FREEPORT MCMORAN OIL & GAS ROYALTY TRUST, 10-K405, 2000-03-30

FREEPORT MCMORAN OIL & GAS ROYALTY TRUST
10-K405, 2000-03-30
OIL ROYALTY TRADERS

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999

[ ] 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)

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

CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, 77002
TRUSTEE (Zip Code)
712 MAIN STREET
HOUSTON, TEXAS
(Address of Principal Executive Offices)
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Registrant's Telephone Number, Including Area Code: (713) 216-5712

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

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NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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Units of Beneficial Interest Over the Counter
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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, 2000 was approximately $3,444,339.70 based on the
closing price of the Units of $.23.

As of March 27, 2000, 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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PAGE
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PART I

Item 1. Business.................................................... 1
Background.................................................. 1
Description of the Trust.................................... 1
Description of the Units.................................... 5
The Royalty Properties and the Royalty...................... 7
Federal Income Tax Considerations........................... 24
Item 2. Properties.................................................. 25
Item 3. Legal Proceedings........................................... 25
Item 4. Submission of Matters to a Vote of Unit Holders............. 25

PART II

Item 5. Market for the Registrant's Units and Related Unit Holder
Matters................................................... 26
Item 6. Selected Financial Data..................................... 26
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of
Operations................................................ 27
Item 7A. Quantitative and Qualitative Disclosures about Market
Risk...................................................... 31
Item 8. Financial Statements and Supplementary Data................. 31
Statements of Royalty Proceeds and Distributable Cash:
For the years ended December 31, 1999,1998, and 1997........ 31
Statements of Assets, Liabilities and Trust Corpus:
As of December 31, 1999 and 1998............................ 32
Statements of Changes in Trust Corpus:
For the years ended December 31, 1999, 1998 and 1997........ 32
Notes To Financial Statements............................... 33
Report Of Independent Public Accountants.................... 40
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 41

PART III

Item 10. Directors and Executive Officers of the Registrant.......... 41
Item 11. Executive Compensation...................................... 41
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 41
Item 13. Certain Relationships and Related Transactions.............. 41

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 42
Signature.............................................................. 43
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PART I

ITEM 1. BUSINESS.

BACKGROUND

Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created under
the laws of the State of Texas. Chase Bank of Texas, National Association (Chase
Texas) serves as Trustee of the Trust.

For a discussion of the (i) estimated reserves attributable to the Royalty
Trust as of December 31, 1999 and the estimated future net income of the Trust,
see the report by Ryder Scott Company L.P. contained on pages 10 through 15
hereof, (ii) financial condition and results of operations of the Trust, see
Item 7 appearing on pages 27 through 31 hereof and (iii) financial statements
and supplementary data of the Trust, see Item 8 appearing on pages 31 through
40, with special reference to Note 10 thereto appearing on page 37.

The combination of the significant Class A cost carry-forward and negative
reserve quantity revisions, have caused there to be no proved oil and gas
reserve quantities and related discounted future net cash flows attributable to
the Trust at December 31, 1999. Further, as described under "Termination of the
Trust," the Trust indenture provides that "if the amount of cash per year
received by the Trust for each of three successive years commencing after
December 31, 1990 is less the $3,000,000 then the Trustee shall sell the Trust's
interest in the Partnership or cause the Partnership to sell the Royalty". The
Trust did not have $3 million in cash receipts during 1998, which was the third
year in a row the Trust failed to achieve $3 million in cash receipts.
Therefore, the Trust indenture provides the Trustee shall sell the Trust's
interest in the Partnership or cause the Partnership to sell the Royalty.
However at a special meeting of the Unit holders held on March 12, 1999, the
Unit holders of the Trust approved a shareholder proposal to amend the Trust
Indenture to extend the life of the Trust for at least another two years. Any
such amendment of the Trust Indenture requires, in addition to the requisite
vote of the Unit holders, the written approval of the Trustee. Before the
Trustee approved the amendment and even before the Unit holders' March 12, 1999
vote, IMC Global Inc. (IMC), the owner of the working interest burdened by the
Trust's royalty interest, filed on March 3, 1999 a declaratory judgment action
in Harris County, Texas seeking to enjoin the Trustee from approving the
amendment of the Trust Indenture (the "IMC Lawsuit"). The Trustee will take no
action to approve the amendment until such time as the lawsuit is resolved.
After filing of the lawsuit, IMC pursued limited discovery. The Trustee,
pursuant to its powers under the Trust Indenture, and IMC have entered into
settlement negotiations. To allow adequate time to pursue all settlement
options, IMC and the Trustee moved for and received from the District Court an
Agreed Order on Joint Motion to Abate. In furtherance of settlement negotiations
and while the lawsuit is abated, the Trustee has retained Albrecht & Associates
to assist it in connection with a possible settlement.

DESCRIPTION OF THE TRUST

On July 2, 1999, the New York Stock Exchange (NYSE) issued a notice to the
Trust that the Trust had fallen below the continued listing qualitative
standards of the Exchange. The notice was based on NYSE's determination that the
Trust did not meet NYSE listing requirements after a review of the Trust's Form
10-K filing for the fiscal year ending December 31, 1998 and Form 10-Q filing
for the three months ending March 31, 1999.

The Trust sent an inquiry letter to the NYSE requesting, in light of the
unique circumstances surrounding the Trust, an extension with respect to the
continued listing criteria, but such request was denied. Following suspension of
trading in the Units, the NYSE filed an application with the Securities Exchange
Commission to delist the Units.

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The Trustee believes that it took all reasonable actions to maintain the
registration of the Units on the NYSE, but because the Trust has fallen below
the NYSE continued listing criteria, the Trustee was unable to maintain such
registration.

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

The term "Company," as used herein, includes IMC successor to
Freeport-McMoRan Inc. (FTX) effective December 22, 1997, its divisions, direct
and indirect subsidiaries and affiliates, except as otherwise indicated by the
context. The term "Working Interest Owner" means IMC, and the successors and
assigns of its oil and gas working interests to the extent the context requires.

The Units are not an interest in or an obligation of the Company, the
Working Interest Owner or any successor Working Interest Owner although they
represent indirect interests in the Royalty Properties (as defined below). The
following information and the information set forth under "DESCRIPTION OF THE
UNITS" are subject to the detailed provisions of the Royalty Trust Indenture
entered into between IMC and the Trustee (the Trust Indenture) and the First
Amended and Restated Articles of General Partnership of Freeport-McMoRan Oil and
Gas Royalty Partnership (the Partnership) entered into between McMoRan Offshore
Management Co., formerly an indirect wholly owned subsidiary of FTX, and the
Trustee (the Partnership Agreement). The Trust Indenture and the Partnership
Agreement are among the exhibits to this report. The provisions governing the
Trust and the Partnership are complex and extensive, and no attempt has been
made below to describe all of such provisions. The following is a general
description of the basic framework of the Trust and the Partnership, and
reference is made to the Trust Indenture and the Partnership Agreement for
detailed provisions concerning the Trust and the Partnership.

CREATION AND TRANSFER OF THE ROYALTY

On September 30, 1983, pursuant to the terms of the Overriding Royalty
Conveyance (the Conveyance), 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.

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.

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THE TRUST

Under the Trust Indenture, the Trustee holds an interest in the Partnership
for the benefit of the Unit holders. The terms of the Trust Indenture provide,
among other things, that (1) the Trustee cannot engage in any business or
investment activity and cannot acquire any asset other than its interest in the
Partnership and cash being held for payment of liabilities or distribution to
Unit holders; (2) the Royalty can be sold in whole or in part upon approval of
the Unit holders or upon termination of the Trust; and (3) any cash
distributions to the Unit holders are made by the Trustee quarterly in January,
April, July and October of each year.

The Trust Indenture provides that Unit holders take their Units subject to
the provisions of the Trust Indenture, which gives the Trustee only such rights
and powers as are necessary and proper for the conservation and protection of
the Royalty. Accordingly, the Trustee has no responsibility or authority with
respect to the operation of the Royalty Properties. The Trust is a passive
trust, and the Trust Indenture requires the Trustee (a) to receive all income
and proceeds of the Royalty net of other Partnership expenses and net of amounts
attributable to the Managing General Partner's 0.1 percent interest in the
Partnership, (b) to pay or provide for the payment of expenses, charges,
liabilities and obligations of the Trust and (c) to distribute to Unit holders
the remaining revenues attributable to the Royalty.

