FREEPORT MCMORAN OIL & GAS ROYALTY TRUST, 10-K405, 1999-04-15

FREEPORT MCMORAN OIL & GAS ROYALTY TRUST
10-K405, 1999-04-15
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, 1998

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-8581

Freeport-McMoRan Oil and Gas Royalty Trust
(Exact Name of Registrant as Specified in Its Charter)

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

CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, TRUSTEE 77002
712 MAIN STREET (Zip Code)
HOUSTON, TEXAS
(Address of Principal Executive Offices)

Registrant's telephone number, including area code: (713) 216-5712

Securities registered pursuant to Section 12(b) of the Act:

NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
------------------- ----------------
Units of Beneficial Interest New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
NONE

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

The aggregate market value of the 14,975,390 Units of Beneficial Interest
in Freeport-McMoRan Oil and Gas Royalty Trust held by non-affiliates of the
registrant on March 22, 1999 was approximately $9,359,619 based on the closing
price of the Units on the New York Stock Exchange as reported in The Wall
Street Journal.

As of March 22, 1999, 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
<TABLE>
<CAPTION>

PART I

PAGE
----
<S> <C> <C>
Item 1. Business........................................................... 4
Description of the Trust........................................... 4
Description of the Units........................................... 7
The Royalty Properties and the Royalty............................. 9
Federal Income Tax Considerations.................................. 25
Item 2. Properties......................................................... 26
Item 3. Legal Proceedings.................................................. 26
Item 4. Submission of Matters to a Vote of Unit Holders.................... 26

PART II

Item 5. Market for the Registrant's Units and Related Unit Holder Matters.. 27
Item 6. Selected Financial Data............................................ 27
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.............................................. 28
Item 7a. Quantitative and Qualitative Disclosures About Market Risk......... 30
Item 8. Financial Statements and Supplementary Data........................ 31
Statements of Royalty Proceeds and Distributable Cash:
For the years ended December 31, 1998, 1997, and 1996.............. 31
Statements of Assets, Liabilities and Trust Corpus:
As of December 31, 1998 and 1997................................... 31
Statements of Changes in Trust Corpus:
For the years ended December 31, 1998, 1997, and 1996.............. 31
Notes to Financial Statements...................................... 32
Report of Independent Public Accountants........................... 37
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................... 38

PART III

Item 10. Directors and Executive Officers of the Registrant................. 38
Item 11. Executive Compensation............................................. 38
Item 12. Security Ownership of Certain Beneficial Owners and Management..... 38
Item 13. Certain Relationships and Related Transactions..................... 38

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.... 39
Signature................................................................... 40
</TABLE>

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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
owned by the Trust as of December 31, 1998 and the estimated future net income
of the Trust see the report by Ryder Scott Company Petroleum Engineers hereof,
(ii) financial conditions and results of operations of the Trust, see Item 7
hereof, and (iii) financial statements and supplementary data of the Trust, see
item 8 with special reference to Note 11 hereof.

The combination of a significant increase in the Class A cost
carry-forward and negative reserve quantity revisions, combined with declines in
oil and gas prices received by the Working Interest Owner, 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, 1998. Further, as described
under "Termination of the Trust," the Royalty Trust Indenture entered into
between IMC Global Inc (IMC) and the Trustee (the Trust Indenture) provides that
the Trust must have received $3 million or more in cash during 1998 to avoid
termination. The Trust did not receive $3 million in cash receipts during 1998.
The Trust Indenture provides that the Trustee must sell the Trust's interest in
the Partnership or cause the Partnership to sell the Royalty. At a special
meeting of the holders of the units of beneficial interest in the Trust (the
"Units") held on March 12, 1999, the Unit holders of the Trust approved a
unitholder 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. IMC, the owner of the working interest burdened by the
Trust's royalty interest, 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 has indicated that it will take no action to
approve the amendment until such time as the lawsuit is resolved. The Trustee
will vigorously defend against the lawsuit, but if IMC prevails in its lawsuit,
the amendment will not be effected and the Trustee will endeavor to liquidate
the royalty interest as soon as practicable and terminate the Trust in
accordance with the terms of the Trust Indenture. It is Trustee's intention to
approve the amendment of the Trust Indenture if the lawsuit is resolved in a
manner that permits the Trustee to do so. See "Termination of the Trust."

DESCRIPTION OF THE TRUST

The Units are traded on the New York Stock Exchange under the trading symbol
"FMR." 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 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 included in 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.

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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.

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 (i) 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; (ii) the Royalty can be sold in whole or in part upon approval of
the Unit holders or upon termination of the Trust; and (iii) 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 (i) 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, (ii) to pay or provide for the payment of expenses, charges,
liabilities and obligations of the Trust and (iii) to distribute to Unit holders
the remaining revenues attributable to the Royalty.

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

The Trust has no employees. Administrative functions of the Trust are
performed by the Trustee, which is compensated for its services and reimbursed
for specified charges for transfer agency and distribution functions out of
Trust assets. The Trustee is also entitled to reimbursement for its out-of-
pocket expenses. Because of the passive nature of the Trust assets and the
restrictions on the power of the Trustee to incur obligations, the only
liabilities which the Trustee ordinarily incurs are those for routine
administrative expenses, such as the Trustee's fees and accounting, legal and
other administrative fees. The costs and expenses of the Trust (including the
Trustee's fees) are estimated to approximate $0.4 million for 1999. 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 $1.4 million remained as of December 31, 1998. 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.

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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 is not otherwise 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 is, in its
judgment, necessary or advisable to achieve the purposes of the Trust. The Trust
Indenture provides that cash being held by the Trustee as a reserve for
liabilities or for distribution at the next distribution date will be placed in
interest-bearing accounts or certificates (which may include accounts or
certificates of the bank acting as Trustee), but the Trustee is otherwise
prohibited from acquiring any asset other than the Trust's interest in the
Partnership or engaging in any business or investment activity of any kind
whatsoever. The Trustee may sell or dispose of its interest in the Partnership,
or permit the Partnership to sell or dispose of all or any part of the Royalty,
only as authorized by a vote of the Unit holders upon termination of the Trust
and in certain other limited circumstances. However, the Trust Indenture states
that the Trustee must effect such a sale (without any such vote) 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. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations". 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 has indicated that it will take
no action to approve the amendment until such time as the lawsuit filed by the
Working Interest Owner to prevent the Trustee from approving the amendment is
resolved. The Trustee will vigorously defend against the lawsuit, but if IMC
prevails in its lawsuit, the amendment will not be effected and the Trustee will
endeavor to liquidate the Royalty as soon as practicable and terminate the Trust
in accordance with the terms of the Trust Indenture. See "Termination of the
Trust."

