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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, 1997
[ ] 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
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 20, 1998 was approximately $40,246,000 based on the closing
price of the Units on the New York Stock Exchange as reported in The Wall Street
Journal.
As of March 20, 1998, 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
PART I
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PAGE
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Item 1. Business..................................................... 1
Description of the Trust.................................... 1
Description of the Units.................................... 4
The Royalty Properties and the Royalty...................... 6
Federal Income Tax Considerations........................... 24
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 8. Financial Statements and Supplementary Data................. 32
Statements of Royalty Proceeds and Distributable Cash:
For the years ended December 31, 1997, 1996, and 1995...... 32
Statements of Assets, Liabilities and Trust Corpus:
As of December 31, 1997 and 1996........................... 32
Statements of Changes in Trust Corpus:
For the years ended December 31, 1997, 1996, and 1995...... 32
Notes to Financial Statements.............................. 33
Report of Independent Public Accountants................... 39
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................... 40
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 40
Item 11. Executive Compensation...................................... 40
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................. 40
Item 13. Certain Relationships and Related Transactions.............. 40
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K........................................................ 41
Signature............................................................. 42
</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 owned by the Trust as of
December 31, 1997 and the estimated future net income of the Trust, see the
report by Ryder Scott Company Petroleum Engineers contained on pages 10 through
15 hereof, (ii) financial condition and results of operations of the Trust, see
Item 7 appearing on pages 28 through 31 hereof and (iii) financial statements
and supplementary data of the Trust, see Item 8 appearing on pages 32 through
38, with special reference to Note 10 thereto appearing on pages 35 through 37
hereof.
LIKELIHOOD OF TRUST TERMINATION
As discussed in "Management's Discussion & Analysis and Results of
Operations" and Notes 1, 3 and 10 to the financial statements included elsewhere
in this Annual Report on Form 10-K, several factors occurring during 1997 have
increased the likelihood of the Trust being terminated. The combination of a
significant increase in the Class A cost carryforward and negative reserve
quantity revisions during 1997, combined with declines in oil and gas prices
received by the Working Interest Owner at December 31, 1997 from those received
at December 31, 1996, 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, 1997. As a result, the remaining unamortized carrying
value of the Royalty was charged directly against Trust corpus. Further, as
described under "Termination of the Trust," the Trust must have $3 million or
more in cash receipts during 1998 to avoid termination. Based on current
circumstances, it is unlikely that cash receipts to the Trust will total $3
million or more in 1998, in which case the Trustee would be required to sell the
Trust's interest in the Partnership or cause the Partnership to sell the
Royalty.
DESCRIPTION OF THE TRUST
Units of beneficial interest (the Units) in the Trust are traded on the New
York Stock Exchange under the trading symbol "FMR." The term "Company," as used
herein, includes IMC Global Inc. (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" includes IMC, and the successors and assigns of its oil and gas
working interests to the extent the context requires.
The Units are not an interest in or an obligation of the Company, the
Working Interest Owner or any successor Working Interest Owner although they
represent indirect interests in the Royalty Properties (as defined below). The
following information and the information set forth under "DESCRIPTION OF THE
UNITS" are subject to the detailed provisions of the Royalty Trust Indenture
entered into between IMC and the Trustee (the Trust Indenture) and the First
Amended and Restated Articles of General Partnership of Freeport-McMoRan Oil and
Gas Royalty Partnership (the Partnership) entered into between McMoRan Offshore
Management Co., formerly an indirect wholly owned subsidiary of FTX, and the
Trustee (the Partnership Agreement). The Trust Indenture and the Partnership
Agreement are among the exhibits to this report. The provisions governing the
Trust and the Partnership are complex and extensive, and no attempt has been
made below to describe all of such provisions. The following is a general
description of the basic framework of the Trust and the Partnership, and
reference is made to the Trust Indenture and the Partnership Agreement for
detailed provisions concerning the Trust and the Partnership.
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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), a net overriding royalty interest (the Royalty) was
transferred to FTX 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 (1) the Trustee cannot engage in any business or
investment activity and cannot acquire any asset other than its interest in the
Partnership and cash being held for payment of liabilities or distribution to
Unit holders; (2) the Royalty can be sold in whole or in part upon approval of
the Unit holders or upon termination of the Trust; and (3) any cash
distributions to the Unit holders are made by the Trustee quarterly in January,
April, July and October of each year.
The Trust Indenture provides that Unit holders take their Units subject to
the provisions of the Trust Indenture, which gives the Trustee only such rights
and powers as are necessary and proper for the conservation and protection of
the Royalty. Accordingly, the Trustee has no responsibility or authority with
respect to the operation of the Royalty Properties. The Trust is a passive
trust, and the Trust Indenture requires the Trustee (a) to receive all income
and proceeds of the Royalty net of other Partnership expenses and net of amounts
attributable to the Managing General Partner's 0.1 percent interest in the
Partnership, (b) to pay or provide for the payment of expenses, charges,
liabilities and obligations of the Trust and (c) to distribute to Unit holders
the remaining revenues attributable to the Royalty.
The 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
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the Trustee to incur obligations, the only liabilities which the Trustee
ordinarily incurs are those for routine administrative expenses, such as
Trustee's fees and accounting, legal and other administrative fees. The costs
and expenses of the Trust (including the Trustee's fees) are estimated to
approximate $0.4 million for 1998. 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 $1.7 million remained
as of December 31, 1997. The costs and expenses of the Trust may increase in
future years, depending on the volume of trading in the Units, the amount of
revenues to the Trust and increases in accounting, legal and other
administrative fees.
DUTIES AND LIMITED POWERS OF THE TRUSTEE
Under the Trust Indenture, the Trustee receives the Trust's share of any
distributions from the Partnership and pays all expenses, charges, liabilities
and obligations of the Trust. With respect to any liability which is contingent
or uncertain in amount or which otherwise is not currently due and payable, the
Trustee has the discretion to establish a cash reserve for the payment of such
liability. If at any time the cash on hand and to be received by the Trustee is
not, in its judgment, sufficient to pay liabilities of the Trust as they become
due, the Trustee is authorized to borrow the funds required to pay such
liabilities, in which event no further distributions will be made to Unit
holders until such borrowing has been repaid. The Trustee is permitted to borrow
such funds from any bank, including itself. To secure payment of any such
indebtedness, the Trustee is authorized to mortgage, pledge, grant security
interests in or otherwise encumber assets of the Trust, or any portion thereof,
to cause the Partnership to mortgage, pledge, grant security interests in or
otherwise encumber the Royalty, and to cause the Partnership to carve out and
convey production payments. After payment of or provision for Trust expenses and
obligations, the Trustee makes quarterly distributions to the Unit holders of
all the proceeds received from the Partnership in respect of the Royalty and not
theretofore distributed. The Trustee submits periodic financial reports to the
Unit holders as described under "DESCRIPTION OF THE UNITS -- Periodic Reports."
The Trust Indenture authorizes the Trustee to take such action as in its
judgment is necessary or advisable to achieve the purposes of the Trust. The
Trust Indenture provides that cash being held by the Trustee as a reserve for
liabilities or for distribution at the next distribution date will be placed in
interest-bearing accounts or certificates (which may include accounts or
certificates of the bank acting as Trustee), but the Trustee is otherwise
prohibited from acquiring any asset other than the Trust's interest in the
Partnership or engaging in any business or investment activity of any kind
whatsoever. The Trustee may sell or dispose of its interest in the Partnership,
or permit the Partnership to sell or dispose of all or any part of the Royalty,
only as authorized by a vote of the Unit holders upon termination of the Trust
and in certain other limited circumstances. However, the Trust is directed to
effect such a sale (without any such vote) if the Trust's cash receipts for each
of three successive years commencing after December 31, 1990 are less than $3
million. The Trustee must distribute the net proceeds of such sale (after
satisfaction of any outstanding liabilities) to the Unit holders. See
"Managements Discussion and Analysis of Financial Condition and Results of
Operations."
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.
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LIABILITIES OF THE TRUSTEE
The Trustee may act in its discretion and will be personally or
individually liable only for fraud, gross negligence or bad faith. The Trustee
will be indemnified from the Trust assets for any liability, expense, claim,
damage or other loss incurred in performing its duties, unless resulting from
fraud, gross negligence or bad faith, and will have a lien upon the assets of
the Trust as security for such indemnification and for reimbursements and
compensation to which it is entitled. The Trustee will not be entitled to
indemnification from Unit holders.
TERMINATION OF THE TRUST
The Trust Indenture provides generally that the Trust shall terminate upon
the first to occur of: (i) the sale of all the Trust's interest in the
Partnership, or the sale by the Partnership of all of its assets including the
Royalty, or (ii) a decision to terminate the Trust by the affirmative vote of
Unit holders representing a majority of the Units. As noted above, the Trustee
is required to sell the Trust's interest in the Partnership, or cause the
Partnership to sell the Royalty, if the Trust's cash receipts for each of three
successive years are less than $3 million, thereby terminating the Trust
pursuant to (i) above. Upon the termination of the Trust under (ii) above, the
Trustee will sell the Royalty (or will cause the Partnership to sell all of the
assets of the Partnership). The Trustee will as promptly as possible distribute
the proceeds of any such sales according to the respective interests and rights
of the Unit holders after discharging all of the liabilities of the Trust and,
if necessary, setting up reserves in such amounts as the Trustee in its
discretion deems appropriate for contingent liabilities. See "Managements
Discussion and Analysis of Financial Condition and Results of Operations."