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 2000. The Trustee, in
accordance with the Trust Indenture, established an expense reserve to cover
Trust expenses as discussed in Note 7 -- Establishment of an Expense Reserve, of
which approximately $0.9 million remained as of December 31, 1999. The costs and
expenses of the Trust may increase in future years, depending on the volume of
trading in the Units, the amount of revenues to the Trust and increases in
accounting, legal and other administrative fees.

DUTIES AND LIMITED POWERS OF THE TRUSTEE

Under the Trust Indenture, the Trustee receives the Trust's share of any
distributions from the Partnership and pays all expenses, charges, liabilities
and obligations of the Trust. With respect to any liability which is contingent
or uncertain in amount or which otherwise is not currently due and payable, the
Trustee has the discretion to establish a cash reserve for the payment of such
liability. If at any time the cash on hand and to be received by the Trustee is
not, in its judgment, sufficient to pay liabilities of the Trust as they become
due, the Trustee is authorized to borrow the funds required to pay such
liabilities, in which event no further distributions will be made to Unit
holders until such borrowing has been repaid. The Trustee is permitted to borrow
such funds from any bank, including itself. To secure payment of any such
indebtedness, the Trustee is authorized to mortgage, pledge, grant security
interests in or otherwise encumber assets of the Trust, or any portion thereof,
to cause the Partnership to mortgage, pledge, grant security interests in or
otherwise encumber the Royalty, and to cause the Partnership to carve out and
convey production payments. After payment of or provision for Trust expenses and
obligations, the Trustee makes quarterly distributions to the Unit holders of
all the proceeds received from the Partnership in respect of the Royalty and not
theretofore distributed. The Trustee submits periodic financial reports to the
Unit holders as described under "DESCRIPTION OF THE UNITS -- Periodic Reports."

The Trust Indenture authorizes the Trustee to take such action as in its
judgment is necessary or advisable to achieve the purposes of the Trust. The
Trust Indenture provides that cash being held by the Trustee as a reserve for
liabilities or for distribution at the next distribution date will be placed in
interest-bearing accounts or certificates (which may include accounts or
certificates of the bank acting as Trustee), but the Trustee is otherwise
prohibited from acquiring any asset other than the Trust's interest in the
Partnership or engaging in any business or investment activity of any kind
whatsoever. The Trustee may sell or dispose of

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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) if the Trust's cash receipts for each of three
successive years commencing after December 31, 1990 are less than $3 million.
The Trustee must distribute the net proceeds of such sale (after satisfaction of
any outstanding liabilities) to the Unit holders. The Trust's cash receipts were
less than $3 million dollars in 1996, 1997, and 1998. Therefore, unless the
amendment of the Trust Indenture approved by the Unit holders on March 12, 1999
is effected, the Trustee will endeavor to effect such a sale. The amendment of
the Trust Indenture approved by the Unit holders will not take effect unless and
until approved in writing by the Trustee. The Trustee will take no action to
approve the amendment until such time as the lawsuit filed by IMC to prevent the
Trustee from approving the amendment is resolved. As discussed under "Business"
above, the Trustee is currently engaged in an effort to settle the IMC Lawsuit.

The Trustee is also authorized to agree to modifications of the terms of
the Partnership Agreement or to cause the Partnership to agree to modifications
of the terms of the Conveyance or to settle disputes with respect thereto, so
long as such modifications or settlements do not (i) alter the nature of the
Royalty as a right to receive a share of the proceeds of minerals produced from
the Royalty Properties, free of any expense or other cost and without any
operating rights, or (ii) alter the Partnership Agreement so as to change the
purposes or scope of activities of the Partnership. Furthermore, the Trustee may
not agree to any distribution from the Partnership of the Royalty, or any other
asset of the Partnership, which would cause the interest of the holders of Units
to be treated as other than an intangible personal property interest.

LIABILITIES OF THE TRUSTEE

The Trustee may act in its discretion and will be personally or
individually liable only for fraud, gross negligence or bad faith. The Trustee
will be indemnified from the Trust assets for any liability, expense, claim,
damage or other loss incurred in performing its duties, unless resulting from
fraud, gross negligence or bad faith, and will have a lien upon the assets of
the Trust as security for such indemnification and for reimbursements and
compensation to which it is entitled. The Trustee will not be entitled to
indemnification from Unit holders.

TERMINATION OF THE TRUST

At a special meeting of the Unit holders held on March 12, 1999, the Unit
holders approved a shareholder proposal to amend the provision of the Trust
Indenture that requires the Trustee to terminate the Trust if the Trust receives
less than $3 million in cash receipts for each of three consecutive years so as
to extend the life of the Trust for at least another two years. Any such
amendment of the Trust Indenture requires both the approval of the Unit holders
and the consent of the Trustee. IMC has filed a declaratory judgment action in
Harris County, Texas seeking to enjoin the Trustee from approving the amendment
of the Trust Indenture. The Trustee will take no action to approve the amendment
until such time as the lawsuit is resolved. After filing of the lawsuit, IMC
pursued limited discovery. Then, in late 1999, the Trustee, pursuant to its
powers under the Trust Indenture, and IMC entered into settlement negotiations.
To allow adequate

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time to pursue all settlement options, IMC and the Trustee moved for and
received from the District Court and Agreed Order on Joint Motion to Abate. In
furtherance of settlement negotiations and while the lawsuit is abated, the
Trustee has retained Albrecht & Associates to assist it in connection with a
possible settlement.

DESCRIPTION OF THE UNITS

GENERAL

Each Unit is evidenced by a transferable certificate. Each Unit evidences
an undivided interest in the Trust, which in turn owns a 99.9 percent interest
in the Partnership. A total of 14,975,390 Units are outstanding.

DISTRIBUTIONS AND INCOME COMPUTATIONS

Each month the Trustee determines the amount, 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. 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, the net taxable income from the Royalty (other than interest earned
on Monthly Distribution Amounts) will be realized by the Unit holders for tax
purposes in the month accrued by the Partnership, rather than in the month
distributed by the Trust. Thus, a Unit holder may be required to report income
attributable to his Units without receiving distributions directly corresponding
to such income.

NATURE OF THE UNITS

The Units are not an interest in or obligation of the Company, the Working
Interest Owner or any successor Working Interest Owner. However, the ultimate
value of the Royalty is dependent to a large extent upon the ability of the
Working Interest Owner to produce oil and gas from the Royalty Properties. There
is no requirement that the Working Interest Owner expend any specific amounts
with respect to the Royalty Properties, and the Working Interest Owner is
entitled to go "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 its working interest (burdened by the
Royalty) to third parties. 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

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arrangements. The realization of the ultimate value of the Royalty is subject to
all the risks associated with exploration on and development of oil and gas
properties and to comprehensive regulation by governmental authorities.

TRANSFER OF THE UNITS

Units are transferable on the records of the Trustee or transfer agent upon
the surrender of any certificate representing Units in proper form for transfer
as required by the Trustee. No service charge 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
able to instigate legal action

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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 the 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 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.

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GENERAL

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. A final settlement has been presented
to the operator to accurately allocate income and expenses attributable to the
assigned interest after the effective date. Under this settlement, the Working
Interest Owner owes the operator $671,338.

During the month of June 1999, in a separate transaction, the Working
Interest Owner received approximately $1.7 million from the operator of the
above listed properties in settlement for the gas imbalances incurred prior to
January 1, 1999. Such amounts will be reflected in the Class A cost carry-
forward.

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. A final settlement statement was presented to the
operator to allocate income and expenses attributable to the assigned interest
subsequent to the effective date. The operator owes the Working Interest Owner
$1,411.

The Working Interest Owner is reviewing all options relating to its
ownership interest in the remaining properties, including discussions with
several unit holders.

As of December 31, 1999, there were 11 gross productive oil wells and 13
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 Company. 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 unitholders. 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, 1999, 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, 1999, 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 1999
attributable to sales of oil and gas produced in the fourth quarter of 1999,
volumes of natural gas sold by other

8
<PAGE> 11

parties pursuant to certain gas balancing arrangements and the effect of the
excess Class A cost carry-forward at December 31, 1999. Therefore, the amounts
set forth in the letter are not necessarily indicative of actual amounts to be
distributed to Unit holders, either annually or ultimately.