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

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(ii) above, the Trustee will sell the Royalty (or will cause the Partnership to
sell all of the assets of the Partnership). The Trustee will as promptly as
possible distribute the proceeds of any such sales according to the respective
interests and rights of the Unit holders after discharging all of the
liabilities of the Trust and, if necessary, setting up reserves in such amounts
as the Trustee in its discretion deems appropriate for contingent liabilities.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations."

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. The Working Interest Owner 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. The Trustee will vigorously defend against the lawsuit, but if the
Working Interest Owner prevails in its lawsuit, the amendment will not be
effected, and the Trustee will endeavor to sell the Royalty as soon as
practicable for cash to the highest bidder and terminate the Trust in accordance
with the terms of the Trust Indenture. Although the Trustee will endeavor to
sell the Royalty pursuant to procedures intended to maximize the proceeds to the
Trust, the Trustee can give no assurance regarding the amounts, if any, to be
realized as a result of such sale. The Trustee intends to approve the amendment
of the Trust Indenture if IMC's lawsuit is resolved in a manner that permits the
Trustee to do so.

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.

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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 farmout interests in the Royalty Properties and to reduce the
Royalty proportionately. See "THE ROYALTY PROPERTIES AND THE ROYALTY -- General
and -- Production and Drilling Activities." The Working Interest Owner does not
have an obligation to produce any specific amounts of oil and gas from any of
the Royalty Properties. It has the right to abandon any well or lease and, upon
termination of any lease, the portion of the Royalty relating thereto will be
extinguished. The amount of revenues attributable to the Royalty may be
affected by operating agreements and unitization and pooling arrangements. The
realization of the ultimate value of the Royalty is subject to all the risks
associated with exploration on and development of oil and gas properties and to
comprehensive regulation by governmental authorities.

TRANSFER OF THE UNITS

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

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<PAGE> 8

matters, the Federal Energy Regulatory Commission (FERC) is not considered to
be empowered under current judicial decisions to compel refunds of gas price
overcharges from overriding royalty interest owners. It is possible, however,
that laws on such matters may change in the future or that other parties, such
as oil or gas purchasers, might be able to instigate legal action to compel
such refunds from royalty owners and that Unit holders might be treated for
such purpose as royalty owners.

STATE LAW CONSIDERATIONS

It is anticipated, based on the structure of the Trust and the Partnership,
that the Units will be treated for certain state law purposes essentially the
same as other securities, that is, as interests in intangible personal property
rather than as interests in real property. However, in the absence of
controlling legal precedent there is a possibility that under certain
circumstances a Unit holder could be treated as owning an interest in real
property. In that event, the tax, probate, devolution of title and
administration laws of Texas or Louisiana applicable to real property may
apply to the Units, even if held by a person who is not a resident or
domiciliary thereof. Application of such laws could make inheritance and
related matters with respect to the Units substantially more onerous than had
the Units been treated as interests in intangible personal property. In any
event, however, the ownership of Units and realization of income from the
Royalty by a Unit holder may subject such Unit holder to state or local income
or other taxation in the state of the Unit holder's residence or domicile. Unit
holders should consult their legal and tax advisors regarding the applicability
of these considerations to their individual circumstances.

POSSIBLE REQUIREMENT THAT UNITS BE DIVESTED

Although the Trust Indenture imposes no restrictions based on nationality
or other status of the persons or other entities who are eligible to hold
Units, it does provide that if at any time the Trust or Trustee is named as a
party in any judicial or other proceeding which seeks the cancellation or
forfeiture of the Trust's interest in any of the Royalty Properties because of
the nationality or other status of any one or more Unit holders, such Unit
holders may be required to sell their Units according to procedures set forth
in the Trust Indenture.

THE ROYALTY PROPERTIES AND THE ROYALTY

EXPLANATORY NOTE

The Trustee has no responsibility relating to the operations of the Royalty
Properties. The information in this report, relating to the characteristics of
and operations on the Royalty Properties and certain other matters, has been
furnished to the Trustee by the Working Interest Owner.

The information in this report regarding the Royalty Properties should be
read in light of the following: The Royalty was carved out of working interests
owned by FTX at the time of creation of the Trust. References in this
report to "net" wells and acres refer to the sum of the fractional working
interests owned by the Working Interest Owner (from which the Royalty was
carved) in the "gross" wells or acres. References to the percentage of the
working interest owned by the Working Interest Owner are references to the
working interest out of which the Royalty was carved. For example, a reference
to a "50 percent working interest" in a well or lease which is included in a
Royalty Property indicates that the Partnership's net overriding royalty
interest (equal to 90 percent of the Net Proceeds, as defined, from all the
Royalty Properties) burdens half of the total working interest in the well or
lease. Such 50 percent working interest will also be subject to landowners'
royalties and may be subject to other overriding royalty interests and other
burdens which are considered prior to calculations of amounts payable to the
owner of the Royalty. Since the amounts and nature of such burdens vary from
lease to lease, the information presented herein and elsewhere regarding the
Working Interest Owner's percentage of the working interest in any well or
lease cannot be used to calculate precisely the interest attributable to the
Trust in a well or lease. In addition, (i) because operating and capital costs
are taken into consideration in calculating the amounts payable to the owner of
the Royalty and because prices for oil and gas may vary from field to field,
information regarding results of well tests of gross quantities of production
from a given well cannot be used to compute the interest attributable to the
Trust, and (ii) because the Royalty Properties consist of multiple leases in
multiple fields, the interest of the Working Interest Owner in any given well
or lease may not be indicative of the interest attributable to the Trust in the
Royalty Properties.

GENERAL

The map on page 5 shows the location and selected information as of
December 31, 1998 for all of the productive Royalty Properties.

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<PAGE> 9

As of December 31, 1998, there were 18 gross productive oil and gas wells on
8 of the remaining productive Royalty Properties where the Working Interest
Owner retains a working interest.

All Royalty Properties are operated under joint operating agreements by 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 has informed the Trustee that it may conduct further development and
exploratory activities on certain of the Royalty Properties. See "Production and
Drilling Activities" below for a discussion of current development and
exploratory activities on certain of the Royalty Properties.

RESERVES

A study of the proved oil and gas reserves attributable to the Royalty
Properties as of December 31, 1998 has been made by Ryder Scott Company
Petroleum Engineers (Ryder Scott), independent petroleum engineers. 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, 1998, 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
1998, volumes of natural gas sold by other parties pursuant to certain gas
balancing arrangements, transportation cost adjustments, if any and the effect
of the excess Class A cost carry-forward at December 31, 1998. Therefore, the
amounts set forth in the letter are not necessarily indicative of actual amounts
to be received by the Trust or 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,
1998. 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).