DESCRIPTION OF THE UNITS
GENERAL
Each Unit is evidenced by a transferable certificate. Each Unit evidences
an undivided interest in the Trust, which in turn owns a 99.9 percent interest
in the Partnership. A total of 14,975,390 Units are outstanding.
DISTRIBUTIONS AND INCOME COMPUTATIONS
Each month the Trustee determines the amount available for distribution for
such month. Such amount (the Monthly Distribution Amount) is equal to the
excess, if any, of the cash distributed by the Partnership to the Trust during
such month, plus any other cash receipts of the Trust during such month (other
than interest earned on the Monthly Distribution Amount for any other month)
over the liabilities of the Trust paid during such month, subject to adjustments
for changes made by the Trustee during such month in any cash reserves
established for the payment of contingent or future obligations of the Trust.
The Monthly Distribution Amount for each month is payable to Unit holders of
record on the Monthly Record Date, which is the close of business on the last
business day of such month, or such later date as the Trustee determines is
required to comply with legal or stock exchange requirements. However, to reduce
the administrative expenses of the Trust, the Trustee does not distribute cash
monthly, but rather, during January, April, July and October of each year. The
Trustee distributes to each person who was a Unit holder of record on a Monthly
Record Date during one or more of the immediately preceding three months, the
Monthly Distribution Amount for the month or months that he was a Unit holder of
record, together with interest earned on such Monthly Distribution Amount from
the Monthly Record Date to the payment date.
Because the Trust is classified for tax purposes as a "grantor trust" and
the Partnership is classified for tax purposes as a partnership (see "FEDERAL
INCOME TAX CONSIDERATIONS") and is required to use the accrual method of
accounting, the net taxable income from the Royalty (other than interest earned
on Monthly Distribution Amounts) will be realized by the Unit holders for tax
purposes in the month accrued by the Partnership, rather than in the month
distributed by the Trust. Thus, a Unit holder may
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be required to report income attributable to his Units without receiving
distributions directly corresponding to such income.
NATURE OF THE UNITS
The Units are not an interest in or obligation of the Company, the Working
Interest Owner or any successor Working Interest Owner. However, the ultimate
value of the Royalty is dependent to a large extent upon the ability of the
Working Interest Owner to produce oil and gas from the Royalty Properties. There
is no requirement that the Working Interest Owner expend any specific amounts
with respect to the Royalty Properties. The Working Interest Owner is free to
transfer its working interest (burdened by the Royalty) to third parties. In
certain cases the Working Interest Owner is permitted to farmout interests in
the Royalty Properties and to reduce the Royalty proportionately. See "THE
ROYALTY PROPERTIES AND THE ROYALTY -- General and -- Production and Drilling
Activities." The Working Interest Owner does not have an obligation to produce
any specific amounts of oil and gas from any of the Royalty Properties. It has
the right to abandon any well or lease, and upon termination of any lease the
portion of the Royalty relating thereto will be extinguished. The amount of
revenues attributable to the Royalty may be affected by operating agreements and
unitization and pooling arrangements. The realization of the ultimate value of
the Royalty is subject to all the risks associated with exploration on and
development of oil and gas properties and to comprehensive regulation by
governmental authorities.
TRANSFER OF THE UNITS
Units are transferable on the records of the Trustee or transfer agent upon
the surrender of any certificate representing Units in proper form for transfer
as required by the Trustee. No service charge 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.
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LIABILITY OF OWNERS OF UNITS
Regarding the Unit holders, the Trust Indenture provides that the Trustee
will be fully liable if the Trustee incurs any liability, except with respect to
the income tax and oil and gas pricing matters described in the next paragraph,
without taking reasonable steps to ensure that such liability will be
satisfiable only out of the Trust assets (regardless of whether the assets are
adequate to satisfy the liability) and in no event out of amounts distributed
to, or other assets owned by, Unit holders. However, under the laws of Texas
(and perhaps California, if applicable), it is unclear whether a Unit holder
would be jointly and severally liable for any liability of the Trust in the
event that both of the following conditions were to occur: (a) the satisfaction
of such liability was not by contract limited to the assets of the Trust, and
(b) the assets of the Trust were insufficient to discharge such liability. Each
Unit holder should weigh this potential exposure in deciding whether to retain
or transfer his Units. In that connection, Unit holders should consider the
value and passive nature of the Trust assets and the restrictions on the power
of the Trustee to incur liabilities.
The Trust Indenture provides that the Trustee will not be liable to Unit
holders for state or federal income taxes or for refunds, fines, penalties or
interest relating to oil or gas pricing overcharges under state or federal price
controls. With respect to gas pricing matters, the Federal Energy Regulatory
Commission (FERC) is not considered to be empowered under current judicial
decisions to compel refunds of gas price overcharges from overriding royalty
interest owners. It is possible, however, that laws on such matters may change
in the future or that other parties, such as oil or gas purchasers, might be
able to instigate legal action to compel such refunds from royalty owners and
that Unit holders might be treated for such purpose as royalty owners.
STATE LAW CONSIDERATIONS
It is anticipated, based on the structure of the Trust and the Partnership,
that the Units will be treated for certain state law purposes essentially the
same as other securities, that is, as interests in intangible personal property
rather than as interests in real property. However, in the absence of
controlling legal precedent there is a possibility that under certain
circumstances a Unit holder could be treated as owning an interest in real
property. In that event, the tax, probate, devolution of title and
administration laws of Texas, Louisiana or California applicable to real
property may apply to the Units, even if held by a person who is not a resident
or domiciliary thereof. Application of such laws could make inheritance and
related matters with respect to the Units substantially more onerous than had
the Units been treated as interests in intangible personal property. In any
event, however, the ownership of Units and realization of income from the
Royalty by a Unit holder may subject such Unit holder to state or local income
or other taxation in the state of the Unit holder's residence or domicile. Unit
holders should consult their legal and tax advisors regarding the applicability
of these considerations to their individual circumstances.
POSSIBLE REQUIREMENT THAT UNITS BE DIVESTED
Although the Trust Indenture imposes no restrictions based on nationality
or other status of the persons or other entities who are eligible to hold Units,
it does provide that if at any time the Trust or Trustee is named as a party in
any judicial or other proceeding which seeks the cancellation or forfeiture of
the Trust's interest in any of the Royalty Properties because of the nationality
or other status of any one or more Unit holders, such Unit holders may be
required to sell their Units according to procedures set forth in the Trust
Indenture.
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THE ROYALTY PROPERTIES AND THE ROYALTY
EXPLANATORY NOTE
The Trustee has no responsibility relating to the operations of the Royalty
Properties. The information in this report, relating to the characteristics of
and operations on the Royalty Properties and certain other matters, has been
furnished to the Trustee by the Working Interest Owner.
The information in this report regarding the Royalty Properties should be
read in light of the following: The Royalty was carved out of working interests
owned by the Company at the time of creation of the Trust. References in this
report to "net" wells and acres refer to the sum of the fractional working
interests owned by the Working Interest Owner (from which the Royalty was
carved) in the "gross" wells or acres. References to the percentage of the
working interest owned by the Working Interest Owner are references to the
working interest out of which the Royalty was carved. For example, a reference
to a "50 percent working interest" in a well or lease which is included in a
Royalty Property indicates that the Partnership's net overriding royalty
interest (equal to 90 percent of the Net Proceeds, as defined, from all the
Royalty Properties) burdens half of the total working interest in the well or
lease. Such 50 percent working interest will also be subject to landowners'
royalties and may be subject to other overriding royalty interests and other
burdens which are considered prior to calculations of amounts payable to the
owner of the Royalty. Since the amounts and nature of such burdens vary from
lease to lease, the information presented herein and elsewhere regarding the
Working Interest Owner's percentage of the working interest in any well or lease
cannot be used to calculate precisely the interest attributable to the Trust in
a well or lease. In addition, (i) because operating and capital costs are taken
into consideration in calculating the amounts payable to the owner of the
Royalty and because prices for oil and gas may vary from field to field,
information regarding results of well tests of gross quantities of production
from a given well cannot be used to compute the interest attributable to the
Trust, and (ii) because the Royalty Properties consist of multiple leases in
multiple fields, the interest of the Working Interest Owner in any given well or
lease may not be indicative of the interest attributable to the Trust in the
Royalty Properties.
GENERAL
The map on page 8 shows the location and selected information as of
December 31, 1997 for all of the productive Royalty Properties where production
or drilling operations are currently under way. Additional exploration may be
proposed for certain other Royalty Properties where geologic features have been
identified through the utilization of 3-D seismic technology. After analyzing
each proposal, the Working Interest Owner will determine whether or not to
participate in additional exploratory operations.
As of December 31, 1997, there were six gross productive oil wells and 16
gross productive gas wells on 10 of the remaining Royalty Properties where the
Working Interest Owner retains a working interest.
All remaining Royalty Properties are operated by other oil and gas
companies under joint operating agreements. Neither the Working Interest Owner
nor any operator has any contractual commitments to the Partnership or the Trust
to conduct further exploratory or development drilling on the Royalty Properties
or to maintain its ownership interest in any of the properties. See "Certain
Factors Affecting Distributions; Conflicts of Interest." However, any operator
of a Royalty Property (including the Working Interest Owner) has an obligation
to operate and develop such property in accordance with the standards of a
reasonable and prudent operator. The Working Interest Owner retains a revenue
interest in the remaining Royalty Properties and it has informed the Trustee
that it may conduct further development and exploratory activities on certain of
the Royalty Properties. See "Production and Drilling Activities" below for a
discussion of current development and exploratory activities on certain of the
Royalty Properties.