The estimates of future net cash flows and discounted present value of
future net cash flows were prepared using prices and costs as of December 31,
1999. 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 11 -- Supplementary Proved Oil and Gas Reserve
Information).

9
<PAGE> 12

[RYDER SCOTT LETTERHEAD]

March 23, 2000

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, 1999. 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 1999 hydrocarbon prices
were used in the preparation of this report as required by SEC guidelines;
however, actual future prices may vary significantly from December 1999 prices.
Therefore, volumes of reserves actually recovered and amounts of income actually
received may differ

10
<PAGE> 13

significantly from the estimated quantities presented in this report. The
results of this study are summarized as follows:

SEC PARAMETERS
ESTIMATED NET RESERVE AND INCOME DATA
FREEPORT-MCMORAN OIL AND GAS ROYALTY PARTNERSHIP
AS OF DECEMBER 31, 1999

<TABLE>
<CAPTION>
TOTAL PROVED
------------
<S> <C>
Remaining Reserves
Oil/Condensate -- Barrels.............................. 240,502
Gas -- MMCF............................................ 1,318
Future Net Income (FNI)
2000................................................... $2,360,194
2001................................................... 1,796,933
2002................................................... 1,436,171
----------
Sub-Total (2000-2002).................................. $5,593,298
Remaining.............................................. 4,217,702
----------
Total.................................................. $9,811,000
Discounted FNI @ 10% (Compounded Annually)............... $7,578,752
</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 $1,400,145 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, no deduction was made to represent any 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.

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, 1999 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.

11
<PAGE> 14

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:

<TABLE>
<C> <C> <C> <S>
Partnership Interest Net Reserves = Royalty Future Net Income
-------------------------
Price per Unit of
Reserves
</TABLE>

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

RESERVE DEFINITIONS

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

Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from
known reservoirs under existing operating conditions, 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 escalation based on future conditions. Reservoirs are considered
proved if economic producibility is supported by either actual production
or conclusive formation test. In certain instances, proved reserves are
assigned on the basis of a combination of core analysis and electrical and
other type logs which indicate the reservoirs are analogous to reservoirs
in the same field which are producing or have demonstrated the ability to
produce on a formation test. The area of a reservoir considered proved
includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can
be reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts,
the lowest known structural occurrence of hydrocarbons controls the lower
proved limit of the reservoir. Reserves that can be produced economically
through the application of improved recovery techniques are included in the
proved classification when these qualifications are met: (1) successful
testing by a pilot

12
<PAGE> 15

project or the operation of an installed program in the reservoir provides
support for the engineering analysis on which the project or program was
based, and (2) it is reasonably certain the project will proceed. Improved
recovery includes all methods for supplementing natural reservoir forces
and energy, or otherwise increasing ultimate recovery from a reservoir,
including (1) pressure maintenance, (2) cycling, and (3) secondary recovery
in its original sense. Improved recovery also includes the enhanced
recovery methods of thermal, chemical flooding, and the use of miscible and
immiscible displacement fluids. Proved natural gas reserves are comprised
of non-associated, associated and dissolved gas. An appropriate reduction
in gas reserves has been made for the expected removal of natural gas
liquids, for lease and plant fuel, and for the exclusion of non-hydrocarbon
gases if they occur in significant quantities and are removed prior to
sale. Estimates of proved reserves do not include crude oil, natural gas,
or natural gas liquids being held in underground or surface storage. Proved
reserves are estimates of hydrocarbons to be recovered from a given date
forward. They may be revised as hydrocarbons are produced and additional
data become available.

Proved 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.
Developed reserves may be subcategorized as producing or non-producing
using the SPE/WPC Definitions:

Producing
Reserves sub-categorized as producing are expected to be recovered
from completion intervals which are open and producing at the time of
the estimate. Improved recovery reserves are considered producing only
after the improved recovery project is in operation.

Non-Producing
Reserves sub-categorized as non-producing include shut-in and
behind pipe reserves. Shut-in reserves are expected to be recovered from
(1) completion intervals which are open at the time of the estimate but
which have not started producing, (2) wells which were shut-in for
market conditions or pipeline connections, or (3) wells not capable of
production for mechanical reasons. Behind pipe reserves are expected to
be recovered from zones in existing wells, which will require additional
completion work or future recompletion prior to the start of production.

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 reasonable certainty that there is continuity of
production from the existing productive formation. Estimates for proved
undeveloped reserves are attributable to any acreage for which an
application of fluid injection or other improved technique is contemplated,
only when such techniques have been proved effective by actual tests in the
area and in the same reservoir.

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.

13
<PAGE> 16

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

FUTURE PRODUCTION RATES

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

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

HYDROCARBON PRICES

The Working Interest Owner furnished us with prices in effect at December
31, 1999 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, 1999 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 1999, 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, 1999
were not considered in this study.

Gas

The Working Interest Owner has furnished us with gas prices in effect at
December 1999 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.

14
<PAGE> 17

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.

GENERAL

The reserve estimates presented herein are based upon a detailed study of
the Subject Properties; however, Ryder Scott has not made any field examination
of the properties. No consideration was given in this report to potential
environmental liabilities which may exist nor were any costs included for
potential liability to restore and clean up damages, if any, caused by past
operating practices. The Working Interest Owner has represented that it has
given Ryder Scott access to its accounts, records, geological and engineering
data and reports and other data as were required for this investigation. The
ownership interests, prices, and other factual data furnished to Ryder Scott by
the Working Interest Owner in connection with this investigation were accepted
without verification. The estimates presented in this report are based on such
furnished data available through December 1999.

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.

Richard J. Savoie, P.E.
Petroleum Engineer

15
<PAGE> 18

All the total 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, 1999. Thus, amounts received
by the Working Interest Owner after November 30, 1999 attributable to production
during 1999 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
1999. The Working Interest Owner has estimated that if Ryder Scott had taken
into account the 2000 Gross Proceeds from 1999 production, the total estimated
future net

16
<PAGE> 19

cash flow and the discounted present value of such estimate in the Ryder Scott
letter would have been approximately $.13 million higher (net to the Trust's
interest). In addition, because Ryder Scott's estimates for the remaining period
are based on estimated production and Costs accrued during each such period and
because actual Gross Proceeds and Costs will not be based on production and
Costs during the same period, the estimates for various time periods will not in
any event correspond to the amount of payments pursuant to the Royalty during
such periods.

Ryder Scott gave no effect in its estimates to amounts to which the Working
Interest Owner is entitled as a result of gas imbalances for certain production
(see Note 5 -- Gas Balancing Arrangements and Note 11 -- Supplementary Proved
Oil and Gas Reserve Information). Pursuant to the Conveyance, proceeds from gas
produced from the Royalty Properties but sold by other parties pursuant to gas
balancing arrangements between the Working Interest Owner and others
(underproduction) are not included in Gross Proceeds for purposes of calculating
the Royalty. In the future the Working Interest Owner will be entitled to sell
volumes equal to such underproduction or receive cash settlements. The amounts
the Working Interest Owner will receive from the future sale of such
underproduction may be more or less than those amounts received by third parties
because of price fluctuations.

The estimated future net cash flows shown in Ryder Scott's letter have not
been reduced for any capital expenditures on Productive Properties in excess of
amounts estimated to be necessary to develop proved reserves attributed thereto.
See "Computation of the Royalty" below. Similarly, such future net cash flows
have also not been reduced for costs and expenses of the Trust, which are
estimated at approximately $.9 million or of the Partnership, which are expected
to be minimal. Additionally, Ryder Scott did not take into account the Class A
cost carry-forward of $22.4 million net to the Trust, as of December 31, 1999,
nor did they take into account the oil transportation deficiency of $724
thousand applicable to 1999 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 month, together with interest
on such excess. This carry-forward amount includes the Class A cost
carry-forward, which was $22.4 million to the Trust at December 31, 1999.
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

17
<PAGE> 20

production payments existing at the time of the creation of the Trust which
burdened the Royalty Properties prior to the effective date of the Conveyance,
and subject to farmouts and certain other adjustments.