10
<PAGE> 10

MAP

11
<PAGE> 11

[RYDER SCOTT LETTERHEAD]

April 1, 1999

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, 1998. 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 ten leases are hereinafter referred to as the "Subject
Properties". All other leases originally subject to the Royalty have either
expired, or have been farmed out, with the working interest owner retaining an
overriding royalty interest burdened by the Royalty. The Working Interest Owner
has assured us that no leases other than these 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 1998
hydrocarbon prices were used in the preparation of this report as required by
SEC guidelines; however, actual future prices may vary significantly from
December 1998 prices. Therefore, volumes of reserves actually recovered and
amounts of income actually received may differ significantly from the estimated
quantities presented in this report. The results of this study are summarized as
follows:

12
<PAGE> 12
Freeport-McMoRan Oil and Gas Royalty Trust
April 1, 1999
Page 2

SEC PARAMETERS
Estimated Net Reserve and Income Data
Freeport-McMoRan Oil and Gas Royalty Partnership
As of December 31, 1998

<TABLE>
<CAPTION>
Total
Proved
----------
<S> <C>
Remaining Reserves
Oil/Condensate - Barrels 91,322
Gas - MMCF 1,422

Future Net Income (FNI)
1999 $1,008,223
2000 1,187,521
2001 685,205
----------
Sub-Total (1999-2001) $2,880,949
Remaining 2,944,719
----------
Total $5,825,668

Discounted FNI @ 10% $4,189,518
(Compounded Annually)
</TABLE>

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

Liquid hydrocarbons are expressed in standard 42 gallon
barrels. All gas volumes are sales gas expressed in millions of cubic feet
(MMCF) at 60 degrees Fahrenheit and 14.73 pounds per square inch absolute.

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

The future net income attributable to the Royalty was
estimated on a yearly basis from a projection of the combined Working Interest
Owner and Partnership future net income. Combined future net income values were
calculated by deducting operating expenses and capital costs from the future
gross revenue of the combined interests. Only those expenses and capital costs
necessary for the development and production of proved reserves were taken into
consideration. 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.

13
<PAGE> 13
Freeport-McMoRan Oil and Gas Royalty Trust
April 1, 1999
Page 3

More than a sufficient amount has been accrued as of December
31, 1998 to pay for the unescalated estimated abandonment costs attributable to
the Royalty; therefore, using SEC pricing and cost parameters, it is anticipated
that no future accruals will be necessary. Furthermore, a reimbursement is
included as Partnership income in the year after depletion and abandonment of
the Subject Properties. This reimbursement is equal to the amount by which
current unspent accruals exceed anticipated unescalated future abandonment
costs.

The future net income calculated for the Partnership is before
the deduction of state and federal income taxes and does not include any
adjustment for cash on hand or undistributed income. No attempt has been made to
quantify or otherwise account for any accumulated gas imbalances that may exist.
In accordance with Securities and Exchange Commission regulations, discounted
future net income values shown above were calculated by discounting the future
net income at the rate of 10 percent per year; however, such rate is not
necessarily the most appropriate discount rate. At the request of the Working
Interest Owner, annual compounding was used in the computation of discounted
future net income. Discounted future net income should not be construed as Ryder
Scott Company's estimate of fair market value since no consideration was given
to the additional factors that influence the prices at which oil and gas
properties are bought and sold, such as taxes on income, allowance for return on
investments and business risks.

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

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

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

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

RESERVE DEFINITIONS

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

14
<PAGE> 14
Freeport-McMoRan Oil and Gas Royalty Trust
April 1, 1999
Page 4

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 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

15
<PAGE> 15
Freeport-McMoRan Oil and Gas Royalty Trust
April 1, 1999
Page 5

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.

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, 1998 and these prices were held constant except for known and
determinable escalations. In accordance

16
<PAGE> 16
Freeport-McMoRan Oil and Gas Royalty Trust
April 1, 1999
Page 6

with Securities and Exchange Commission guidelines, changes in liquid and gas
prices subsequent to December 31, 1998 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 1998, 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, 1998 were not considered in this study.

Gas

The Working Interest Owner has furnished us with gas prices in
effect at December 1998 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 operating, development, abandonment, and overhead costs
used in this study were furnished by the Working Interest Owner. The operating
costs are based on the operating expense reports of the Working Interest Owner,
or on operating expense estimates furnished by the Working Interest Owner for
properties not yet on production. The development and abandonment costs are
based on authorizations for expenditure for the proposed work, or on actual
costs for similar projects.

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

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 1998.

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.

17
<PAGE> 17
Freeport-McMoRan Oil and Gas Royalty Trust
April 1, 1999
Page 7

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

Very truly yours,

RYDER SCOTT COMPANY
PETROLEUM ENGINEERS

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

KAW/sw

18
<PAGE> 18
Of the total discounted present value of future net cash flows attributable
to the Royalty estimated by Ryder Scott, approximately 40.8 percent was
accounted for by West Cameron Block 498, 30.5 percent by Vermilion 58 and 16
percent 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, 1998. Thus, amounts received
by the Working Interest Owner after November 30, 1998 attributable to
production during 1998 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 1998. The Working Interest Owner has estimated that if Ryder
Scott had taken into account the 1999 Gross Proceeds from 1998 production, the
total estimated future net cash flow and the discounted present value of such
estimate in the Ryder Scott letter would have been approximately $.8 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

19
<PAGE> 19

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 $4 million per year, or of the Partnership, which
are expected to be minimal. Additionally, Ryder Scott did not take into account
the Class A cost carry-forward of $25.6 million net to the Trust, as of December
31, 1998.

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 $25.6 million to the Trust at December 31, 1998.
Amounts equal to 90 percent of the Net Proceeds for any month are payable by the
Working Interest Owner to the Partnership on the last business day of the
following month.

"Gross Proceeds" means the amount received from sales of hydrocarbons
produced from the Royalty Properties that are attributable to the working
interests subject to the Royalty, net of lessor royalties and production
payments existing at the time of the creation of the Trust which burdened the
Royalty Properties prior to the effective date of the Conveyance, and subject
to farmouts and certain other adjustments.

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

The Working Interest Owner is entitled to accrue certain estimated future
costs in accordance with a formula set forth in the Conveyance. The accrual
formula provides that, for any month and with respect to a specific item of
future costs, the Working Interest Owner may include in its costs an amount
calculated by multiplying (i) the excess of (a) the total estimated amount of
such item of future cost over (b) the aggregate amount accrued in previous
months with respect to such item, by (ii) 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 (i) costs incurred to discover or
develop minerals on certain leases, (ii) any monthly future cost accruals, (iii)
such costs that were not covered by proceeds in the previous month and (iv)
interest thereon.

20
<PAGE> 20

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 (i) 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 (ii) certain events of
bankruptcy or insolvency relating to the Working Interest Owner.

CERTAIN FACTORS AFFECTING DISTRIBUTIONS; CONFLICTS OF INTEREST

The amount of cash payable on account of the Royalty, and thus the amount of
cash available for distribution to Unit holders, depends upon future sales 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. The minimum volume, net to the Working Interest
Owner, for 1999 will be 697,010 barrels, declining to 126,449 barrels in 2007.
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 will be included in the Class A cost carry-forward in
1999. Based on 1999 projected production the minimum delivery volumes will not
be met in 1999. However, should production exceed the 1999 minimum, the Working
Interest Owner is entitled to receive transportation without pay, up to the
cumulative prior underdelivered volumes.