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RESERVES
A study of the proved oil and gas reserves attributable to the Royalty
Properties as of December 31, 1997, has been made by Ryder Scott Company
Petroleum Engineers, independent petroleum engineers (Ryder Scott). In
accordance with regulations of the Securities and Exchange Commission (the SEC),
such study is limited to reserves currently classified as "proved." The amount
of reserves and the timing of production attributable to the Royalty Properties
are, and in the future will continue to be, significantly affected by the level
of capital expenditures to be incurred on the individual properties and the
success of exploration and development activities. The assumptions used in
preparing the reserve study are detailed within the following letter, which
summarizes such reserve study. Such assumptions, as well as the cautionary
paragraphs following the letter, should be studied carefully together with the
estimates contained in the letter. Ryder Scott also prepared estimates of future
net cash flows attributable to the Royalty from proved oil and gas reserves and
the discounted present value of such future net cash flows. The estimates of
Ryder Scott are used in the preparation of the Trust's financial statements and
for other reporting purposes. However, as explained in the cautionary paragraphs
immediately following the letter, Ryder Scott's estimates were prepared based on
production and costs as of December 31, 1997, 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 1998 attributable to sales of oil and gas produced in the fourth quarter of
1997, volumes of natural gas sold by other parties pursuant to certain gas
balancing arrangements and the effect of the excess Class A cost carry-forward
at December 31, 1997. Therefore, the amounts set forth in the letter are not
necessarily indicative of actual amounts to be distributed to Unit holders,
either annually or ultimately.
The estimates of future net cash flows and discounted present value of
future net cash flows were prepared using prices and costs as of December 31,
1997. Proved reserves are estimated quantities of oil and gas which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions (see Note 10 -- Supplementary Proved Oil and Gas Reserve
Information).
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MAP
[CRC FBC]
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[RYDER SCOTT LETTERHEAD]
March 30, 1998
Freeport-McMoRan Oil and Gas Royalty Trust
c/o Texas Commerce Bank National Association, Trustee
600 Travis Street, Suite 1150
Houston, Texas 77002
Gentlemen:
At the request of IMC Global Inc. (IGL), 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, 1997. 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 IGL and the successors and
assigns of its oil and gas working interests to the extent the context requires.
Ten offshore leases subject to the Royalty have been considered in this
report, and the impact of these leases' reserves, revenues, expenses, and
expense accruals on the income of the Partnership has been determined. These ten
leases are hereinafter referred to as the "Subject Properties". All other leases
originally subject to the Royalty have either expired, or have been farmed out,
with the working interest owner retaining an overriding royalty interest
burdened by the Royalty. The Working Interest Owner has assured us that no
leases other than the ten included in our evaluation have a material effect on
the overall revenues or liabilities of the Partnership.
The estimated reserve quantities and future income quantities presented in
this report are related to hydrocarbon prices. December 1997 hydrocarbon prices
were used in the preparation of this report as required by SEC guidelines;
however, actual future prices may vary significantly from December 1997 prices.
Therefore, volumes of reserves actually recovered and amounts of income actually
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received may differ significantly from the estimated quantities presented in
this report. The results of this study are summarized as follows:
SEC PARAMETERS
ESTIMATED NET RESERVE AND INCOME DATA
FREEPORT-MCMORAN OIL AND GAS ROYALTY PARTNERSHIP
AS OF DECEMBER 31, 1997
<TABLE>
<CAPTION>
TOTAL
PROVED
-----------
<S> <C>
Remaining Reserves
Oil/Condensate -- Barrels................................. 197,933
Gas -- MMCF............................................... 2,601
Future Net Income (FNI)
1998...................................................... $ 1,426,436
1999...................................................... 2,583,487
2000...................................................... 2,307,491
-----------
Sub-Total (1998-2000)..................................... $ 6,317,414
Remaining................................................. 5,705,183
-----------
Total..................................................... $12,022,597
Discounted FNI @ 10%........................................ $ 8,442,775
(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 15.025 pounds per square inch absolute.
The reserve volumes and income values shown above for the properties
transferred to the Partnership were estimated from projections of reserves and
income attributable to the combined interests consisting of the Royalty and the
interest of the Working Interest Owner in the Subject Properties. Interests
related to non-consent operations and interests acquired subsequent to the
conveyance of the Royalty to the Partnership are excluded from the calculation
of Partnership income.
The future net income attributable to the Royalty was estimated on a yearly
basis from a projection of the combined Working Interest Owner and Partnership
future net income. Combined future net income values were calculated by
deducting operating expenses and capital costs from the future gross revenue of
the combined interests. Only those expenses and capital costs necessary for the
development and production of proved reserves were taken into consideration. The
annual income values for each property were further reduced by an overhead
charge furnished by the Working Interest Owner. The adjusted annual income
resulting from subtracting the overhead charge was multiplied by a factor of 90
percent to arrive at the annual future net income of the Partnership.
More than a sufficient amount of income has been accrued as of December 31,
1997 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
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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:
<TABLE>
<C> <C> <S>
Royalty Future Net Income
Partnership Interest Net Reserves = --------------------------
Price per Unit of Reserves
</TABLE>
The price per unit of reserves was calculated by dividing combined future gross
revenues by combined net reserves.
RESERVE DEFINITIONS
The proved reserves presented in this report comply with the Securities and
Exchange Commission's Regulation S-X Part 210.4-10 (a) as clarified by
subsequent Commission's Staff Accounting Bulletins, and are based on the
following definitions and criteria:
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from
known reservoirs under existing operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but
not on escalation based on future conditions. Reservoirs are considered
proved if economic producibility is supported by either actual production
or conclusive formation test. In certain instances, proved reserves are
assigned on the basis of a combination of core analysis and electrical and
other type logs which indicate the reservoirs are analogous to reservoirs
in the same field which are producing or have demonstrated the ability to
produce on a formation test. The area of a reservoir considered proved
includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can
be reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts,
the lowest known structural occurrence of hydrocarbons controls the lower
proved limit of the reservoir. Reserves that can be produced economically
through the application of improved recovery techniques are included in the
proved classification when these qualifications are met: (1) successful
testing by a pilot project or the operation of an installed program in the
reservoir provides
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support for the engineering analysis on which the project or program was
based, and (2) it is reasonably certain the project will proceed. Improved
recovery includes all methods for supplementing natural reservoir forces
and energy, or otherwise increasing ultimate recovery from a reservoir,
including (1) pressure maintenance, (2) cycling, and (3) secondary recovery
in its original sense. Improved recovery also includes the enhanced
recovery methods of thermal, chemical flooding, and the use of miscible and
immiscible displacement fluids. Proved natural gas reserves are comprised
of non-associated, associated and dissolved gas. An appropriate reduction
in gas reserves has been made for the expected removal of natural gas
liquids, for lease and plant fuel, and for the exclusion of non-hydrocarbon
gases if they occur in significant quantities and are removed prior to
sale. Estimates of proved reserves do not include crude oil, natural gas,
or natural gas liquids being held in underground or surface storage. Proved
reserves are estimates of hydrocarbons to be recovered from a given date
forward. They may be revised as hydrocarbons are produced and additional
data become available.
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved. Developed reserves may be subcategorized as producing
or non-producing using the SPE/WPC Definitions:
Producing
Reserves sub-categorized as producing are expected to be recovered
from completion intervals which are open and producing at the time of the
estimate. Improved recovery reserves are considered producing only after
the improved recovery project is in operation.
Non-Producing
Reserves sub-categorized as non-producing include shut-in and behind
pipe reserves. Shut-in reserves are expected to be recovered from (1)
completion intervals which are open at the time of the estimate but which
have not started producing, (2) wells which were shut-in for market
conditions or pipeline connections, or (3) wells not capable of production
for mechanical reasons. Behind pipe reserves are expected to be recovered
from zones in existing wells, which will require additional completion work
or future recompletion prior to the start of production.
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
reasonable certainty that there is continuity of production from the existing
productive formation. Estimates for proved undeveloped reserves are attributable
to any acreage for which an application of fluid injection or other improved
technique is contemplated, only when such techniques have been proved effective
by actual tests in the area and in the same reservoir.
ESTIMATES OF RESERVES
In general, the reserves included herein were estimated by performance
methods or the volumetric method; however, other methods were used in certain
cases where characteristics of the data indicated such other methods were more
appropriate in our opinion. The reserves estimated by the performance method
utilized extrapolations of various historical data in those cases where such
data were definitive in our opinion. Reserves were estimated by the volumetric
method in those cases where there were inadequate historical performance data to
establish a definitive trend or where the
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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, 1997 and these prices were held constant except for known and determinable
escalations. In accordance with Securities and Exchange Commission guidelines,
changes in liquid and gas prices subsequent to December 31, 1997 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 1997, 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, 1997
were not considered in this study.
GAS
The Working Interest Owner has furnished us with gas prices in effect at
December 1997 and with its forecasts of future gas prices which take into
account SEC guidelines and current market prices. In accordance with SEC
guidelines, the future gas prices used in this report make no allowance for
future gas price increases which may occur as a result of inflation nor do they
allow any allowance for seasonal variations in gas prices which are likely to
cause future yearly average gas prices to be somewhat lower than December gas
prices. At the request of the Working Interest Owner, a market price of $2.343
per MMBTU was used in this study for uncontracted gas.