"Costs" means, generally, (i) all costs incurred by the Working Interest
Owner in producing and operating the Royalty Properties (lease operating
expenses), (ii) all capital costs incurred, or projected to be incurred, by the
Working Interest Owner in drilling and completing exploratory and development
wells and in connection with the installation of platforms, pipelines and other
production facilities, (iii) an overhead charge and (iv) amounts recovered by
the Working Interest Owner as estimated Abandonment Costs ("Abandonment Costs"
means, generally, the future costs to be incurred by the Working Interest Owner
to plug and abandon wells and dismantle and remove platforms, pipelines and
other production facilities from the Royalty Properties).

The Working Interest Owner is entitled to accrue certain estimated future
costs in accordance with a formula set forth in the Conveyance. The accrual
formula provides that, for any month and with respect to a specific item of
future costs, the Working Interest Owner may include in its costs an amount
calculated by multiplying (a) the excess of (i) the total estimated amount of
such item of future cost over (ii) the aggregate amount accrued in previous
months with respect to such item, by (b) a fraction, the numerator of which is
Adjusted Gross Proceeds for such month and the denominator of which is total
estimated future Adjusted Gross Proceeds for such month and all future months.
For this purpose, "Adjusted Gross Proceeds" means Gross Proceeds for a month
less all Class A Costs for such month, such costs that were not covered in the
previous month and interest thereon. Class A Costs are all costs that are not
Class B Costs. Class B Costs for a month are (a) costs incurred to discover or
develop minerals on certain leases, (b) any monthly future cost accruals, (c)
such costs that were not covered by proceeds in the previous month and (d)
interest thereon.

If Costs exceed Gross Proceeds for any month, the excess will be recovered
by the Working Interest Owner, with interest at the prime rate (as defined in
the Conveyance), compounded monthly, out of future Gross Proceeds prior to the
making of further payments to the Partnership, but the Partnership and the
Trustee are not liable for any operating, capital or other costs or liabilities
attributable to the Royalty Properties or hydrocarbons produced therefrom. Such
recovery will apply to Class B Costs as well. The Partnership and the Trustee
are not obligated to return any Royalty income received in any period, but
overpayments made by the Working Interest Owner would reduce future amounts
payable.

The Working Interest Owner is required to maintain books and records
sufficient to determine the amounts payable under the Conveyance. Additionally,
in the event of a controversy between the Working Interest Owner and any
purchaser as to the correct sales price of any production, amounts received by
the Working Interest Owner and promptly deposited by it with an escrow agent
shall not be considered as having been received by the Working Interest Owner,
and therefore shall not be included as Gross Proceeds, until the controversy is
resolved, but all amounts thereafter paid to the Working Interest Owner by the
escrow agent shall be considered Gross Proceeds. Similarly, Costs will include
any amounts the Working Interest Owner is required to pay as a refund, interest
or penalty because the amount received by it as a sales price was in excess of
that permitted by the terms of any applicable contract, statute, regulation,
order, decree or other obligation. Because the Units are publicly traded,
purchasers of Units in the market may, as a result of such procedures, receive
distributions of amounts that would have been distributed to former holders if
such amounts had not 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.

18
<PAGE> 21

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 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 1999, the Working
Interest Owner did not deliver the minimum volume under the agreement;
therefore, in February 2000, the pipeline company billed the Working Interest
Owner approximately $724,000 for the 1999 deficiency. This amount is not
included in the Class A cost carry-forward of $22.4 million as of December 31,
1999. Based on 2000 projected production, the minimum delivery volumes will not
be met in 2000.

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 1999 as well as information concerning other activities on such
properties during 1999, see Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations and Note 11 -- 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 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.
19
<PAGE> 22

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 1999 was 2% lower than the average
price received during 1998 and 33% higher than that during 1997. 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.

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 1999, the
Working Interest Owner did not deliver the minimum volume under the agreement;
therefore, in February 2000, the pipeline company billed the Working Interest
Owner approximately $724,000 for the 1999 deficiency. This amount will be
included in the Class A cost carry-forward in 2000. The minimum proved oil
reserves to be produced, based on Ryder Scotts reserve evaluation, net to the
Working Interest Owner, for 2000 will be 249,207 barrels, declining to 135,157
in 2001. Based on 2000 projected production the minimum delivery volumes will
not be met in 2000. 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.

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 non-price 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
20
<PAGE> 23

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.

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

21
<PAGE> 24

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.

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

22
<PAGE> 25

responsibility for its offshore facilities. A failure to comply with ongoing
requirements or inadequate cooperation in a spill event may subject a
responsible party to civil or criminal enforcement action. In short, the OPA
places a burden on offshore lease holders to conduct safe operations and take
other measures to prevent oil spills; if one occurs, the OPA then imposes
liability for resulting damages.

In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating on the
OCS. Specific design and operational standards may apply to OCS vessels, rigs,
platforms, vehicles and structures. Violations of environmental related lease
conditions or regulations issued pursuant to the OCSLA can result in substantial
civil and criminal penalties as well as potential court injunctions curtailing
operations and the cancellation of leases. Such enforcement liabilities can
result from either governmental prosecution or citizen initiated legal action.

The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of person
that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site where the release occurred and companies that disposed or
arranged for disposal of hazardous substances found at the site. Persons who are
or were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances released into the environment and for damages to natural
resources, and it is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage allegedly caused
by the hazardous substances released into the environment.

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.

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<PAGE> 26

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 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
24
<PAGE> 27

disposition and provide the Trustee with the Unit holder's name, address,
taxpayer identification number and the date of the disposition. Failure to so
notify the Trustee may subject such a Unit holder, as well as the Trust and the
Partnership, to the above-described penalties. Without notification from Unit
holders, the Trust and Partnership cannot comply with these reporting
requirements because they have no other means of determining which Units
disposed of during the year were acquired by the transferring Unit holder
subsequent to December 31, 1986.

Other Possible Penalties. An owner of a security who receives income in
respect of such interest must report the character and amount of such income,
for federal tax purposes, in a manner which is consistent with the federal tax
reports of the entity which was the source of the income. The consistency
requirement is deemed to be waived if the taxpayer files a statement with the
Service identifying the inconsistency. Because of the presence of "street name"
investors and the possible existence of transfer record inaccuracies, holders of
interests which are actively traded in the securities markets may encounter
situations in which it is difficult to fully and accurately comply with the
consistency requirement and other federal tax reporting requirements. Certain
penalties could be assessed against a taxpayer that fails to comply with such
requirements. Because of the complexity of the federal tax reporting
requirements applicable to trusts (such as the Trust) which own interests in
partnerships (such as the Partnership) and because all of the tax attributes of
the Royalty flow through the Partnership and the Trust to the Unit holders,
there is an increased likelihood that Unit holders will violate the consistency
requirement and other reporting requirements regarding their individual federal
income tax returns and the information returns of the Trust and the Partnership.
Any violations of the consistency requirements could lead to imposition of
certain penalties on the Unit holders or other adverse results. Furthermore, the
Trust or the Partnership might be subject to certain penalties in connection
with their furnishing of statements and information to Unit holders or the
government if such statements or information prove to be inaccurate due, for
example, to differences between the transfer agent's records and actual
ownership data. The Code provides reporting requirements designed to facilitate
the transfer of information between partnerships and trusts and owners of
interests therein held by nominees.

ITEM 2. PROPERTIES.

Reference is made to Item 1 of this report.

ITEM 3. LEGAL PROCEEDINGS.

As disclosed above, The Trust is currently the subject of the IMC Lawsuit.
The IMC Lawsuit seeks to enjoin and deny effect to the Unit holders' March 12,
1999 vote approving a shareholder proposal to amend the provision of the Trust
Indenture that requires the Trustee to terminate the Trust if the Trust receives
less than $3 million in cash receipts for each of three consecutive years so as
to extend the life of the Trust for at least another two years. In its
discretion, the Trustee has yet to approve the Unit Holder vote pending a
resolution of the IMC Lawsuit. The Trustee will take no action to approve the
amendment until such time as the lawsuit is resolved. The Trustee will either
settle or vigorously defend the IMC Lawsuit. The Trustee has taken no action to
terminate the Trust at this time.

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 1999.

