ownership
interest in West Cameron Block 215, Breton Sound Block 55 and Vermilion Block 58
to the operator in exchange for the operator assuming all duties and obligations
with respect to the assigned interest and existing wells and platforms. The
assignment was effective January 1, 1999. On August 30, 1999 the Working
Interest Owner assigned its ownership interest in Vermilion Blocks 21/22 and
paid $.3 million to the operator in exchange for the operator assuming all
duties and obligations with respect to the assigned interest and existing wells
and platforms. The assignment was effective April 1, 1999. The completion of
these assignments resulted in a reduction of estimated future abandonment costs,
which total approximately $4.2 million, net to the Trust.




                                       39
<PAGE>   41


         Any further adjustments to estimated abandonment costs or variances to
actual costs will reduce or increase future distributable cash after
consideration of the cost carryforward.


9. TRANSPORTATION AGREEMENT

         In December 1997 the Working Interest Owner entered into a crude oil
agreement with an oil pipeline company to deliver on a daily basis specified
quantities of crude oil from West Cameron 498. Under the terms of the agreement
the Working Interest Owner agreed to pay a transportation fee calculated at a
sliding monthly rate based upon the total average daily volumes delivered from
West Cameron 498 during the month. Should the annual minimum delivery volume not
be met, a deficiency payment is assessed by the pipeline.


         During 2000, 1999 and 1998, the Working Interest Owner did not deliver
the minimum volume under the agreement, therefore, the pipeline company billed
the Working Interest Owner for the deficiencies. In 2001 the pipeline company
billed the Working Interest Owner approximately $.5 million for the 2000
deficiency. This amount was taken into account in computing the cost
carryforward of $19.8 million at December 31, 2000. Deficiency payments of
approximately $.7 million for 1999 and 1998, respectively, were paid by the
Working Interest Owner and were taken into account in computing the cost
carryforward of $19.8 million at December 31, 2000. Based on 2001 projected
production, the minimum delivery volumes will not be met in 2001 and the Working
Interest Owner expects a deficiency assessment of approximately $.2 million in
2001. However, should production exceed the 2001 minimum, the Working Interest
Owner is entitled to receive transportation without pay up to the cumulative
prior undelivered volumes.





10. SUPPLEMENTARY PROVED OIL AND GAS RESERVE INFORMATION (UNAUDITED)

         Pursuant to the Financial Accounting Standards Board's (FASB) and SEC's
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
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 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 are hypothetical and
are not comparable to estimates of reserves attributable to a working interest.


         The reserve volume and cash flow amounts 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 a report of Ryder Scott Company L.P. (Ryder
Scott). In accordance with the requirements of the FASB, the reserve estimates
were calculated using year-end oil and gas prices being received and current
operating and abandonment cost levels. 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, 2000, 1999 and 1998, approximately .2 bcf, .2 bcf, and 1.4 bcf sold
by other patties pursuant to certain gas balancing arrangements and (c) an
excess cost carryforward of $19.8 million, $22.4 million and $25.6 million at
December 31, 2000, 1999 and 1998, respectively. For purposes of the reserve
volume and cash flow amounts, the estimates of Ryder Scott were adjusted to take
into account the foregoing factors, based on calculations supplied by the
Working Interest Owner. In making such adjustment, the Working Interest Owner
subtracted amounts attributable to the items referred to in (a), (b) and (c) of
the preceding






                                       40
<PAGE>   42


sentence. Based on the estimates of Ryder Scott, as adjusted for the effect of
the cost carryforward and as calculated in accordance with the FASB's and SEC's
standards, at December 31, 2000, 1999 and 1998 there were no proved reserves and
no estimated future net cash flow attributable to the Royalty.

         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.
Additionally, as required under FASB's and SEC's standards, the supplementary
information excludes consideration of anticipated future oil and gas prices and
costs and does not consider additional potentially recoverable oil and gas
reserves not currently classified as proved. Such factors should be considered
in estimating the cash flows which ultimately could be derived from production
of the related oil and gas reserves or sale of the reserves in-place.






                                       41
<PAGE>   43





                   FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST

                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Chase Bank of Texas, National Association (Trustee) and the Unit Holders of
Freeport-McMoRan Oil and Gas Royalty Trust:

         We have audited the accompanying statements of assets, liabilities and
trust corpus of Freeport-McMoRan Oil and Gas Royalty Trust as of December 31,
2000 and 1999, 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, 2000. These financial statements are the responsibility of
the Trustee. Our responsibility is to express an opinion on these financial
statements based on our audits.

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

         As described in Note 3, these financial statements were prepared on the
cash basis of accounting which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States.

         In our opinion, the financial statements referred to above present
fairly, in all material respects, the assets, liabilities and trust corpus of
Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 2000 and 1999, and
the royalty proceeds and distributable cash, and changes in trust corpus for
each of the three years in the period ended December 31, 2000, on the cash basis
of accounting described in Note 2.

                                               ARTHUR ANDERSEN LLP

Houston, Texas
March 30, 2001


                                       42

<PAGE>   44





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

         Chase Bank of Texas, National Association, as Trustee of the Trust,
owns no Units. Chase Bank of Texas, 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.

         The parent of Chase Texas, Chase Manhattan Corporation, has banking
relationships with the Company.

                                     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.



                                       43
<PAGE>   45





         (a)3. Exhibits

<Table>
<Caption>

 EXHIBIT
  NUMBER                                DESCRIPTION
 -------                                -----------
<S>            <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.

         (b) Reports on Form 8-K

         No reports on Form 8-K were filed during 2000.


                                       44
<PAGE>   46





                                    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:  THE CHASE MANHATTAN BANK, Trustee



                                    By:           /s/ MIKE ULRICH
                                       -----------------------------------------
                                                    Mike Ulrich
                                         Senior Vice President and Trust Officer

March 30, 2001

         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.


                                       45
<PAGE>   47






                                  EXHIBIT INDEX

<Table>
<Caption>


       EXHIBIT
       NUMBER                          DESCRIPTION
       ------                          -----------

<S>                 <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.



<PAGE>   48





         THIS ANNUAL REPORT ON FORM 10-K WAS DISTRIBUTED TO UNIT HOLDERS AS AN
ANNUAL REPORT. ADDITIONAL COPIES OF THIS ANNUAL REPORT WILL BE PROVIDED, WITHOUT
CHARGE, AND COPIES OF EXHIBITS HERETO WILL BE PROVIDED, UPON PAYMENT OF A
REASONABLE FEE, UPON WRITTEN REQUEST FROM ANY HOLDER OF UNITS TO:

Freeport-McMoRan Oil and Gas Royalty Trust
The Chase Manhattan Bank
Attention: Corporate Trust Department
700 Lavaca, 5th Floor
Austin, TX 73701