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
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offshore areas. The estimates of the net abandonment costs for the Subject
Properties were furnished by the Working Interest Owner and were accepted
without independent verification.
All operating, development, abandonment, and overhead costs used in this
study were furnished by the Working Interest Owner. The operating costs are
based on the operating expense reports of the Working Interest Owner, or on
operating expense estimates furnished by the Working Interest Owner for
properties not yet on production. The development costs are based on
authorizations for expenditure for the proposed work, or on actual costs for
similar projects.
GENERAL
The reserve estimates presented herein are based upon a detailed study of
the Subject Properties; however, Ryder Scott has not made any field examination
of the properties. No consideration was given in this report to potential
environmental liabilities which may exist nor were any costs included for
potential liability to restore and clean up damages, if any, caused by past
operating practices. The Working Interest Owner has represented that it has
given Ryder Scott access to its accounts, records, geological and engineering
data and reports and other data as were required for this investigation. The
ownership interests, prices, and other factual data furnished to Ryder Scott by
the Working Interest Owner in connection with this investigation were accepted
without verification. The estimates presented in this report are based on such
furnished data available through December 1997.
The future prices received for the sale of production may be higher or
lower than the prices used in this report as described above, and the operating
costs and other costs related to such production may also increase or decrease
from existing levels; however, such possible changes in prices and costs were,
in accordance with rules adopted by the Securities and Exchange Commission,
omitted from consideration in preparing our report.
Neither Ryder Scott Company nor any of its employees has any interest in
the Subject Properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future income for
the Subject Properties.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Kent A. Williamson, P.E.
Senior Vice President
KAW/sw
[SEAL]
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Of the total discounted present value of future net cash flows attributable
to the Royalty estimated by Ryder Scott, approximately 57 percent was accounted
for by West Cameron Block 498, 12 percent by West Cameron Block 215 and 11
percent by Breton Sound Block 55.
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.
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The Ryder Scott estimates were prepared on the basis of estimated
production and Costs accrued through December 31, 1997. Thus, amounts received
by the Working Interest Owner after November 30, 1997 attributable to production
during 1997 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
1997. The Working Interest Owner has estimated that if Ryder Scott had taken
into account the 1998 Gross Proceeds from 1997 production, the total estimated
future net cash flow and the discounted present value of such estimate in the
Ryder Scott letter would have been approximately $0.7 million higher (net to the
Trust's interest). In addition, because Ryder Scott's estimates for the
remaining period are based on estimated production and Costs accrued during each
such period and because actual Gross Proceeds and Costs will not be based on
production and Costs during the same period, the estimates for various time
periods will not in any event correspond to the amount of payments pursuant to
the Royalty during such periods.
Ryder Scott gave no effect in its estimates to amounts to which the Working
Interest Owner is entitled as a result of gas imbalances for certain production
(see Note 5 -- Gas Balancing Arrangements and Note 10 -- Supplementary Proved
Oil and Gas Reserve Information). Pursuant to the Conveyance, proceeds from gas
produced from the Royalty Properties but sold by other parties pursuant to gas
balancing arrangements between the Working Interest Owner and others
(underproduction) are not included in Gross Proceeds for purposes of calculating
the Royalty. In the future the Working Interest Owner will be entitled to sell
volumes equal to such underproduction or receive cash settlements. The amounts
the Working Interest Owner will receive from the future sale of such
underproduction may be more or less than those amounts received by third parties
because of price fluctuations.
The estimated future net cash flows shown in Ryder Scott's letter have not
been reduced for any capital expenditures on Productive Properties in excess of
amounts estimated to be necessary to develop proved reserves attributed thereto.
See "Computation of the Royalty" below. Similarly, such future net cash flows
have also not been reduced for costs and expenses of the Trust, which are
estimated at approximately $0.4 million per year, or of the Partnership, which
are expected to be minimal. Additionally, Ryder Scott did not take into account
the Class A cost carry-forward of $17.4 million net to the Trust, as of December
31, 1997.
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
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received (on a cash basis) during a particular month over Costs incurred (on an
accrual basis) during such month. Generally, such Costs include any excess of
Costs over Gross Proceeds carried forward from the previous month, together with
interest on such excess. Amounts equal to 90 percent of the Net Proceeds for any
month are payable by the Working Interest Owner to the Partnership on the last
business day of the following month.
"Gross Proceeds" means the amount received from sales of hydrocarbons
produced from the Royalty Properties that are attributable to the working
interests subject to the Royalty, net of lessor royalties and production
payments existing at the time of the creation of the Trust which burdened the
Royalty Properties prior to the effective date of the Conveyance, and subject to
farmouts and certain other adjustments.
"Costs" means, generally, (i) all costs incurred by the Working Interest
Owner in producing and operating the Royalty Properties (lease operating
expenses), (ii) all capital costs incurred, or projected to be incurred, by the
Working Interest Owner in drilling and completing exploratory and development
wells and in connection with the installation of platforms, pipelines and other
production facilities, (iii) an overhead charge and (iv) amounts recovered by
the Working Interest Owner as estimated Abandonment Costs ("Abandonment Costs"
means, generally, the future costs to be incurred by the Working Interest Owner
to plug and abandon wells and dismantle and remove platforms, pipelines and
other production facilities from the Royalty Properties).
The Working Interest Owner is entitled to accrue certain estimated future
costs in accordance with a formula set forth in the Conveyance. The accrual
formula provides that, for any month and with respect to a specific item of
future costs, the Working Interest Owner may include in its costs an amount
calculated by multiplying (a) the excess of (i) the total estimated amount of
such item of future cost over (ii) the aggregate amount accrued in previous
months with respect to such item, by (b) a fraction, the numerator of which is
Adjusted Gross Proceeds for such month and the denominator of which is total
estimated future Adjusted Gross Proceeds for such month and all future months.
For this purpose, "Adjusted Gross Proceeds" means Gross Proceeds for a month
less all Class A Costs for such month, such costs that were not covered in the
previous month and interest thereon. Class A Costs are all costs that are not
Class B Costs. Class B Costs for a month are (a) costs incurred to discover or
develop minerals on certain leases, (b) any monthly future cost accruals, (c)
such costs that were not covered by proceeds in the previous month and (d)
interest thereon.
If Costs exceed Gross Proceeds for any month, the excess will be recovered
by the Working Interest Owner, with interest at the prime rate (as defined in
the Conveyance), compounded monthly, out of future Gross Proceeds prior to the
making of further payments to the Partnership, but the Partnership and the
Trustee are not liable for any operating, capital or other costs or liabilities
attributable to the Royalty Properties or hydrocarbons produced therefrom. Such
recovery will apply to Class B Costs as well. The Partnership and the Trustee
are not obligated to return any Royalty income received in any period, but
overpayments made by the Working Interest Owner would reduce future amounts
payable.
The Working Interest Owner is required to maintain books and records
sufficient to determine the amounts payable under the Conveyance. Additionally,
in the event of a controversy between the Working Interest Owner and any
purchaser as to the correct sales price of any production, amounts received by
the Working Interest Owner and promptly deposited by it with an escrow agent
shall not be considered as having been received by the Working Interest Owner,
and therefore shall not be included as Gross Proceeds, until the controversy is
resolved, but all amounts thereafter paid to the Working Interest Owner by the
escrow agent shall be considered Gross Proceeds. Similarly, Costs will include
any amounts the Working Interest Owner is required to pay as a refund, interest
or penalty because the amount received by it as a sales price was in excess of
that permitted by the terms of any applicable contract, statute, regulation,
order, decree or other obligation. Because the Units are publicly traded,
purchasers of Units in the market may, as a result of such procedures, receive
distributions of amounts that would have been distributed to former holders if
such amounts had not
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been held in escrow or, conversely, may have their distributions reduced or
eliminated as a result of controversies about amounts which may have been
collected. Within 30 days following the close of each calendar quarter, the
Working Interest Owner is required to deliver to the Partnership a statement of
the computation of Net Proceeds attributable to the quarter.
If a default occurs under the Conveyance, the holder of the Royalty may
pursue any legal or equitable remedies available to it, including seeking
specific performance of any covenant that has been breached. Defaults under the
Conveyance include (1) failure on the part of the Company to observe or perform
any covenant contained in the Conveyance, which failure materially adversely
affects the interests of the holder of the Royalty, and (2) certain events of
bankruptcy or insolvency relating to the Working Interest Owner.
CERTAIN FACTORS AFFECTING DISTRIBUTIONS; CONFLICTS OF INTEREST
The amount of cash payable on account of the Royalty, and thus the amount
of cash available for distribution to Unit holders, depends upon numerous
factors and may vary substantially from month to month. In addition, conflicts
of interest may arise between the Working Interest Owner and the Trust. These
factors and potential conflicts include the following:
Timing of Collections by the Working Interest Owner. An alteration in
the timing of the receipt of payment for proceeds of production from the
Royalty Properties from the collection pattern normally anticipated can
occur for a number of reasons beyond the Working Interest Owner's control.
Such altered timing can result in: (1) wide swings in Monthly Distribution
Amounts, and (2) delays from one quarter to the next in the timing of the
actual cash distribution by the Trust to the Unit holders of amounts
attributable to such delayed receipts. Accordingly, the Monthly
Distribution Amount for any particular month is not necessarily indicative
of future Monthly Distribution Amounts which will depend on future costs
incurred and revenues received.