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<PAGE> 28

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 27, 2000, 14,975,390 Units
were outstanding and held of record by 8,771 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 1999 and 1998 were:

<TABLE>
<CAPTION>
UNITS OF
BENEFICIAL
INTEREST DISTRIBUTABLE
QUARTER ----------- CASH PER
ENDED HIGH LOW UNIT
- ------- ---- ---- -------------
<S> <C> <C> <C>
Mar. 31, 1998............................................... 3.31 2.25 --
Jun. 30, 1998............................................... 2.88 1.88 --
Sept. 30, 1998.............................................. 2.56 1.50 --
Dec. 31, 1998............................................... 1.74 .50 --
Mar. 31, 1999............................................... 1.125 .56 --
Jun. 30, 1999............................................... .63 .25 --
Sept. 30, 1999.............................................. .88 .06 --
Dec. 31, 1999............................................... .31 .04 --
</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 1999.

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,
--------------------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C>
Royalty proceeds(1)..................................... $-- $-- $-- $-- $5,235,068
Distributable cash(1)................................... -- -- -- -- 4,662,081
Distributable cash per Unit............................. -- -- -- -- 0.31130
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------------------------
1999 1998 1997 1996 1995
-------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Cash...................... $896,620 $1,406,603 $1,705,582 $1,983,571 $2,300,979
Total assets.... 896,620 1,406,603 1,705,582 2,166,784 2,484,192
Distributions payable..... -- -- -- --
Trust corpus.............. -- -- -- 183,213 183,213
</TABLE>

- ---------------

(1) Includes $4.3 million in 1995 and related to various gas contract
settlements (See Note 6 -- Gas Contract Settlement).

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

26
<PAGE> 29

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

In 1999, the Class A cost carry-forward decreased by $3.2 million, from
$25.6 million at December 31, 1998 to $22.4 million at December 31, 1999. There
were no proved oil and gas reserve quantities and related discounted future net
cash flows attributable to the Trust at December 31, 1999. Such proved reserve
estimates are based on various assumptions, many of which are subject to
uncertainties, as more fully discussed in Note 11 to the financial statements.
These estimates do not consider changes in prices and costs subsequent to
December 31, 1999, 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 substantially less than the cumulative excess Class A cost carry-forward. 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.
Depending on the resolution of the IMC Lawsuit, the Trustee will take
appropriate actions to continue to administer the Trust throughout the extension
period approved by the Unit holders or liquidate the Trust by selling the Trust
assets for cash to the highest bidder in accordance with the terms of the Trust
Indenture. The resolution or settlement of the lawsuit could result in other
actions.

RESULTS OF OPERATIONS

No cash distributions were made during 1999, 1998 and 1997, because of
capital expenditures and lower gas and oil revenues in 1999, 1998 and 1997.
During 1999, Gross Proceeds exceeded total costs by approximately $3.6 million,
primarily because of the receipt of $1.7 million for the settlement of gas
imbalances on West Cameron 215 and significantly lower capital and operating
costs. As a result, the Class A cost carry-forward decreased to $22.4 million
net to the Trust as of December 31, 1999. 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,
-----------------------------------------
1999 1998 1997
----------- ------------ ------------
<S> <C> <C> <C>
Gross Proceeds(1)........................... $ 5,997,857 $ 11,247,539 $ 2,804,130
Total costs(2).............................. (2,438,992) (20,381,222) (19,446,762)
Excess Class A cost carry-forward(3)........ (3,558,865) 9,133,683 16,642,632
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............... (559,995) (371,133) (356,880)
----------- ------------ ------------
(559,995) (371,133) (356,880)
Interest earned............................. 50,013 72,154 78,890
Reserve for future Trust expenses(4)........ 509,982 298,979 277,990
----------- ------------ ------------
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 $2,292,141, $1,954,000 and $724,370
respectively. Total costs for 1999 also includes a credit of $4,636,212 for
the reversal of plug and abandonment costs.

27
<PAGE> 30

(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 (added to) 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,
------------------------
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Natural Gas
Revenues (in millions)................................... $ 3.7 $ 4.9 $ 1.5
Sales volumes (in billion cubic feet).................... 2.3 2.1 0.6
Average realization (per thousand cubic feet)............ $ 1.65 $ 2.28 $ 2.53
Oil
Revenues (in millions)................................... $ 2.3 $ 6.3 $ 1.3
Sales volumes (in thousands of barrels).................. 166.0 449.0 65.0
Average realization (per barrel)......................... $13.82 $14.13 $20.58
</TABLE>

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 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 during 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.

Revenues and volumes for oil and gas during 1998 increased substantially
over 1997 primarily reflecting the increased development and the commencement of
production at West Cameron Block 498. Production at West Cameron Block 498
commenced during the fourth quarter of 1997 from six wells and the number of
producing wells increased to ten by the end of 1998. The 1998 increased revenues
from West Cameron Block 498 were offset in part by normal production declines at
the other properties burdened by the Royalty and by lower oil and natural gas
prices, which fell significantly in early 1998. Additionally, oil and gas
volumes for 1997 were impacted by normal production declines. Revenues during
1998 and 1997 benefited from an increase in average realizations reflecting the
rise in natural gas and oil market prices during these years. Gas volumes in
1998 included an additional net underdelivery of 0.1 bcf and 1997 included a
make-up of gas sold under balancing agreements totaling 0.2 bcf.

28
<PAGE> 31

Costs consist of the following (in millions):

<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31,
--------------------
1999 1998 1997
----- ----- ----
<S> <C> <C> <C>
Lease operating expenses.................................... $ 3.3 $ 3.7 $1.0
Exploration and development costs........................... 1.4 14.2 17.6
Interest.................................................... 2.3 2.0 0.7
Abandonment costs withheld and other........................ (4.6) 0.4 0.1
----- ----- ----
$ 2.4 $20.3 $19.4
===== ===== ====
</TABLE>

Lease operating expenses for the 1999 periods decreased over the 1998
periods 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 has 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 1998 increased from 1997 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 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 9. 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 1998, the
Working interest Owner did not deliver the minimum volume under the agreement
therefore, in February 1999, the pipeline company billed the Working Interest
Owner approximately $687,000 for the 1998 deficiency. This amount was included
in the Class A cost carry-forward in 1999. During 1999 the Working Interest
Owner did not deliver the minimum volume under the agreement; therefore, in
February 2000, the pipeline company billed the Working Interest Owner
approximately $724,000 for the 1999 deficiency. This amount will be included in
the Class A cost carry-forward in 2000. Based on 2000 projected production the
minimum delivery volumes will not be met in 2000. 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 1999 relate primarily to the payment
during 1999 of invoices relating to 1998 in connection with the development at
West Cameron Block 498. Development costs for 1998 also related to the
development of West Cameron Block 498.

29
<PAGE> 32

CAPITAL RESOURCES AND LIQUIDITY

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

Exploratory drilling on West Cameron Block 498 began in June 1994 and
ultimately resulted in four successful wells which were saved for future
production. A 12 slot, four pile drilling platform was set in March 1997, from
which four additional wells were drilled during the rest of 1997 and early 1998.
An auxiliary platform was set in October 1997, with production facilities
capable of handling 55 million cubic feet of natural gas and 15,000 barrels of
oil per day. In February 1998, Coastal Oil & Gas Corporation, the operator,
announced intended future development plans for additional drilling and
construction activity in this block during the remainder of 1998, including
drilling and completing four additional wells and setting a six-well satellite
platform. At December 31, 1999, West Cameron Block 498 had 10 producing
development wells, this compares to 9 development wells producing at December
31, 1998. The average daily production relating to revenue received by the Trust
from this field during 1999 was approximately 595.6 barrels of oil and 1.3 Mmcf
of gas. The average daily production relating to revenue received by the Trust
from this field during 1998 was approximately 1,486.5 barrels of oil and 4.8
Mmcf of gas. 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 1999, the field was
producing approximately 8.3 Mmcf per day and 1,134 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.

At the West Cameron 215 field, the Working Interest Owner participated in
the drilling of the West Cameron 215 #8 exploratory well during the fourth
quarter of 1997. The well did not encounter any commercial hydrocarbons and was
plugged and abandoned. The cost net to the Trust was $1.6 million, which is
reflected in the cost carry-forward. The Working Interest Owner's interest in
this property was assigned to the operator in 1999.

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 for 2000.

Estimated future abandonment costs, based on current laws and regulations,
are accrued over the life of the Trust's properties (see Note 9). 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. As a result of this transaction the Working Interest
Owner reversed the plug and abandonment accrual associated with the assigned
properties, which reduced the Class A cost carry-forward 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. A final settlement will occur in early 2000 to allocate income
and expenses attributable to the assigned interest subsequent to the effective
date.