PRODUCTION AND DRILLING ACTIVITIES

Of the ten remaining Royalty Properties, eight are currently producing. For
a discussion concerning the oil and gas production from such properties in 1998
as well as information concerning drilling activities on such properties during
1998, 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 (other
than Vermilion Block 21/22 and West Cameron Block 65), that party's right to
receive a share of production from such development well is suspended until
such time as the participating parties have recovered an amount ranging from
approximately 400 percent to approximately 600 percent of the cost of drilling,
testing, completing and equipping the development well. With respect to
Vermilion Block 21/22 and West Cameron Block 65, the non-consenting party must
assign all its

21
<PAGE> 21

working interest in the previously designated development area, subject to
retention by that party of its interest in wells previously drilled in such
area and an overriding royalty interest in all subsequent wells drilled in such
area. The loss of revenues from any failure by the Working Interest Owner to
participate in a development well would reduce the aggregate proceeds from the
Royalty in the event such development well produced in paying quantities in
excess of the cost of drilling, testing, completing and equipping such well.
Neither the Partnership nor the Trustee is entitled to compel the Working
Interest Owner to participate in any operation on a Royalty Property if the
Working Interest Owner makes a "non-consent" election with respect thereto.

The Working Interest Owner may choose to conduct exploration and
development operations on one or more of the Royalty Properties without the
participation of some, or all, of the other joint interest owners by assuming
the obligations of non-consenting parties. If the Working Interest Owner elects
to assume a share of the costs associated with any non-consenting party's
interest, such costs and the production, if any, attributable to the assumption
of such interest will not be taken into account in the computation of the Net
Proceeds.

The receipt of revenues from the sale of gas production could be delayed
for extended periods of time by gas balancing arrangements which allow other
joint interest owners to take gas production in excess of their ownership
percentage if the Working Interest Owner is unable to take all or a part of its
share of production. On the other hand, if the Working Interest Owner takes gas
production in excess of its ownership percentage, the revenues attributable to
the excess production will not be included in Gross Proceeds except to the
extent such excess is offset by prior or subsequent deficits created after
October 1, 1983 by the Working Interest Owner taking less than its ownership
percentage share of gas production. If a source of gas supply depletes before
the Working Interest Owner has balanced all deficits created after October 1,
1983 with excess production volumes, the Working Interest Owner will be
entitled to receive a cash settlement for such deficits from those joint
interest owners with excess production totals. All such settlement receipts
will be included in Gross Proceeds.
See "Reserves" above.

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 1998 was 31.3 percent lower than the
average price received during 1997. Oil prices can be expected to continue to
exhibit volatility as a result of such factors as the unstable situation in the
Middle East, future actions of OPEC and future changes in worldwide economic
conditions.

The Working Interest Owner currently sells gas at spot market prices from
blocks that were previously subject to long-term contracts with Transco, but
which contracts were terminated by the Working Interest Owner at the end of
1987 and the beginning of 1988 pursuant to the provisions of such contracts.

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 will be included in
the Class A cost carryforward in 1999. The minimum volume, net to the Working
Interest Owner, for 1999 will be 697,010 barrels, declining to 126,449 barrels
in 2001. Based on 1999 projected production the minimum delivery volumes will
not be met in 1999. However, should production exceed the 1999 minimum, the
Working Interest Owner is entitled to receive transportation without pay up to
the cumulative prior underdelivered 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 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

22
<PAGE> 22

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.

23
<PAGE> 23

Additional proposals and proceedings that might affect the natural gas
industry are considered from time-to-time by Congress, the FERC, state
regulatory bodies, and the courts. The Working Interest Owner cannot predict
when or if any such proposals might become effective, or their effect, if any,
on the Trust. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.

Environmental Regulation. The Working Interest Owner's oil and gas
activities on the Royalty Properties are subject to existing federal, state and
local laws and regulations relating to health, safety, environmental quality
and pollution control. The Working Interest Owner has advised the Trustee that
it believes that its operations and facilities are in general compliance with
applicable health, safety, and environmental laws and regulations. Events in
recent years have, however, heightened environmental concerns about the oil and
gas industry generally, and about offshore operations in particular. As a
consequence, offshore oil and gas leases have become subject to more extensive
governmental regulation, including regulations that may in certain
circumstances impose absolute liability upon lessees for cost of removal of
pollution and for pollution and natural resource damages resulting from their
operations, and that may result in assessment of civil or criminal penalties
against lessees, or even suspension or cessation of operations in the affected
areas. Although the Working Interest Owner has advised the Trustee that current
environmental regulation has not had a material adverse effect on the Working
Interest Owner's present method of operations, the impact of changes in
environmental laws, such as stricter environmental regulation and enforcement
policies, cannot be predicted at this time.

The Oil Pollution Act of 1990 (OPA) and regulations promulgated pursuant
thereto impose a variety of obligations on "responsible parties" with respect
to the prevention of oil spills and liability for damages resulting from such
spills. A "responsible party" includes the owner or operator of a facility,
pipeline or vessel. For offshore facilities, the responsible party is the
lessee or permittee or holder of a right of use and easement (granted under
applicable state law or OCSLA) of the area in which the offshore facility is
located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages, including natural resource
damages. While liability limits apply in some circumstances, a responsible
party for an Outer Continental Shelf facility must pay all spill removal costs
incurred by a federal, state or local government. The OPA establishes a
liability limit (subject to indexing) for offshore facilities of all removal
costs plus $75,000,000. A party cannot take advantage of liability limits if
the spill was caused by gross negligence or willful misconduct or resulted from
violation of a federal safety, construction, or operating regulation. If the
party fails to report a spill or to cooperate fully in the cleanup, liability
limits likewise do not apply. Few defenses exist to the liability imposed by
OPA.

The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover a substantial portion of
environmental clean-up and restoration costs that could be incurred by
governmental entities in connection with an oil spill. Other requirements
imposed by the OPA include the preparation of an oil spill contingency plan.
The Working Interest Owner has advised the Trustee that it has in place
appropriate spill contingency plans and has established adequate proof of
financial responsibility for its offshore facilities. A failure to comply with
ongoing requirements or 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

24
<PAGE> 24

products and circumstances under which they were created. In addition,
legislation has been proposed in Congress from time to time that would
reclassify certain oil and gas exploration and production wastes as "hazardous
wastes," which would make the reclassified wastes subject to much more
stringent handling, disposal and clean-up requirements under the Resource
Conservation and Recovery Act. Any reclassification of oil and gas exploration
and production wastes from non-hazardous to hazardous could have a significant
impact on the operating costs of the Working Interest Owner, as well as the oil
and gas industry in general. Initiatives to further regulate the disposal of
oil and gas wastes are also pending in certain states, and these various
initiatives could have a similar impact on the Working Interest Owner.