Capital Expenditures. Although the Working Interest Owner's
management believes that the Royalty Properties have potential for reserve
additions from future exploration and development activities, the success
of such activities cannot be assured. The value of the Royalty, and thus of
the Units, will depend in part upon the level of, and the degree of success
of, such activities. In the event a decision is made to explore for or
develop hydrocarbons on the Royalty Properties, subsequent capital
expenditures required to explore for, develop and produce the reserves
could be of such magnitude that they would result in the elimination or
reduction of distributions to Unit holders for a substantial period of
time. See "Production and Drilling Activities" below.
Oil and Gas Surplus and Other Marketing Factors. The prices of crude
oil have fluctuated significantly in recent years as a result of an
oversupply of crude oil on world markets and other factors beyond the
Working Interest Owner's control. Such factors may adversely affect both
the availability of a ready market for production from the Royalty
Properties and the sales prices received for such production. Gas market
conditions are affected by gas price competition, competition from
alternative fuels, energy conservation and a variety of other factors.
Variation of Partnership's Interest. Although the Royalty conveyed to
the Partnership is set forth in the Conveyance, the actual amount of
revenues from the Royalty Properties may be increased or reduced as a
result of future farmouts, unit agreements and unit operating agreements.
Certain portions of the Royalty have been and other portions of the Royalty
may be extinguished as leases expire as a result of the failure to
establish or maintain commercial production or to pay annual rentals. In
addition, the Working Interest Owner's right to revenues from a well to be
drilled in the future may be extinguished or suspended as a result of "non-
consent" provisions of present or future operating agreements with other
working interest owners. See "Operating Agreements" below. Since the
Royalty was conveyed out of working interests, distributions to the Trust
will be reduced, extinguished or suspended as, when and to the extent the
Working Interest Owner's right to revenues from a well is reduced,
extinguished or suspended.
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<PAGE> 22
Operating Hazards. Operation of the Royalty Properties is subject to
all the risks incident to offshore exploration for and production of oil
and gas, including blowouts, cratering, fires and marine perils such as
capsizing, collision and adverse weather and seas. Any of these events
could result in damage to or destruction of oil and gas wells or producing
facilities, suspension of operations and pollution damage. Although losses
and liabilities arising from such events would not require payment by the
Trust of funds previously received, they would reduce the proceeds payable
thereafter with respect to the Royalty.
Ownership of Adjacent Properties. The Working Interest Owner may own
interests in offshore tracts that are adjacent to or in the vicinity of,
but not included in, the Royalty Properties, and it may in the future
acquire additional such tracts. Drilling conducted on the Royalty
Properties may provide the Working Interest Owner or any successor with
valuable information regarding such other tracts, which it would then be
free to develop unburdened by the Royalty and which in some cases could
drain oil and gas from the Royalty Properties. In the second quarter of
1995, McMoRan Oil & Gas Co. (MOXY), a former affiliate of FTX, acquired a
25% undivided interest in West Cameron Block 519, a tract which is adjacent
to West Cameron Block 498. The Royalty will not apply to this tract just as
it would not have applied had it been purchased by the Working Interest
Owner. The Working Interest Owner is not the operator of West Cameron 498
and MOXY is not the operator of West Cameron 519, and neither has the
voting interest necessary to determine the nature or timing of operations
on either of these tracts.
Negotiation and Amendment of Contracts. The Working Interest Owner and
the purchasers of gas from the Royalty Properties have the right to enter
into and amend contracts for the sale of production without the consent of
the Trustee. In addition, the Working Interest Owner is responsible for the
marketing of its working interest share of any commercial quantities of oil
or gas produced from the Royalty Properties. Although the Working Interest
Owner is generally expected to seek the highest prices obtainable for the
production, its negotiations regarding future contracts and possible
revisions to existing contracts may be affected by factors which are of
economic significance to it but not to the Unit holders, such as the
existence or anticipation of other contractual arrangements between the
Working Interest Owner and the purchaser. The Working Interest Owner is
entitled to make arrangements for the marketing of its share of production
from the Royalty Properties independently of other working interest owners.
Transfer of Working Interest; Abandonment. The Working Interest Owner
is free to transfer all or a portion of its working interest in any Royalty
Property (burdened by the Royalty) to any third party in sound financial
condition. The Working Interest Owner is also free to enter into farmouts
on the Royalty Properties, whereby it would transfer a portion of its
interest (unburdened by the Royalty) while retaining a lesser interest
(burdened by the Royalty) in return for the transferee's obligation to
drill a well on the Royalty Property; however, it may not enter into such
farmouts on the Productive Properties except with respect to exploratory
wells. The Working Interest Owner has the right to abandon any well or
lease if, in its opinion, such well or lease ceases to produce or is not
capable of producing in paying quantities, and upon termination of any
lease, the portion of the Royalty relating thereto will be extinguished.
Should a lease on one of the Royalty Properties expire, the Working
Interest Owner would thereafter be free to acquire a new lease on the same
block, unburdened by the Royalty.
PRODUCTION AND DRILLING ACTIVITIES
Of the ten remaining Royalty Properties, seven are currently producing. For
a discussion concerning the oil and gas production from such properties in 1997
as well as information concerning drilling activities on such properties during
1997, see Item 7 -- Management's Discussion and Analysis of Financial Condition
and Results of Operations beginning on page 29 and Note 10 -- Supplementary
Proved Oil and Gas Reserve Information.
20
<PAGE> 23
OPERATING AGREEMENTS
All of the remaining Royalty Properties are operated by oil and gas
companies that are not affiliated with the Company. Costs attributable to the
Royalty Properties generally will be computed based on the costs charged to the
Working Interest Owner's account under the terms of existing joint operating
agreements.
Besides general provisions for proposing, conducting and sharing costs for
joint operations on the Royalty Properties, the existing operating agreements
contain provisions which can significantly affect the amount of capital and
operating expenditures and vary the receipt of revenues from the sale of
production. For example, the "non-consent" provisions of the operating
agreements allow other joint interest owners to propose the drilling of wells
and thereby require the Working Interest Owner to elect either to pay its share
of the cost of drilling such wells or suffer a "non-consent" penalty. The
particulars of non-consent penalties on the Royalty Properties vary somewhat
between operating agreements, but generally require the forfeiture to the
participating parties of a significant interest if the party elects not to
participate in the drilling of certain exploratory wells. If a party elects not
to participate in a development well on any of the Royalty Properties (other
than Vermilion Block 21/22 and West Cameron Block 65), that party's right to
receive a share of production from such development well is suspended until such
time as the participating parties have recovered an amount ranging from
approximately 400 percent to approximately 600 percent of the cost of drilling,
testing, completing and equipping the development well. With respect to
Vermilion Block 21/22 and West Cameron Block 65, the non-consenting party must
assign all its working interest in the previously designated development area,
subject to retention by that party of its interest in wells previously drilled
in such area and an overriding royalty interest in all subsequent wells drilled
in such area. The loss of revenues from any failure by the Working Interest
Owner to participate in a development well would reduce the aggregate proceeds
from the Royalty in the event such development well produced in paying
quantities in excess of the cost of drilling, testing, completing and equipping
such well. Neither the Partnership nor the Trustee is entitled to compel the
Working Interest Owner to participate in any operation on a Royalty Property if
the Working Interest Owner makes a "non-consent" election with respect thereto.
The Working Interest Owner may choose to conduct exploration and
development operations on one or more of the Royalty Properties without the
participation of some, or all, of the other joint interest owners by assuming
the obligations of non-consenting parties. If the Working Interest Owner elects
to assume a share of the costs associated with any non-consenting party's
interest, such costs and the production, if any, attributable to the assumption
of such interest will not be taken into account in the computation of the Net
Proceeds.
The receipt of revenues from the sale of gas production could be delayed
for extended periods of time by gas balancing arrangements which allow other
joint interest owners to take gas production in excess of their ownership
percentage if the Working Interest Owner is unable to take all or a part of its
share of production. On the other hand, if the Working Interest Owner takes gas
production in excess of its ownership percentage, the revenues attributable to
the excess production will not be included in Gross Proceeds except to the
extent such excess is offset by prior or subsequent deficits created after
October 1, 1983 by the Working Interest Owner taking less than its ownership
percentage share of gas production. If a source of gas supply depletes before
the Working Interest Owner has balanced all deficits created after October 1,
1983 with excess production volumes, the Working Interest Owner will be entitled
to receive a cash settlement for such deficits from those joint interest owners
with excess production totals. All such settlement receipts will be included in
Gross Proceeds. See "Reserves" above.
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<PAGE> 24
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 1997 was 9.5 percent higher than the
average price received during 1996. Oil prices can be expected to continue to
exhibit volatility as a result of such factors as the unstable situation in the
Middle East, future actions of OPEC and future changes in worldwide economic
conditions.
The Working Interest Owner currently sells gas at spot market prices from
blocks that were previously subject to long-term contracts with Transco, but
which contracts were terminated by the Working Interest Owner at the end of 1987
and the beginning of 1988 pursuant to the provisions of such contracts.
REGULATION
The production, sale and transportation of oil and gas from the Royalty
Properties are subject to various forms of regulation by federal and state
authorities, and are affected from time to time in varying degrees by political
developments.
Energy Regulation. 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 Trust 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 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
22
<PAGE> 25
the FERC has opted not to impose the regulations of Order No. 509, which
implements the OCSLA, on gatherers and other non-jurisdictional entities, the
FERC has retained the authority to exercise jurisdiction over those entities if
necessary to permit non-discriminatory access to service on the OCS.