The Working Interest Owner is reviewing all options relating to its
ownership interest in the remaining properties, including discussions with
several Unit holders.

As of December 31, 1999, 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 withheld from distributions to Unit holders.
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
30
<PAGE> 33

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 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.

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 7 -- Establishment
of an Expense Reserve), of which $0.9 million remained at December 31, 1999.

The Trustee may sell or dispose of its interest in the Partnership, or
permit the Partnership to sell or dispose of all or any part of the Royalty,
only as authorized by a vote of Unit holders, upon termination of the Trust and
in certain other limited circumstances. However, the Trust is directed to effect
such a sale (without any such vote) if the Trust's cash receipts for each of
three successive years are less than $3 million. The Trustee must distribute the
net proceeds of such sale (after satisfaction of any outstanding liabilities) to
the Unit holders. The Trust's had no cash receipts in 1996, 1997, 1998 or 1999.
Additionally, the balance of the Class A cost carry-forward was $22.4 million at
December 31, 1999, primarily from the significant development costs incurred at
West Cameron Blocks 498 and 215 during 1997 and 1998. This cost carry-forward
must be recouped by the Working Interest Owner before any distribution may be
made to the Trust. Since the Trust did not receive cash receipts of at least $3
million during the three successive years ending December 31,1998, the Trust
will be terminated by one of the means described under "Termination of the
Trust" above.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The only significant market risk to the Trust is oil and gas commodities
prices, which are discussed more fully in ITEM 7, "MANAGEMENTS DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS."

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,
---------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Royalty proceeds.............................. $ -- $ -- $ --
Trust administrative expenses................. (559,996) (371,133) (356,880)
Interest income............................... 50,013 72,154 78,890
Reserve for future Trust expenses............. 509,983 298,979 277,990
----------- ----------- -----------
Distributable cash............................ $ -- $ -- $ --
=========== =========== ===========
Distributable cash per Unit................... $ -- $ -- $ --
=========== =========== ===========
Units outstanding............................. 14,975,390 14,975,390 14,975,390
=========== =========== ===========
</TABLE>

31
<PAGE> 34

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1999 1998
------------- -------------
<S> <C> <C>
ASSETS

Cash................................................... $ 896,620 $ 1,406,603
Net overriding royalty interest in oil and gas
properties........................................... 189,875,741 189,875,741
Less, adjustment to recorded cost of net overriding
royalty interest in oil and gas properties........... (25,614,756) (25,614,756)
Less, accumulated amortization of net overriding
royalty interest..................................... (164,260,985) (164,260,985)
------------- -------------
Total assets........................................... $ 896,620 $ 1,406,603
============= =============

LIABILITIES AND TRUST CORPUS

Reserve for future Trust expenses...................... $ 896,620 $ 1,406,603
Trust corpus (14,975,390 Units of Beneficial Interest
authorized, issued and outstanding).................. -- --
------------- -------------
Total liabilities and trust corpus..................... $ 896,620 $ 1,406,603
============= =============
</TABLE>

STATEMENTS OF CHANGES IN TRUST CORPUS

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------
1999 1998 1997
----- ----- ----------
<S> <C> <C> <C>
Trust corpus, beginning of year............................. $-- $-- $ 183,213
Royalty proceeds and interest earned, net of trust
administrative expenses and reserve for future Trust
expenses.................................................. -- -- --
Distributions payable to Unit holders....................... -- -- --
Adjustment to recorded cost of net overriding royalty
interest in oil and gas properties (Note 3)............... -- -- (183,213)
Amortization of net overriding royalty interest............. -- -- --
--- --- ---------
Trust corpus, end of year................................... $-- $-- $ --
=== === =========
</TABLE>

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

32
<PAGE> 35

FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

1. THE TRUST

Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created
effective September 30, 1983. On that date, Freeport-McMoRan Inc. (FTX)
transferred 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 Chase Bank of Texas, National Association as Trustee. The Trustee
has only such powers as are necessary for the collection and distribution of
revenues attributable to the Royalty, the payment of Trust liabilities and the
protection of Trust assets.

The Trust Indenture provides generally that the Trust shall terminate upon
the first to occur of: (i) the sale of all the Trust's interest in the
Partnership, or the sale by the Partnership of all the assets of the Partnership
including the Royalty, or (ii) a decision to terminate the Trust by the
affirmative vote of Unit holders representing a majority of the Units. The Trust
Indenture also provides "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 Trustee shall sell the Trust's interest in the Partnership
or cause the Partnership to sell the Royalty". The Trust did not have $3 million
in cash receipts during 1998, which was the third year in a row the Trust failed
to achieve $3 million in cash receipts. Therefore, the Trust indenture provides
the Trustee shall sell the Trust's interest in the Partnership or cause the
Partnership to sell the Royalty However, the Unit holders of the Trust, at a
special meeting of the Unit holders held on March 12, 1999, approved a Unit
holder proposal to amend the Trust Indenture to extend the life of the Trust for
at least another two years. Any such amendment of the Trust Indenture requires
the written approval of the Trustee as well as approval of the Unit holders. IMC
Global Inc. (IMC), the Working Interest Owner, has filed a declaratory judgment
action seeking to prevent the Trustee from approving the amendment. The Trustee
will take no action to approve the amendment until such time as the lawsuit is
resolved. After the filing of the lawsuit, IMC pursued limited discovery. The
Trustee, pursuant to its powers under the Trust Indenture, and IMC have entered
into settlement negotiations. To allow adequate time to pursue all settlement
options, IMC and the Trustee moved for and received from the District Court an
Agreed Order on Joint Motion to Abate. In furtherance of settlement negotiations
and while the lawsuit is abated, the Trustee has retained Albrecht & Associates
(Albrecht) to assist it in connection with a possible settlement.

The Trust's cash receipts last reached $3 million during 1995 and there
were no cash receipts in 1996, 1997, 1998 or 1999. Additionally, the Class A
cost carry-forward is $22.4 million at December 31, 1999, primarily from the
significant development costs incurred at West Cameron Block 498. This cost
carry-forward must be recouped by the Working Interest Owner before any
distribution may be made to the Trust. The Trust did not have cash receipts of
at least $3 million during 1998, therefore, unless the amendment of the Trust
Indenture approved by the Unit holders at the special meeting held on March 12,
1999 is effected, the Trust will be terminated by one of the means described
above.

2. THE ROYALTY

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).

33
<PAGE> 36
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

3. 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.

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
11). 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,
1999 and 1998. As there was no discounted present value of estimated future net
cash flows from proved reserves attributable to the Trust at December 31, 1997
(see Note 11), the remaining carrying value of the Royalty ($183,213) was
charged directly against trust corpus. The adjustment did not affect royalty
proceeds or distributable cash. Neither the initial nor the December 31, 1998
carrying value is necessarily indicative of the fair market value of the Royalty
held by the Trust.

Because the Trust is a grantor trust which is not a taxable entity, no
income taxes are reported in the Trust's financial statements. The tax
consequences of owning Units are included in the federal, state and local income
tax returns of the individual Unit holders.

4. DISTRIBUTIONS TO UNIT HOLDERS

As a result of the capital costs incurred in recent years, a cumulative
excess Class A cost carry-forward of $22,427,192 existed as of December 31,
1999. The Class A cost carry-forward was $25,626,860 at December 31, 1998. The
cost carry-forward is subject to and includes an interest amount at the prime
rate, which totaled $4,676,648 net to the Trust at December 31, 1999. This
excess Class A cost carry-forward 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.

5. GAS BALANCING ARRANGEMENTS

As a result of past curtailments in gas takes by the principal purchaser of
production from the Royalty Properties, certain quantities of gas have been sold
by other parties with interests in the Royalty Properties pursuant to gas
balancing arrangements. Proceeds from gas produced from the Royalty Properties
but sold by other parties pursuant to such balancing arrangements
(underproduction) are not included in 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, 1999, 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 will
be increased in future periods when the Working Interest Owner is compensated
either through the sale of gas or through cash settlements, the amount and
timing of which are uncertain.

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
34
<PAGE> 37
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 $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. These transactions are
reflected in the Class A cost carry-forward at December 31, 1999.

6. 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.