TITLE TO PROPERTIES

The Conveyance is subject to customary interests and burdens, to the terms
and provisions of the underlying leases, to liens and other provisions of
farmout, operating, pooling and unitization agreements and to minor
encumbrances, easements and restrictions. The Royalty Properties are also
subject to the OCSLA, the regulations promulgated thereunder and possibly
certain provisions of the laws of the adjacent states. The Conveyance contains
a special warranty of title in which the Company warranted title to the Royalty
against persons claiming by, through or under the Company, but not otherwise.

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 prior to December 22, 1997, when IMC became FTX's
successor. See "Description of the Trust." 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

25
<PAGE> 25

exchange of Units, other than through a broker, the partnership is required to
notify the Service of any such sale or exchange (of which it has notice) of a
partnership interest after December 31, 1984, and to report the name and
address of the transferee and the transferor who were parties to such
transaction, along with all other information required by applicable Treasury
regulations. The partnership must also provide this information to the
transferor and the transferee. If the partnership fails to furnish any such
notification, it may be subjected to a penalty of $50 per failure, up to an
annual maximum of $100,000. Final Treasury regulations exempt partnerships from
the requirement to report any sales which are reported by a broker on Form
1099-B.

The Code provides that depletion deductions subject to recapture under
Section 1254 of the Code constitute "unrealized receivables" within the meaning
of Section 751 of the Code. Section 1254 of the Code provides that for property
placed in service by a taxpayer after December 31, 1986, depletion deductions
which reduce the adjusted basis of such property must be recaptured as ordinary
income upon a disposition of the property (to the extent gain is recognized on
such disposition). It is unclear whether this recapture provision applies to
any portion of the depletion claimed with respect to the Royalty (placed in
service in 1983 by the Partnership) in the case of Units acquired after
December 31, 1986. The Service has not issued any regulations or other
pronouncements to indicate its interpretation of these recapture provisions as
they might affect the transfer of partnership interests. Accordingly, Unit
holders disposing of Units acquired after December 31, 1986 (other than through
a broker) may be required to notify the Trustee in writing of such disposition
and provide the Trustee with the Unit holder's name, address, taxpayer
identification number and the date of the disposition. Failure to so notify the
Trustee may subject such a Unit holder, as well as the Trust and the
Partnership, to the above-described penalties. Without 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.

At a special meeting of the Unit holders held on March 12, 1999, the Unit
holders of the Trust approved a unitholder 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 both the approval of the Unit holders
and the written approval of the Trustee. On March 3, 1999, the Working Interest
Owner filed a Petition for declaratory judgment, Specific Performance and
Injunctive Relief in the District Court for the 165th Judicial District of
Harris County, Texas against the Trustee. The Petition asserts that the Working
Interest Owner is a third-party beneficiary of the Trust, that extending the
life of the Trust will cause the Working Interest Owner irreparable injury, and
that approval by the Trustee of the amendment would constitute a violation of
the Trust Indenture and a violation of the rights of the Working Interest Owner
as a third-party beneficiary of the Trust. The Petition seeks to enjoin the
Trustee from approving the amendment of the Trust Indenture and to compel the
Trustee to liquidate the Trust's interest in the Partnership, or cause the
Partnership to liquidate the Royalty, as soon as possible. The Trustee intends
to contest vigorously the allegations in the complaint.

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 1998.

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<PAGE> 26

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S UNITS AND RELATED UNIT HOLDER MATTERS.

Freeport-McMoRan Oil and Gas Royalty Trust Units are traded on the New York
Stock Exchange under the symbol "FMR". At March 22, 1999, 14,975,390 Units were
outstanding and held of record by 9,428 Unit holders.

The high and low sales prices of the Units as reported on the New York
Stock Exchange and distributable cash per Unit for each quarterly period of
1997 and 1998 were:

<TABLE>
<CAPTION>
UNITS OF
BENEFICIAL
INTEREST DISTRIBUTABLE
QUARTER ----------------------- CASH PER
ENDED HIGH LOW UNIT
------ ---- --- -------------
<S> <C> <C> <C>
Mar. 31, 1997 ............................ 4.00 2.50 --
Jun. 30, 1997 ............................ 3.63 2.00 --
Sept. 30, 1997 ........................... 3.69 2.00 --
Dec. 31, 1997 ............................ 3.56 2.19 --
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 --
</TABLE>

Distributable cash, if any, 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 1998.

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,
---------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Royalty proceeds(1) ..................... $ -- $ -- $ -- $5,235,068 $2,551,586
Distributable cash(1) .................... -- -- -- 4,662,081 --
Distributable cash per
Unit ................................... -- -- -- 0.31130 --

DECEMBER 31,
---------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Cash ...................................... $1,406,603 $1,705,582 $1,983,571 $2,300,979 $1,977,583
Total assets .............................. 1,406,603 1,705,582 2,166,784 2,484,192 2,190,501
Distributions payable ..................... -- -- -- -- --
Trust corpus .............................. -- -- 183,213 183,213 212,918
</TABLE>
- ----------

(1) Includes $4.3 million and $2.4 million in 1995 and 1994, respectively,
related to various gas contract settlements.

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

27
<PAGE> 27

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

There was a significant increase in the Class A cost carryforward during 1998,
and declines in oil and gas prices received by the Working Interest Owner at
December 31, 1998 from those received at December 31, 1997. There were no proved
oil and gas reserve quantities and related discounted future net cash flows
attributable to the Trust at December 31, 1998 or 1997. 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, 1998, 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 carryforward. See
Note 1 to the Financial Statements. The information from the Working Interest
Owner indicates that the Royalties may have little or no value, based on the net
present value of reserves determined as a result of the independent review. The
Trust Indenture provides that the Trustee must sell the Trust's interest in the
Partnership, or cause the Partnership to sell the Royalty, if the Trust receives
less than $3 million in cash receipts in each of three consecutive years. The
Trust received no cash receipts in 1996, 1997 or 1998. Therefore, unless the
amendment of the Trust Indenture approved by the Unit holders is effected, the
Trustee will endeavor to effect such sale. 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. The Working Interest Owner has filed a declaratory
judgment action seeking to enjoin the Trustee from approving the amendment. The
Trustee will take no action to approve the amendment until such time as the
lawsuit is resolved. The Trustee will vigorously defend against the lawsuit, but
if the Working Interest Owner prevails in its lawsuit, the amendment will not be
effected and the Trustee will endeavor to sell the Royalty as soon as
practicable for cash to the highest bidder and terminate the Trust in accordance
with the terms of the Trust Indenture. Although the Trustee will endeavor to
offer the Royalty pursuant to procedures intended to maximize the proceeds to
the Trust, the Trustee can give no assurance regarding the amounts, if any, to
be realized as a result of such offer. It is the Trustee's intention to approve
the amendment if the lawsuit is resolved in a manner that permits the Trustee to
do so. See "Termination of the Trust."