Operations the Working Interest Owner conducts relating to the Royalty
Properties are on federal oil and gas leases, which the Minerals Management
Service (MMS) administers. The MMS issues such leases through competitive
bidding. These leases contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the OCSLA (which
are subject to change by the MMS). For offshore operations, lessees must obtain
MMS approval for exploration plans and development and production plans prior to
the commencement of such operations. In addition to permits required from other
agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has promulgated regulations
requiring offshore production facilities located on the OCS to meet stringent
engineering and construction specifications. The MMS also has regulations
restricting the flaring or venting of natural gas and has recently proposed to
amend such regulations to prohibit the flaring of liquid hydrocarbons and oil
without prior authorization. Similarly, the MMS has promulgated other
regulations governing the plugging and abandonment of wells located offshore and
the removal of all production facilities. To cover the various obligations of
lessees on the OCS, the MMS generally requires that lessees post substantial
bonds or other acceptable assurances that such obligations will be met. The cost
of such bonds or other surety can be substantial and there is no assurance that
the Working Interest Owner can obtain bonds or other surety in all cases.
Additional financial responsibility requirements may be imposed under the Oil
Pollution Act of 1990, as discussed under "Environmental Regulation."
Under certain circumstances, the MMS may require any Working Interest Owner
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially and adversely affect the Working Interest
Owner's financial condition and operations. In addition, the MMS is conducting
an inquiry into certain contract agreements from which producers on MMS leases
have received settlement proceeds that are royalty bearing and the extent to
which producers have paid the appropriate royalties on these proceeds. The
Working Interest Owner believes that this inquiry will not have a material
impact on its financial condition, liquidity or results of operations.
The MMS has issued a notice of proposed rulemaking in which it proposes to
amend its regulations governing the calculation of royalties and the valuation
of crude oil produced from federal leases. This proposed rule would modify the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on oil posted prices and assign a value to
crude oil that better reflects market value, establish a new MMS form for
collecting value differential data, and amend the valuation procedure for the
sale of federal royalty oil. The Working Interest Owner cannot predict what
action the MMS will take on this matter, nor can it predict at this stage of the
rulemaking proceeding how the Working Interest Owner might be affected by this
amendment to the MMS' regulations.
In April 1997, after two years of study, the MMS withdrew proposed changes
to the way it values natural gas for royalty payments. These proposed changes
would have established an alternative market-based method to calculate royalties
on certain natural gas sold to affiliates or pursuant to non-arm's length sales
contracts. Informal discussions among the MMS and industry officials are
continuing, although it is uncertain whether, and what changes may be proposed
regarding gas royalty valuation. In addition, MMS has recently announced its
intention to issue a proposed rule that would require all but the smallest
producers to be capable of reporting production information electronically by
the end of 1998.
From 1986 through 1992, the Working Interest Owner entered into several gas
contract settlements with a gas purchaser related to the Royalty Properties
which involved payments of cash by the gas purchaser to the Working Interest
Owner. The Working Interest Owner included in Gross Proceeds the payments
received in connection with these settlements, net of amounts retained in a
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<PAGE> 26
suspense account representing settlement proceeds that were subject to possible
royalty obligations to the MMS. In December 1994, the Working Interest Owner
entered into an agreement with the MMS relating to these gas contract
settlements, resulting in a payment by the Working Interest Owner to the MMS.
After the settlement, approximately $4 million of the funds initially retained
for possible royalty obligations remained. The Working Interest Owner informed
the Trustee that it anticipated expenditures for the development operations on
the Royalty Properties in excess of $4 million and, accordingly, proposed to
retain the funds remaining in the suspense account for use as payments of these
anticipated expenditures, as sufficient funds may not be otherwise available.
The Trustee and the Working Interest Owner evaluated the legal, tax and other
issues relating to retaining such amounts for use in the exploratory and
development operations on the Royalty Properties and concluded that the funds
should be paid to the Trust. Such funds, including interest, were included in
the April 1995 Net Proceeds as a special payment resulting in a distribution of
$0.28794 per Unit.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time-to-time by Congress, the FERC, state
regulatory bodies, and the courts. The Working Interest Owner cannot predict
when or if any such proposals might become effective, or their effect, if any,
on the Trust. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.
Environmental Regulation. The Working Interest Owner's oil and gas
activities on the Royalty Properties are subject to existing federal, state and
local laws and regulations relating to health, safety, environmental quality and
pollution control. The Working Interest Owner has advised the Trustee that it
believes that its operations and facilities are in general compliance with
applicable health, safety, and environmental laws and regulations. Events in
recent years have, however, heightened environmental concerns about the oil and
gas industry generally, and about offshore operations in particular. As a
consequence, offshore oil and gas leases 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
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<PAGE> 27
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 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.
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<PAGE> 28
INTERNAL REVENUE SERVICE RULINGS
The following information regarding FTX's private letter rulings has been
supplied to the Trustee by FTX. In connection with the creation of the Trust and
the distribution of Units to FTX's stockholders (the Distribution) FTX requested
and received favorable private letter rulings from the Internal Revenue Service
(Service) regarding certain tax matters. Among the principal rulings requested
and received were the following:
1. For Federal income tax purposes, the Trust and the Partnership
will be classified as a trust and a partnership, respectively, and not as
associations taxable as corporations.
2. For Federal income tax purposes, the Trust will be characterized
as a "grantor" trust as to the Unit holders and their transferees.
3. For federal income tax purposes, the Distribution will be treated
as a distribution of the Royalty by FTX to the stockholders, followed by
the contribution of the Royalty by the stockholders to the Partnership in
exchange for interests therein, followed in turn by the contribution by the
stockholders of the interests in the Partnership to the Trust in exchange
for the Units.
4. FTX will recognize no gain or loss upon the transfer of the
Royalty to its stockholders.
5. Each Unit holder will be entitled to deduct cost depletion with
respect to its pro-rata interest in the Royalty computed with reference to
the Unit holder's basis in the Units.
6. The Royalty will be considered an economic interest in oil and gas
in place, and the Royalty will constitute a single property within the
meaning of Section 614(a) of the Internal Revenue Code of 1954, as amended,
as in effect when the transaction was consummated.
AREAS OF POTENTIAL TAX CONTROVERSY
Information Return Filing Requirements. Under the Internal Revenue Code of
1986, as amended (the Code), any partner who sells or exchanges (other than
through a broker) an interest in a partnership holding "unrealized receivables"
within the meaning of Section 751 of the Code is required to notify the
partnership of such transaction in accordance with Treasury regulations. Any
such partner who fails to so notify the partnership may be subject to a $50
penalty for each such failure. Furthermore, on a sale or exchange of Units,
other than through a broker, the partnership is required to notify the Service
of any such sale or exchange (of which it has notice) of a partnership interest
after December 31, 1984, and to report the name and address of the transferee
and the transferor who were parties to such transaction, along with all other
information required by applicable Treasury Regulations. The partnership must
also provide this information to the transferor and the transferee. If the
partnership fails to furnish any such notification, it may be subjected to a
penalty of $50 per failure, up to an annual maximum of $100,000. Final Treasury
regulations exempt partnerships from the requirement to report any sales which
are reported by a broker on Form 1099-B.
The Code provides that depletion deductions subject to recapture under
Section 1254 of the Code constitute "unrealized receivables" within the meaning
of Section 751 of the Code. Section 1254 of the Code provides that for property
placed in service by a taxpayer after December 31, 1986, depletion deductions
which reduce the adjusted basis of such property must be recaptured as ordinary
income upon a disposition of the property (to the extent gain is recognized on
such disposition). It is unclear whether this recapture provision applies to any
portion of the depletion claimed with respect to the Royalty (placed in service
in 1983 by the Partnership) in the case of Units acquired after December 31,
1986. The Service has not issued any regulations or other pronouncements to
indicate its 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
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<PAGE> 29
so notify the Trustee may subject such a Unit holder, as well as the Trust and
the Partnership, to the above-described penalties. Without notification from
Unit holders, the Trust and Partnership cannot comply with these reporting
requirements because they have no other means of determining which Units
disposed of during the year were acquired by the transferring Unit holder
subsequent to December 31, 1986.
Other Possible Penalties. An owner of a security who receives income in
respect of such interest must report the character and amount of such income,
for federal tax purposes, in a manner which is consistent with the federal tax
reports of the entity which was the source of the income. The consistency
requirement is deemed to be waived if the taxpayer files a statement with the
Service identifying the inconsistency. Because of the presence of "street name"
investors and the possible existence of transfer record inaccuracies, holders of
interests which are actively traded in the securities markets may encounter
situations in which it is difficult to fully and accurately comply with the
consistency requirement and other federal tax reporting requirements. Certain
penalties could be assessed against a taxpayer that fails to comply with such
requirements. Because of the complexity of the federal tax reporting
requirements applicable to trusts (such as the Trust) which own interests in
partnerships (such as the Partnership) and because all of the tax attributes of
the Royalty flow through the Partnership and the Trust to the Unit holders,
there is an increased likelihood that Unit holders will violate the consistency
requirement and other reporting requirements regarding their individual federal
income tax returns and the information returns of the Trust and the Partnership.
Any violations of the consistency requirements could lead to imposition of
certain penalties on the Unit holders or other adverse results. Furthermore, the
Trust or the Partnership might be subject to certain penalties in connection
with their furnishing of statements and information to Unit holders or the
government if such statements or information prove to be inaccurate due, for
example, to differences between the transfer agent's records and actual
ownership data. The Code provides reporting requirements designed to facilitate
the transfer of information between partnerships and trusts and owners of
interests therein held by nominees.