7. 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 $896,620 remained as of December 31, 1999. Because the Trust had no cash
receipts in 1999, $509,983 was withdrawn from the expense reserve during 1999 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 4.4 percent for 1999, 4.5
percent for 1998, and 4.3 percent for 1997.

8. FEDERAL INCOME TAX MATTERS

Ownership of Units

The IRS has ruled that the Trust is a grantor trust and that the
Partnership is a partnership for federal income tax purposes. Thus, the Trust
will incur no federal income tax liability, each Unit holder will be treated as
owning an interest in the Partnership and each Unit holder of record as of the
last business day of each quarter will be allocated a share of the income and
deductions of the Trust, including the Trust's share of the income and
deductions of the Partnership (computed on an accrual basis), for that quarter.
Also, each Unit holder will be entitled to compute cost depletion with respect
to his share of income from the Royalty based on his basis in the Royalty. A
Unit holder will have a basis in the Royalty equal to the basis in his Units.
Unit holders that acquired Units after October 11, 1990, are entitled to
percentage depletion on Royalty income attributable to those Units.

Since the IRS has ruled that the Trust is a grantor trust and that the
Partnership is a partnership for federal income tax purposes, the Trustee will
treat each Unit holder as owning an interest in the Partnership and will report
to the Unit holders in a manner consistent with the Trust Agreement and the
Partnership Agreement, allocating income and deductions of the Partnership and
the Trust for each quarter to the Unit holders of record as of the last business
day of that quarter. Also, since the IRS has ruled that the Royalty is a
non-operating economic interest giving rise to income subject to depletion, the
Trustees will treat the Royalty

35
<PAGE> 38
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

as a single property giving rise to income subject to depletion, although the
computation of depletion will be made by each Unit holder based upon information
provided by the Trustee.

The Tax Reform Act of 1986 made significant changes as to the
classification of certain income and expense items. Royalty income is considered
portfolio income. Since all income from the Partnership is royalty income, this
amount, net of depletion, is portfolio income and, subject to certain exceptions
and transitional rules, this royalty income cannot be offset by losses from
passive businesses. Additionally, interest income is portfolio income.
Administrative expense is an investment expense.

Backup Withholding

Distributions from the Trust are generally subject to backup withholding at
a rate of 31% of those distributions. Backup withholding will not normally apply
to distributions to a Unit holder, however, unless a Unit holder fails to
properly provide to the Trust his taxpayer identification number ("TIN") or the
IRS notifies the Trust that the TIN provided by a Unit holder is incorrect.

Sale of Units

Generally, except for recapture items, the sale, exchange or other
disposition of a Unit will result in capital gain or loss measured by the
difference between the basis in the Unit and the amount realized. Effective for
property placed in service after December 31, 1986, the amount of gain, if any,
realized upon the disposition of oil and gas property is treated as ordinary
income to the extent of the intangible drilling and development costs incurred
with respect to the property and depletion claimed with respect to the property
to the extent it reduced the taxpayer's basis in the property. Depletion
attributable to a positive Section 743(b) basis adjustment of a Unit acquired
after 1986 will also be subject to recapture as ordinary income upon disposition
of the Unit or upon disposition of the oil and gas property to which the
depletion is attributable. The balance of any gain or any loss will be capital
gain or loss if the Unit was held by the Unit holder as a capital asset, either
long-term or short-term depending on the holding period of the Unit. This
capital gain or loss will be long-term if a Unit Holder's holding period for the
Units exceeded one year as of the date of sale or exchange. A long-term capital
gains rate of 20% applies to most capital assets sold with a holding period of
more than one year. Capital gain or loss will be short-term if the Unit has not
been held for more than one year at the time of disposition.

Foreign Unit Holders

In general, a Unit holder who is a nonresidential alien individual or which
is a foreign corporation (each a "Foreign Taxpayer") will be subject to tax on
the gross income produced by the Royalty at a rate equal to 30% (or lower treaty
rate, if applicable). This tax will be withheld by the Trustee and remitted
directly to the United States Treasury. A Foreign Taxpayer may elect to treat
the income from the Royalty as effectively connected with the conduct of a
United States trade or business under Section 871 or Section 882 of the Internal
Revenue Code of 1986, as amended (the "Code") (or pursuant to any similar
provisions of applicable treaties). Upon making that election that Unit holder
is entitled to claim all deductions with respect to that income, but he must
file a United States income tax return to claim those deductions. This election
once made is irrevocable (unless an applicable treaty allows the election to be
made annually). However, that effectively connected income is subjected to
withholding equal to the highest applicable percentage (tax rate) -- 39.6% for
individual foreign Unit holders and 35% for corporate foreign Unit holders.

Section 897 of the Code and the Treasury Regulations thereunder treat the
publicly traded Trust as if it were a United States real property holding
corporation. Accordingly, Foreign Taxpayers owning greater than five percent of
the outstanding Units (or 237,576 Units) are subject to United States income tax
on the gain on the disposition of their Units. Foreign Taxpayers owning five
percent of the outstanding Units are not subject to United States income tax on
the gain on the disposition of their Units.

36
<PAGE> 39
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Federal income taxation of a Foreign Taxpayer is a highly complex matter
which may be affected by many other considerations. Therefore, each Taxpayer
holder should consult his own tax adviser as to the advisability of his
ownership of Units.

9. 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. During the 1997 fourth
quarter, an updated assessment of estimated future abandonment costs was
undertaken by the Working Interest Owner taking into consideration current labor
and equipment cost levels and permitted abandonment practices. This assessment
resulted in a revision of estimated remaining future abandonment costs to an
amount that is approximately equal to amounts previously withheld from
distributions to Unitholders. 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, 1999, 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 withheld from distributions to Unit holders.

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 $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. The completion of these
assignments resulted in a reduction of estimated future abandonment costs
totaling approximately $4.2 million, net to the Trust.

Any further adjustments to estimated abandonment costs or variances to
actual costs will reduce or increase future distributable cash after
consideration of the Class A cost carry-forward.

10. 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 1999 and 1998,
the Working Interest Owner did not deliver the minimum volume under the
agreement, therefore, in 2000 the pipeline company billed the Working Interest
Owner approximately $724,000 for the 1999 deficiency. This amount is not
included in the Class A cost carry-forward of $22.4 million at December 31,
1999. During 1999 the Working Interest Owner paid the oil pipeline company
approximately $687,000 for the 1998 deficiency. This amount is included in the
Class A cost carry-forward of $22.4 million at December 31, 1999.

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

Pursuant to the Financial Accounting Standards Board's (FASB) disclosure
standards for oil and gas producing activities, the Trust is required to include
as supplementary information, estimates of quantities of proved oil and gas
reserves attributable to the Trust. Since the Royalty is a net profits 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
37
<PAGE> 40
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 set forth below are
hypothetical and are not comparable to estimates of reserves attributable to a
working interest.

The reserve volume and cash flow amounts set forth below are for the
interest in the Royalty attributable to the Trust, based on the Trust's 99.9
percent interest in the Partnership. Estimates of proved oil and gas reserves
attributable to the Trust's interest are based on reports of Ryder Scott Company
L.P. (Ryder Scott). In preparing its estimates, Ryder Scott did not take into
account (a) revenues received after November 30 attributable to production
during the fourth quarter of the respective year, (b) as of December 31, 1999,
1998 and 1997, approximately .2 bcf, 1.4 bcf, and 1.6 bcf sold by other parties
pursuant to certain gas balancing arrangements and (c) an excess Class A cost
carry-forward of $22.4 million, $25.6 million and $17.4 million at December 31,
1999, 1998 and 1997, respectively. For purposes of the reserve volume and cash
flow amounts set forth below, the Trustee adjusted the estimates of Ryder Scott
to take into account the foregoing factors, based on calculations supplied by
the Working Interest Owner. In accordance with the requirements of the FASB, the
reserve disclosures below were calculated using year-end oil and gas prices
being received and current operating and abandonment cost levels.

As discussed in Note 9, based on escalated estimates of costs to abandon
the properties burdened by the Royalty, estimated remaining future abandonment
costs approximately equal amounts previously withheld from distributions to Unit
holders. For purposes of the reserve volume and cash flow amount set forth
below, Ryder Scott has not considered the escalated estimates of these costs,
nor has there been any adjustment to Ryder Scott's estimates, as the Trust is
required to present the supplementary information assuming no escalation in
costs.