RESULTS OF OPERATIONS

There were no cash distributions to Unit holders during 1998, 1997 and
1996. No cash distributions were made during 1998, 1997 and 1996, because of
capital expenditures and lower gas and oil revenues in 1996 and 1997. During
1998, total costs exceeded Gross Proceeds by approximately $9.1 million,
primarily because of the capital costs incurred to drill and evaluate West
Cameron Blocks 498. As a result, the Class A cost carry-forward increased to
$25.6 million net to the Trust as of December 31, 1998. 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,
-------------------------------------------------------
1998 1997 1996
------------- ------------ -------------
<S> <C> <C> <C>
Gross Proceeds(1) $ 11,247,539 $ 2,804,130 $ 3,810,791
Total costs(2) (20,342,923) (19,446,762) (4,489,202)
Excess Class A cost carry-forward(3) 9,095,384 16,642,632 678,411
------------ ------------ ------------
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 (371,133) (356,880) (398,134)
------------ ------------ ------------
(371,133) (356,880) (398,134)
------------
Interest earned 72,154 78,890 80,727
Reserve for future Trust expenses(4) 298,979 277,990 317,407
------------ ------------ ------------
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 $1,954,000, $724,370 and $207,662
respectively.

28
<PAGE> 28

(3) Represents Class A costs incurred 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:

YEARS ENDED DECEMBER 31,
--------------------------------
1998 1997 1996
---------- ---------- ---------
<S> <C> <C> <C>
Natural Gas
Revenues (in millions)..................... $ 4.9 $ 1.5 $ 2.4
Sales volumes (in billion cubic feet)...... 2.1 0.6 1.0
Average realization (per thousand cubic
feet).................................... $ 2.28 $ 2.53 $ 2.42
Oil
Revenues (in millions)..................... $ 6.3 $ 1.3 $ 1.4
Sales volumes (in thousands of barrels) 449.0 65.0 74.0
Average realization (per barrel)........... $ 14.13 $ 20.58 $ 18.80
</TABLE>

Revenues and volumes for oil and gas during 1998 increased substantially
over 1997 and 1996 primarily reflecting the increased development and subsequent
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 has increased to nine by the end of 1998. The 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. At year end 1998, the field was
producing approximately 5.2 Mmcf per day and 700 barrels per day net to the
Working Interest Owner. Production has rapidly declined during the first three
months of 1999 and is far below expectations due primarily to mechanical
problems and well performance. The operator plans remedial action on one well in
April 1999 and has submitted an AFE for approximately $60 thousand net to the
Working Interest Owner. Additionally, oil and gas volumes for 1997 and 1996 were
impacted by normal production declines. Revenues during 1997 and 1996 benefited
from an increase in average realizations reflecting the rise in natural gas and
oil market prices during these years. Gas volumes include an additional net
underdelivery of (0.1) bcf in 1998 and a make-up of gas sold under balancing
agreements totaling 0.2 bcf and 0.1 bcf in 1997 and 1996, respectively.

Costs consist of the following (in millions):

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------
1998 1997 1996
--------- --------- --------
<S> <C> <C> <C>
Lease operating expenses......................... $ 3.7 $ 1.0 $ 2.2
Exploration and development costs................ 14.2 17.6 1.6
Interest ........................................ 2.0 0.7 0.2
Other............................................ 0.4 0.1 0.5
----- ----- -----
$20.3 $ 19.4 $ 4.5
===== ===== =====

</TABLE>

Lease operating expenses for 1998 increased from 1997 and 1996 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 and
were consistent between 1996 and 1995. Exploration and development costs
primarily consist of costs incurred to explore and develop West Cameron Blocks
498 and 215 in 1997, as described below, and Breton Sound Block 55 and
Vermilion Block 58 in 1996. Exploration and development costs in 1995 included
the drilling of two exploratory wells at West Cameron Block 498. Interest is
accrued on cumulative costs in excess of gross proceeds with interest at the
prime rate (as defined in the conveyance), compounded monthly. Abandonment
costs were accrued each year based on the estimate of costs required to abandon
the Trust's properties and are estimated to be fully accrued -- see Note 9.

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 will be included in
the Class A cost carry-forward in 1999. Based on 1999 projected production the
minimum delivery volumes will not be met in 1999. However, should production
exceed the 1999 minimum the Working Interest Owner is entitled to receive
transportation without pay up to the cumulative prior underdelivered volumes.

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 remainder of 1997 and early
1998. An auxiliary platform was set in October 1997, with production facilities
capable of handling 55 million cubic feet (Mmcf) 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, 1998, West Cameron Block 498 had 9 development wells
producing. The average daily production relating to revenue received by the
Trust from this field during 1998 was approximately 1,486.5 barrels of oil per
day and 4.8 Mmcf of gas per day. 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 1998,
the field was producing approximately 5.2 Mmcf per day 700 barrels per day net
to the Working Interest Owner. Oil production has rapidly declined during the
first three months of 1999. This is due primarily to mechanical and well
performance on one well. However the operator of West Cameron 498 will conduct
remedial action to attempt to return the field to production expectations. Total
capital expenditures of the Working Interest Owner during 1998 were
approximately $12.9 million for West Cameron 498, in which the Working Interest
Owner owns a 23.1 percent working interest and a 19.2 pecent net revenue
interest prior to taking into account the Trust's Royalty interest. The
operators have not presented the Working Interest Owner with any further
exploration or development plans for 1999 therefore, there are no exploration
and development costs budgeted for 1999.

29
<PAGE> 29

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 at December 31, 1998.

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.

The operators have not presented the Working Interest Owner with any further
exploration or development plans for 1999 therefore, there are no exploration
and development costs budgeted for 1999. However the operator of West Cameron
498 will conduct remedial action to attempt to return the field to production
expectations.

Estimated future abandonment costs, based on current laws and regulations,
are accrued over the life of the Trust's properties (see Note 9). During the
third quarter of 1996, the Working Interest Owner assigned its interest in East
Cameron Block 336 to a co-owner, free and clear of the Royalty, subject to the
conditions contained in the agreement. The Working Interest Owner paid $0.2
million for abandonment costs to the co-owner and the co-owner assumed all
additional abandonment obligations under the lease. The completion of this
assignment resulted in a reduction of estimated future abandonment costs
totaling approximately $0.7 million, net to the Trust. As of December 31, 1998,
the estimated remaining aggregate abandonment costs to be incurred for all of
the Trust's properties totaled $9.5 million net to the Trust, on an escalated
basis, 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 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 approximately $1.4 million
remained at December 31, 1998.