ITEM 2. PROPERTIES.
Reference is made to Item 1 of this report.
ITEM 3. LEGAL PROCEEDINGS.
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS.
No matters were submitted to a vote of Unit holders during the fourth
quarter of 1997.
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 27, 1998, 14,975,390 Units were
outstanding and held of record by 10,377 Unit holders.
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<PAGE> 30
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 1996
and 1997 were:
<TABLE>
<CAPTION>
UNITS OF
BENEFICIAL INTEREST
--------------------- DISTRIBUTABLE
QUARTER HIGH LOW CASH PER UNIT
ENDED -------- -------- -------------
<S> <C> <C> <C>
Mar. 31, 1996.......................................... 4.75 3.50 --
Jun. 30, 1996.......................................... 4.00 2.38 --
Sept. 30, 1996......................................... 3.00 1.38 --
Dec. 31, 1996.......................................... 3.63 2.50 --
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 --
</TABLE>
Distributable cash for any quarter is distributed to Unit holders in the
month following the close of the quarter.
The Trust did not sell any unregistered securities in 1997.
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,
--------------------------------------------------------------
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Royalty proceeds(1)......... $ -- $ -- $5,235,068 $2,551,586 $6,797,931
Distributable cash(1)....... -- -- 4,662,081 -- 6,334,690
Distributable cash per
Unit...................... -- -- 0.31130 -- 0.42295
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------------------------------
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Cash........................ $1,705,582 $1,983,571 $2,300,979 $1,977,583 $ --
Total assets................ 1,705,582 2,166,784 2,484,192 2,190,501 260,059
Distributions payable....... -- -- -- -- --
Trust corpus................ -- 183,213 183,213 212,918 260,059
</TABLE>
- ------------
(1) Includes $4.3 million, $2.4 million and $2.3 million in 1995 through 1993,
respectively, related to various gas contract settlements (See Note 6 -- Gas
Contract Settlement).
The Trust has not reported estimates of total proved net oil or gas
reserves to any federal authority or agency other than the SEC.
28
<PAGE> 31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
LIKELIHOOD OF TRUST TERMINATION
As discussed in "Capital Resources and Liquidity" below and Notes 1, 3 and
10 to the financial statements included elsewhere in this Annual Report on Form
10-K, several factors occurring during 1997 have increased the likelihood of the
Trust being terminated. The combination of a significant increase in the Class A
cost carryforward and negative reserve quantity revisions during 1997, combined
with declines in oil and gas prices received by the Working Interest Owner at
December 31, 1997 from those received at December 31, 1996, 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, 1997. As a result, the
remaining unamortized carrying value of the Royalty was charged directly against
Trust corpus. Further, as described, under "Termination of the Trust," the Trust
must have $3 million or more in cash receipts during 1998 to avoid termination.
Based on current circumstances, it is unlikely that cash receipts to the Trust
will total $3 million or more in 1998, in which case the Trustee would be
required to sell the Trust's interest in the Partnership or cause the
Partnership to sell the Royalty.
RESULTS OF OPERATIONS
There were no cash distributions to Unit holders during 1997 and 1996. Cash
distributions to Unit holders totaled $4.7 million ($0.31130 per Unit) during
1995. No cash distributions were made during 1996 and 1997 because of lower gas
and oil revenues and capital expenditures. Cash distributions during 1995
resulted from $4.3 million included in Gross Proceeds because of settlement of
amounts owed the Minerals Management Service (MMS), discussed in Note 6. During
1997, total costs exceeded Gross Proceeds by approximately $16.6 million,
primarily because of the capital costs incurred to drill and evaluate West
Cameron Blocks 498 and 215. As a result, the Class A cost carry-forward
increased to $17.4 million net to the Trust as of December 31, 1997. 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,
------------------------------------------
1997 1996 1995
------------ ----------- -----------
<S> <C> <C> <C>
Gross Proceeds(1).......................... $ 2,804,130 $ 3,810,791 $ 9,807,120
Total costs(2)............................. (19,446,762) (4,489,202) (6,070,921)
Excess Class A cost carry-forward(3)....... 16,642,632 678,411 2,086,366
------------ ----------- -----------
Net Proceeds............................... -- -- 5,822,565
Percentage attributable to Royalty......... 90.0% 90.0% 90.0%
------------ ----------- -----------
Amounts payable attributable to Royalty.... -- -- 5,240,309
Percentage attributable to the Trust....... 99.9% 99.9% 99.9%
------------ ----------- -----------
Royalty Proceeds........................... -- -- 5,235,068
Trust administrative expenses.............. (356,880) (398,134) (369,101)
------------ ----------- -----------
(356,880) (398,134) 4,865,967
Interest earned............................ 78,890 80,727 119,510
Reserve for future Trust expenses(4)....... 277,990 317,407 (323,396)
------------ ----------- -----------
Distributable Cash......................... $ -- $ -- $ 4,662,081
============ =========== ===========
</TABLE>
- ---------------
(1) Gross proceeds represent amounts received by the Working Interest Owner
during the twelve month period ended November 30 of such year.
(2) Total costs represent amounts accrued by the Working Interest Owner during
the twelve month period ended November 30 of such year. Includes interest to
the Working Interest Owner of $724,370, $207,662 and $26,592, respectively.
(3) Represents Class A costs incurred in the applicable periods that remained
outstanding as of the end of such period.
29
<PAGE> 32
(4) Represents the net amount withdrawn from (added to) the Trust administrative
expense reserve during the respective period.
Gross proceeds, which include gas and oil revenues, are calculated based on
amounts received by the Working Interest Owner. Operating information follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Natural Gas
Revenues (in millions)................................. $ 1.5 $ 2.4 $ 3.5
Sales volumes (in billion cubic feet).................. 0.6 1.0 1.8
Average realization (per thousand cubic feet).......... $ 2.53 $ 2.42 $ 1.94
Oil
Revenues (in millions)................................. $ 1.3 $ 1.4 $ 1.5
Sales volumes (in thousands of barrels)................ 65.0 74.0 88.7
Average realization (per barrel)....................... $20.58 $18.80 $16.96
</TABLE>
The decline in gas volumes over the three-year period is caused primarily
by the depletion of the Eugene Island Block 10 and Vermilion Block 310 fields in
1995. The decrease in oil volumes is caused primarily by production declines at
West Cameron Block 215. 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 make-up of gas sold
under balancing agreements totaling 0.2 bcf, 0.1 bcf and 0.3 bcf, respectively.
Costs consist of the following (in millions):
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1997 1996 1995
----- ---- ----
<S> <C> <C> <C>
Lease operating expenses.................................. $ 1.0 $2.2 $2.4
Exploration and development costs......................... 17.6 1.6 2.5
Abandonment costs withheld and other...................... 0.1 0.7 1.2
----- ---- ----
===== ==== ====
</TABLE>
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.
Abandonment costs are accrued each year based on the estimate of costs required
to abandon the Trust's properties -- see Note 9.
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 Net Proceeds before any distributions
may be made to Unit holders.
Exploratory drilling on West Cameron Block 498 began in June 1994 and
ultimately resulted in four successful wells which were saved for future
production. A 12 slot, four pile drilling platform was set in March 1997, from
which four additional wells were drilled during the rest of 1997 and early 1998.
An auxiliary platform was set in October 1997, with production facilities
capable of handling 55 million cubic feet of natural gas and 15,000 barrels of
oil per day. In February, 1998 Coastal Oil & Gas
30
<PAGE> 33
Corporation (Coastal), the operator, announced average gross daily production
from the initial six wells drilled of 52 million cubic feet of gas and 7,800
barrels of oil. The two additional wells are scheduled to be placed on
production during the second quarter of 1998. Coastal also 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 in the fourth
quarter. Total expenditures net to the Trust during 1997 were $12.9 million for
this block, in which the Working Interest Owner owns a 23.1% working interest
and a 19.2% net revenue interest.
At the West Cameron 215 field the Working Interest Owner participated in
the drilling of the West Cameron 215 #8 exploratory well during the fourth
quarter of 1997. The well did not encounter any commercial hydrocarbons and was
plugged and abandoned. The cost net to the Trust was $1.6 million, which is
reflected in the cost carryforward at December 31, 1997.
Development operations were completed and the exploratory well on Breton
Sound Block 55 began production during 1997. The Working Interest Owner owns an
18.75% working interest in the block and a 9.375% working interest in the well
pursuant to a co-development agreement with the owner of an adjacent block.
Costs and ownership of the production resulting from this activity will be
retroactively adjusted based upon the location of reserves discovered following
further development of the area. The cost net to the Trust was $0.8 million
during 1997, which is reflected in the cost carryforward at December 31, 1997.
Additional exploration may be proposed by the operators of certain other Royalty
Properties. After analyzing each proposal, the Working Interest Owner will
determine whether or not to participate in additional exploratory operations.
Total exploration and development costs for 1998 are presently budgeted at
approximately $5 million for the Working Interest Owner, representing further
development of West Cameron Block 498. This estimate is derived from cost
estimates provided by the operators of the Royalty Properties and may vary from
actual costs depending on the success of drilling, particular circumstances
encountered during drilling and many other factors outside the control of the
operator. These expenditures can be expected to reduce and could further delay
resumption of distributions to Unit holders.