Proved Oil and Gas Reserves. The following table sets forth estimates of
the interest attributable to the Trust in proved oil and gas reserves and
changes in such estimates. Oil, including crude oil, condensate and natural gas
liquids, is stated in thousands of barrels; gas is stated in millions of cubic
feet.

<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- -------------
OIL GAS OIL GAS OIL GAS
--- --- --- --- ---- ------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of year.............. -- -- -- -- 804 6,490
-- --
Changes in prices and other Revisions to
previous estimates, including impact of
Class A cost carry-forward(1).............. -- -- -- -- (746) (5,969)
Extensions and discoveries.................... -- -- -- -- -- --
Production.................................... -- -- -- -- (58) (521)
-- -- -- -- ---- ------
Proved reserves, end of year.................... -- -- -- -- -- --
== == == == ==== ======
</TABLE>

- ---------------

(1) Estimates of proved reserves are subject to possible change, either upward
or downward, as additional information becomes available. Because the
Royalty is a net profits interest and reserve quantities are estimated
pursuant to a formula based in part on the estimated future net cash flows,
factors other than changes in estimates of gross quantities of reserves
(such as changes in prices and costs) can result in changes in estimates of
reserve quantities attributable to the Trust. Negative revisions in 1997
reflect the impact of lower oil and gas prices, unfavorable drilling results
and the effect of the Class A cost carry-forward. Approximately 300,000
barrels and 4,400 million cubic feet of the negative revision amounts shown
for 1997 are attributable to the cost carry-forward, based on the formula
discussed above. Consequently, proved oil and gas reserves at December 31,
1999 and 1998, based on year-end prices, would provide estimated future net
revenues in an amount less than the Class A cost carry-forward. Accordingly,
there were no proved reserves as of December 31, 1999, 1998 and 1997
attributable to the Trust.

38
<PAGE> 41
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Standardized Measure of Discounted Future Net Cash Flows from Proved Oil
and Gas Reserves. The supplementary information presented below reflects
estimates of discounted future net cash flows from proved oil and gas reserves
and changes in such estimates prepared in accordance with requirements
prescribed by the FASB.

Future cash flows are determined by multiplying the estimated future net
cash flows attributable to the combined interests of the Partnership and the
Working Interest Owner by a factor of 90 percent (the Partnership's Royalty).
The resulting amount is then multiplied by a factor of 99.9 percent reflecting
the Trust's interest in the Partnership. Future net cash flows also include an
estimate of the proceeds to be received from underdelivered gas (see Note 5
above) and give consideration to the cost carryforward at December 31, 1999 (see
Note 1 above).

It is emphasized that this supplementary information represents estimates
which may be imprecise, and extreme caution should accompany its use and
interpretation. The estimates were based on various assumptions, many of which
are subject to uncertainties, and therefore, the estimates should not be
considered to be a prediction of actual amounts to be paid to the Trustee.
Additionally, as required under FASB's standards, the supplementary information
excludes consideration of anticipated future oil and gas prices and costs, does
not consider discount rates other than 10 percent 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.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED OIL AND GAS
RESERVES:

<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Future cash flows........................................... $-- $-- $--
Discount for estimated timing of cash flows (10 percent
discount rate)............................................ (--) (--) (--)
--- --- ---
Standardized measure of discounted future net cash flows
from proved oil and gas reserves.......................... $-- $-- $--
=== === ===
</TABLE>

CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM
PROVED OIL AND GAS RESERVES:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------
1999 1998 1997
---- ---- ------------
<S> <C> <C> <C>
Discounted future net cash flows, beginning of year....... $-- $-- $ 25,197,000
Royalty proceeds........................................ -- -- --
Changes in prices and other revisions to previous
estimates, including impact of Class A cost
carry-forward(1)..................................... -- -- (27,717,000)
Extensions and discoveries.............................. -- -- --
Accretion of discount................................... -- -- 2,520,000
-- -- ------------
Discounted future net cash flows, end of year............. $-- $-- $ --
== == ============
</TABLE>

- ---------------

(1) Revisions for 1997 reflect the impact of lower oil and gas prices, negative
reserve quantity revisions and the effect of the Class A cost carry-forward.
Approximately $15.0 million of discounted future net cash flows of the
negative revision amounts shown for 1997 are attributable to the cost
carry-forward. See Note 1 under "Proved Oil and Gas Reserves" above.
Accordingly, there was no standardized measure of discounted future net cash
flows from proved oil and gas reserves as of December 31, 1999, 1998 and
1997 attributable to the Trust.

39
<PAGE> 42

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,
1999 and 1998, 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, 1999. 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, 1999 and 1998, and
the royalty proceeds and distributable cash, and changes in trust corpus for
each of the three years in the period ended December 31, 1999, on the cash basis
of accounting described in Note 3.

ARTHUR ANDERSEN LLP

Houston, Texas
March 30, 2000

40
<PAGE> 43

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.

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.

41
<PAGE> 44

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

(a)1. Financial Statements

Reference is made to Item 8 of this Form 10-K.

(a)2. Schedules

Schedules have been omitted because they are not required, not
applicable or the information required has been included elsewhere herein.

(a)3. Exhibits

<TABLE>
<CAPTION>
EXHIBIT
NO.
-------
<C> <S>
4.1* -- Overriding Royalty Conveyance from McMoRan-Freeport Oil
Company to McMoRan Oil & Gas Co. (attached as Annex I to
Exhibit 4.4).
4.2* -- Royalty Trust Indenture for Freeport-McMoRan Oil and Gas
Royalty Trust between Freeport-McMoRan Inc. ("FTX") and
First City National Bank of Houston, as Trustee.
4.3* -- First Amended and Restated Articles of General
Partnership of Freeport-McMoRan Oil and Gas Royalty
Partnership between McMoRan Offshore Management Co. and
First City National Bank of Houston, as Trustee.
4.4* -- Act of Assignment and Assumption and Mortgage from
McMoRan Oil & Gas Co. to FTX.
4.5* -- Act of Assignment and Assumption and Mortgage from FTX to
Freeport-McMoRan Oil and Gas Royalty Partnership (for
omitted attachments see Exhibit 4.4).
27 -- Financial Data Schedule.
</TABLE>

- ---------------

* Incorporated by reference to Exhibits of like designation to the registrant's
Annual Report on Form 10-K for the period ended December 31, 1983.

(b) Reports on Form 8-K

No reports on Form 8-K were filed during 1999.

42
<PAGE> 45

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: CHASE BANK OF TEXAS,
NATIONAL ASSOCIATION, Trustee

By: /s/ PETE FOSTER
----------------------------------
Pete Foster
Senior Vice President and Trust
Officer

March 30, 2000

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.

43
<PAGE> 46

EXHIBIT INDEX

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
4.1* -- Overriding Royalty Conveyance from McMoRan-Freeport Oil
Company to McMoRan Oil & Gas Co. (attached as Annex I to
Exhibit 4.4).
4.2* -- Royalty Trust Indenture for Freeport-McMoRan Oil and Gas
Royalty Trust between Freeport-McMoRan Inc. ("FTX") and
First City National Bank of Houston, as Trustee.
4.3* -- First Amended and Restated Articles of General
Partnership of Freeport-McMoRan Oil and Gas Royalty
Partnership between McMoRan Offshore Management Co. and
First City National Bank of Houston, as Trustee.
4.4* -- Act of Assignment and Assumption and Mortgage from
McMoRan Oil & Gas Co. to FTX.
4.5* -- Act of Assignment and Assumption and Mortgage from FTX to
Freeport-McMoRan Oil and Gas Royalty Partnership (for
omitted attachments see Exhibit 4.4).
27 -- Financial Data Schedule.
</TABLE>

- ---------------

* Incorporated by reference to Exhibits of like designation to the
registrant's Annual Report on Form 10-K for the period ended December 31,
1983.

<ARTICLE> 5
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 896,620
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 896,620
<PP&E> 189,875,741
<DEPRECIATION> (189,875,741)
<TOTAL-ASSETS> 896,620
<CURRENT-LIABILITIES> 896,620
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 896,620
<SALES> 0
<TOTAL-REVENUES> 0
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 0
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 0
<EPS-BASIC> 0
<EPS-DILUTED> 0

</TABLE>