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 cash receipts last reached $3 million during 1995
and there were no cash receipts in 1996, 1997 or 1998. Additionally, the Class A
cost-carryforward has increased to $25.6 million at December 31, 1998, primarily
from the significant development costs incurred at West Cameron Blocks 498. 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 1998, the Trust will be terminated by one
of the means described under "Termination of the Trust" above, unless the
amendment to the Trust Indenture approved by the Unitholders on March 12, 1999
is implemented. See "Item 1 -- Business -- Description of the Trust --
Termination of the Trust".

IMPACT OF YEAR 2000 COMPLIANCE

Chase Bank of Texas, National Association (Chase) has developed and is
implementing a program to prepare its systems and applications for the Year
2000, including those used to render services to the Trust. In connection
therewith, Chase intends to have such systems and applications capable of
processing, on and after January 1, 2000, date and date-related data consistent
with the functionality of such systems and applications, without a material
adverse effect upon its performance of services as Trustee.

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, "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS."

30
<PAGE> 30

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,
----------------------------------------
1998 1997 1996
----------- ----------- ------------
<S> <C> <C> <C>
Royalty proceeds.............. $ -- $ -- $ --
Trust administrative expenses. (371,133) (356,880) (398,134)
Interest income............... 72,154 78,890 80,727
Reserve for future Trust
expenses................... 298,979 277,990 317,407
----------- ----------- -----------
Distributable cash............ $ -- $ -- $ --
=========== =========== ===========
Distributable cash per Unit... $ -- $ -- $ --
=========== =========== ===========
Units outstanding............. 14,975,390 14,975,390 14,975,390
=========== =========== ===========
</TABLE>

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1998 1997
------------ -------------
ASSETS
<S> <C> <C>
Cash............................................... $ 1,406,603 $ 1,705,582
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....................................... $ 1,406,603 $ 1,705,582
============= =============

LIABILITIES AND TRUST CORPUS

Reserve for future Trust expenses.................. $ 1,406,603 $ 1,705,582
Trust corpus (14,975,390 Units of Beneficial Interest
authorized, issued and outstanding).............. -- --
------------- -------------
Total liabilities and trust corpus................. $ 1,406,603 $ 1,705,582
============= =============
</TABLE>

STATEMENTS OF CHANGES IN TRUST CORPUS

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Trust corpus, beginning of year.............. $ -- $ 183,213 $ 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.................. $ -- $ -- $ 183,213
========= =========== ============
</TABLE>

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

31
<PAGE> 31

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 that the Trustee is required to sell the Trust's
interest in the Partnership, or cause the Partnership to sell the Royalty, if
the Trust's cash receipts for each of three successive years are less than $3
million, thereby terminating the Trust pursuant to (i) above. There were no cash
receipts were less than $3 million dollars in 1996, 1997, and 1998 and,
therefore, the terms of the Trust Indenture dictate that the Trustee effect such
a sale. However, the Unit holders of the Trust, at a special meeting of the Unit
holders held on March 12, 1999, approved a unitholder 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) has filed
a declaratory judgment action seeking to prevent the Trustee from approving the
amendment. The Trustee has indicated that it will take no action to approve the
amendment until such time as the lawsuit is resolved. The Trustee will
vigorously defend against the lawsuit, but if IMC prevails in its lawsuit, the
amendment will not be effected and the Trustee will endeavor to sell the Royalty
as soon as practicable for cash to the highest bidder and terminate the Trust in
accordance with the terms of the Trust Indenture. See "Termination of the
Trust." The Trustee will as promptly as possible distribute the proceeds of any
such sales according to the respective interests and rights of the Unit holders
after discharging all of the liabilities of the Trust and, if necessary, setting
up reserves in such amounts as the Trustee in its discretion deems appropriate
for contingent liabilities. As of December 31, 1998, this Class A cost
carry-forward was $25.6 million. This cost carry-forward must be recouped by the
Working Interest Owner before any distribution may be made to the Trust. There
is no guarantee that the sale of the royalty or future production would result
in proceeds in excess of the cost carry-forward. As a result, whether or not the
Trust is terminated there is a high likelihood that there will be no further
distributions to the Trust.

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).

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Trust's financial statements, which reflect the Trust's 99.9 percent
interest in the Partnership as though the Partnership did not exist, are
prepared on the cash basis of accounting for reporting revenues and expenses.
Therefore, revenues and expenses are recognized only as cash is received or
paid and the associated receivables, payables and accrued expenses are not
reflected in the accompanying financial statements. Under generally accepted
accounting principles, revenues and expenses would be recognized on an accrual
basis.

32
<PAGE> 32

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 10).
Any excess carrying value is reduced and the adjustment is charged directly
against trust corpus. The carrying value of the Royalty was $0 at December 31,
1998 and 1997. 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 10), the remaining carrying value of the Royalty ($183,213) was
charged directly against trust corpus in 1997. 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 $25,626,860 existed as of December 31,
1998. The cost carry-forward is subject to and includes an interest amount at
the prime rate, which totaled $1,756,841 net to the Trust for 1998. 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 for purposes of
calculating the Royalty. In the future, the Working Interest Owner will be
entitled to sell volumes equal to such underproduction or receive cash
settlements. On certain of the Royalty Properties, a cash settlement may be
required, depending on future results, due to the lack of sufficient remaining
reserves from which to makeup any underproduction. As of December 31, 1998, the
unrecovered quantity of gas sold by third parties pursuant to such gas
balancing arrangements since inception of the Trust was approximately 1.4
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.

6. GAS CONTRACT SETTLEMENT

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 $1,406,603 remained as of December 31, 1998. Because of the cumulative
excess Class A cost carry-forward, $298,979 was withdrawn from the expense
reserve during 1998 to pay Trust administrative expenses. There will be tax
consequences to the Unit holders for such reserve as described in Note 8 below.

The funding for this reserve is deposited with Chase Bank of Texas and
invested in Chase Bank of Texas collateralized certificates of deposit. The
average interest rate earned on these funds was 4.5 percent for 1998, 4.3
percent for 1997, and 3.7 percent for 1996.

33
<PAGE> 33

8. FEDERAL INCOME TAX MATTERS

Unit holders were required to report taxable income for the original expense
reserve. The expense reserve established for Trust administrative expenses
described in Note 7 above, however, gives rise to tax deductions as additional
administrative expenses are incurred and paid with funds deposited in the
reserve. During 1998, the amount of deductions exceeded interest income.

9. RESERVE FOR FUTURE ESTIMATED ABANDONMENT COSTS

For purposes of calculating the Royalty, 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 labor and equipment costs 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, operation or
technology. As of December 31, 1998, the estimated remaining aggregate
abandonment costs to be incurred for all of the Trust's properties totaled $9.5
million net to the Trust, on an escalated basis, all of which has been withheld
from distributions to Unit holders. Any further adjustments to estimated
abandonment costs or variances to actual costs will reduce or increase future
distributable cash accordingly.

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 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 will be included in
cost carry-forward in 1999. The minimum volume, net to the Working Interest
Owner for 1999 will be 697,000 barrels, declining to 126,449 barrels in 2007.
Based on 1999 projected production the minimum delivery volumes will not be met
in 1999. However should production exceed the 1999 minimum, the Working
Interest Owner is entitled to receive transportation without pay up to the
cumulative prior underdelivered volumes.

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
future net cash flows, such reserves are necessarily affected by changes in
various economic factors including prices, costs and the level and timing of
capital expenditures on the properties. Therefore, the reserve volume estimates
set forth below are hypothetical and are not comparable to estimates of
reserves attributable to a working interest.

The reserve volume and cash flow amounts set forth below are for the
interest in the Royalty attributable to the Trust, based on the Trust's 99.9
percent interest in the Partnership. Estimates of proved oil and gas reserves
attributable to the Trust's interest are based on reports of Ryder Scott Company
Petroleum Engineers (Ryder Scott). The Ryder Scott report reflected discounted
future net cash flows as of December 31, 1998 of $4,189,518. 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, 1998, 1997 and 1996, approximately, 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 $25.6 million,
$17.4 million and $2.5 million at December 31, 1998, 1997 and 1996,
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. These amounts have not been adjusted for additional amounts due the oil
transporter, if any, in deficiency payments under the transportation contract.
(See Note 10). 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
Unitholders. For purposes of the reserve volume and cash flow amount set forth
below, Ryder Scott considered unescalated estimates of these costs, which is
$1,950,000 less than the escalated amounts. As a result, at December 31, 1998 an
estimated cash inflow of $1,950,000 representing an estimated reimbursement from
the Working Interest Owner, has been reflected in the reserve report upon
completion of the abandonment of the properties. Any reimbursement would offset
the Class A cost carry-forward. 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.

34
<PAGE> 34

<TABLE>
<CAPTION>
1998 1997 1996
----------------- ----------------- -----------------
OIL GAS OIL GAS OIL GAS
--------- ------- -------- -------- -------- ---------
<S> <C> <C> <C> <C> <C>
Proved reserves, beginning of year.... -- -- 804 6,490 603 5,241
Changes in prices and other
Revisions to previous
estimates, including impact of
Class A cost carryforward(1).......... -- -- (746) (5,969) 220 1,788
Extensions and discoveries(2)....... -- -- -- -- 47 360
Production.......................... (58) (521) (66) (899)
---- ------ --- ---- --- ------
Proved reserves, end of year.......... -- -- -- -- 804 6,490
==== ====== === ==== === ======
</TABLE>

- ----------
(1) Estimates of proved reserves are subject to possible change, either upward
or downward, as additional information becomes available. Because the
Royalty is a net profits interest and reserve quantities are estimated
pursuant to a formula based in part on the estimated future net cash flows,
factors other than changes in estimates of gross quantities of reserves
(such as changes in prices and costs) can result in changes in estimates of
reserve quantities attributable to the Trust. The positive revisions in
1996 primarily reflect the impact of higher oil and gas prices. Negative
revisions in 1997 reflect the impact of lower oil and gas prices,
unfavorable drilling results and the effect of the Class A cost
carryforward. Approximately 300,000 barrels and 4,400 million cubic feet of
the negative revision amounts shown for 1997 are attributable to the cost
carryforward, based on the formula discussed above. Consequently, proved
oil and gas reserves at December 31, 1998, based on year-end prices, would
provide estimated future net revenues in an amount less than the Class A
cost carryforward. Accordingly, there were no proved reserves as of
December 31, 1998 attributable to the Trust.

(2) Includes reserves related to West Cameron Block 215 and the Breton Sound
Block 55 No. 4 well in 1996.

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, 1998
(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,
----------------------------------
1998 1997 1996
------ ------------- ------------
<S> <C> <C> <C>
Future cash flows.............................. $ -- $ -- $ 44,031,000
Discount for estimated timing of cash flows
(10 percent discount rate)..................... (--) (--) (18,834,000)
------ ----------- ------------
Standardized measure of discounted future net
cash flows from proved oil and gas reserves.... $ -- $ -- $ 25,197,000
====== ============ ============
</TABLE>

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

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------
1998 1997 1996
-------------- -------------- --------------
<S> <C> <C> <C>
Discounted future net cash flows,
beginning of year....................... $ $25,197,000 $12,296,000
Royalty proceeds........................ -- -- --
Changes in prices and other revisions
to previous estimates, including
impact of Class A cost
carryforward(1)...................... -- (27,717,000) 9,911,000
Extensions and discoveries(2)........... -- -- 1,760,000
Accretion of discount................... 2,520,000 1,230,000
----------- ----------- -----------
Discounted future net cash flows, end of
year.................................... $ -- $ -- $25,197,000
=========== =========== ===========
</TABLE>

35
<PAGE> 35

- ----------
(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
carryforward. Approximately $15.0 million of discounted future net cash
flows of the negative revision amounts shown for 1997 are attributable to
the cost carryforward. 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, 1997
attributable to the Trust.

(2) Includes increased reserves at West Cameron Block 215 and the addition of
the Breton Sound Block 55 No. 4 well in 1996.

36
<PAGE> 36

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 statements of assets, liabilities and trust corpus of
Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 1998 and 1997,
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, 1998. These financial statements are the responsibility of the
Trustee and the General Partner of the Royalty Partnership. Our responsibility
is to express an opinion on these financial statements based on our audits.

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

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

In our opinion, the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of
Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 1998 and 1997,
and the royalty proceeds and distributable cash, and changes in trust corpus
for each of the three years in the period ended December 31, 1998, on the cash
basis of accounting described in Note 3.

ARTHUR ANDERSEN LLP

New Orleans, Louisiana,
April 5, 1999

37
<PAGE> 37

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 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.

38
<PAGE> 38

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

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

(b) REPORTS ON FORM 8-K

No reports on Form 8-K were filed with the Securities and Exchange
Commission during the fourth quarter of 1998.

39
<PAGE> 39

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

April 15, 1999

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.

40
<PAGE> 40
EXHIBIT INDEX

- -----------
* 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.

41
<PAGE> 41

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

Freeport-McMoRan Oil and Gas Royalty Trust
Chase Bank of Texas, National Association, Trustee
Attention: Corporate Trust Department
600 Travis, Suite 1150
Houston, Texas 77002

<ARTICLE> 5
<MULTIPLIER> 1

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 1,406,603
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,406,603
<PP&E> 189,875,741
<DEPRECIATION> (189,875,741)
<TOTAL-ASSETS> 1,406,603
<CURRENT-LIABILITIES> 1,406,603
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 1,406,603
<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-PRIMARY> 0
<EPS-DILUTED> 0

</TABLE>