Estimated future abandonment costs, based on current laws and regulations,
are accrued over the life of the Trust's properties (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, 1997,
the estimated remaining aggregate abandonment costs to be incurred for all of
the Trust's properties totaled $9.5 million net to the Trust, all of which has
been withheld from distributions to Unit holders. Such costs are by their nature
imprecise and can be expected to be revised over time because of changes in
general and specific cost levels, government regulations, operations or
technology. Any further adjustments to estimated abandonment costs or variances
to actual costs will reduce or increase future distributable cash accordingly.
From 1986 through 1992, the Working Interest Owner entered into several gas
contract settlements with a gas purchaser related to the Royalty Properties
which involved payments of cash by the gas purchaser to the Working Interest
Owner. The Working Interest Owner included in Gross Proceeds the payments
received in connection with these settlements, net of amounts retained in a
suspense account representing settlement proceeds that were subject to possible
royalty obligations to the MMS. In December 1994, the Working Interest Owner
entered into an agreement with the MMS relating to these gas contract
settlements, resulting in a payment by the Working Interest Owner. After the
settlement, approximately $4 million of the funds initially retained for
possible royalty obligations
31
<PAGE> 34
remained. The Working Interest Owner informed the Trustee that it anticipated
expenditures for the development operations on the Royalty Properties in excess
of $4 million and, accordingly, proposed to retain the funds remaining in the
suspense account for use as payments of these anticipated expenditures, as
sufficient funds may not be otherwise available. The Trustee and the Working
Interest Owner evaluated the legal, tax and other issues relating to retaining
such amounts for use in the exploratory and development operations on the
Royalty Properties and concluded that the funds should be paid to the Trust.
Such funds, including interest, were included in the April 1995 Net Proceeds as
a special payment resulting in a distribution of $0.28794 per Unit.
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 $1.7 million remained at December 31, 1997.
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 or 1997. Additionally, the Class A
cost-carryforward has increased to $17.4 million at December 31, 1997, primarily
from the significant development costs incurred at West Cameron Blocks 498 and
215. This cost carry-forward must be recouped by the Working Interest Owner
before any distribution may be made to the Trust. Unless the Trust has 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. The actual level
of Trust cash receipts, if any, during 1998 will depend primarily on the rate of
production from West Cameron Block 498, the costs and results of future
exploration and development costs on West Cameron Blocks 498, oil and gas prices
and other factors. Based on current circumstances, it is unlikely that cash
receipts to the Trust will total $3 million or more in 1998, in which case the
Trustee would be required to sell the Trust's interest in the Partnership or
cause the Partnership to sell the Royalty.
32
<PAGE> 35
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,
--------------------------------------
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Royalty proceeds................................... $ -- $ -- $5,235,068
Trust administrative expenses...................... (356,880) (398,134) (369,101)
Interest income.................................... 78,890 80,727 119,510
Reserve for future Trust expenses.................. 277,990 317,407 (323,396)
---------- ---------- ----------
Distributable cash................................. $ -- $ -- $4,662,081
========== ========== ==========
Distributable cash per Unit........................ $ -- $ -- $ 0.31130
========== ========== ==========
Units outstanding.................................. 14,975,390 14,975,390 14,975,390
========== ========== ==========
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1997 1996
------------ ------------
<S> <C> <C>
ASSETS
Cash........................................................ $ 1,705,582 $ 1,983,571
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) (25,431,543)
Less, accumulated amortization of net overriding royalty
interest.................................................. (164,260,985) (164,260,985)
------------ ------------
Total assets................................................ $ 1,705,582 $ 2,166,784
============ ============
LIABILITIES AND TRUST CORPUS
Reserve for future Trust expenses........................... $ 1,705,582 $ 1,983,571
Trust corpus (14,975,390 Units of Beneficial Interest
authorized, issued and outstanding)....................... -- 183,213
------------ ------------
Total liabilities and trust corpus.......................... $ 1,705,582 $ 2,166,784
============ ============
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------
1997 1996 1995
-------- ----------- -----------
<S> <C> <C> <C>
Trust corpus, beginning of year.................... $183,213 $ 183,213 $ 212,918
Royalty proceeds and interest earned, net of trust
administrative expenses and reserve for future
Trust expenses................................... -- -- 4,662,081
Distributions payable to Unit holders.............. -- -- (4,662,081)
Adjustment to recorded cost of net overriding
royalty interest in oil and gas properties (Note
3)............................................... (183,213) -- --
Amortization of net overriding royalty interest.... -- -- (29,705)
-------- ----------- -----------
Trust corpus, end of year.......................... $ -- $ 183,213 $ 183,213
======== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
33
<PAGE> 36
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
1. THE TRUST
Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created
effective September 30, 1983. On that date, Freeport-McMoRan Inc. (FTX)
transferred a net overriding royalty interest in certain offshore oil and gas
properties to a Partnership (the Partnership) equal to 90 percent of the Net
Proceeds (as defined in the Conveyance referred to below) from FTX's working
interests in such properties and conveyed a 99.9 percent general partnership
interest in the Partnership to the Trust. See "The Royalty Properties and the
Royalty -- Computation of the Royalty." Such net overriding royalty interest is
referred to herein as the "Royalty." The Overriding Royalty Conveyance which
created the Royalty is referred to herein as the "Conveyance." The Trust is
passive, with 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. As noted
above, the Trustee is required to sell the Trust's interest in the Partnership,
or cause the Partnership to sell the Royalty, if the Trust's cash receipts for
each of three successive years are less than $3 million, thereby terminating the
Trust pursuant to (i) above. 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.
The Trust's cash receipts last reached $3 million during 1995 and there
were no cash receipts in 1996 or 1997. Additionally, the Class A
cost-carryforward has increased to $17.4 million at December 31, 1997, primarily
from the significant development costs incurred at West Cameron Blocks 498 and
215. This cost carry-forward must be recouped by the Working Interest Owner
before any distribution may be made to the Trust. Unless the Trust has cash
receipts of at least $3 million during 1998, the Trust will be terminated by one
of the means described above. The actual level of Trust cash receipts, if any,
during 1998 will depend primarily on the rate of production from West Cameron
Block 498, the costs and results of future exploration and development costs on
West Cameron Blocks 498, oil and gas prices and other factors. Based on current
circumstances, it is unlikely that cash receipts to the Trust will total $3
million or more in 1998, in which case the Trustee would be required to sell the
Trust's interest in the Partnership or cause the Partnership to sell the
Royalty.
2. THE ROYALTY
IMC Global Inc. (IGL), succeeded to FTX effective December 22, 1997,
following the merger of FTX into IGL. Accordingly, IGL is now the Working
Interest Owner and presently owns the oil and gas interests burdened by the
Royalty. The Conveyance provides that the owner of the interests burdened by the
Royalty will calculate and pay monthly to the Partnership an amount equal to 90
percent of the net proceeds for the preceding month. Net proceeds generally
consist of the excess of gross revenues received from the Royalty Properties
(Gross Proceeds), on a cash basis, over operating costs, capital expenditures
and other charges, on an accrual basis (Net Proceeds).
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Trust's financial statements, which reflect the Trust's 99.9 percent
interest in the Partnership as though the Partnership did not exist, are
prepared on the cash basis of accounting for reporting
34
<PAGE> 37
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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.
The initial carrying amount of the Royalty represents 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. As there was no discounted present value of estimated
future net cash flows 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. The adjustment does not affect royalty proceeds or
distributable cash. Neither the initial nor the December 31, 1997 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 $17,449,200 existed as of December 31,
1997. The cost carry-forward is subject to and includes interest due the Working
Interest Owner at the prime rate, which totaled $651,281 net to the Trust for
1997. This excess Class A cost carry-forward must be recouped out of future Net
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, 1997, 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 is uncertain.
35
<PAGE> 38
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
6. GAS CONTRACT SETTLEMENT
From 1986 through 1992, the Working Interest Owner entered into several gas
contract settlements with a gas purchaser related to the Royalty Properties
which involved payments of cash by the gas purchaser to the Working Interest
Owner. The Working Interest Owner included in Gross Proceeds the payments
received in connection with these settlements, net of amounts retained in a
suspense account representing settlement proceeds that were subject to possible
royalty obligations to the Minerals Management Service (the MMS). In December
1994, the Working Interest Owner entered into an agreement with the MMS relating
to these gas contract settlements, resulting in a payment by the Working
Interest Owner. After the settlement, approximately $4 million of the funds
initially retained for possible royalty obligations remained. The Working
Interest Owner informed the Trustee that it anticipated expenditures for the
development operations on the Royalty Properties in excess of $4 million and,
accordingly, proposed to retain the funds remaining in the suspense account for
use as payments of these anticipated expenditures, as sufficient funds may not
be otherwise available. The Trustee and the Working Interest Owner evaluated the
legal, tax and other issues relating to retaining such amounts for use in the
exploratory and development operations on the Royalty Properties and concluded
that the funds should be paid to the Trust. Such funds, including interest, were
included in the April 1995 Net Proceeds as a special payment resulting in a
distribution of $0.28794 per Unit.
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
Process and the Funds paid to the MMS reduced the Trust's Gross Proceeds. The
suit is in the early stages, and no trial date has been set. The amount of any
recovery with respect to this claim is presently indeterminable. However, if the
Working Interest Owner receives any amount in this litigation, a major portion
of it will be treated as Gross Proceeds.
7. ESTABLISHMENT OF AN EXPENSE RESERVE
Because of the decline in Royalty income, at certain times since late 1993
the Trust has been unable to pay its ongoing administrative expenses. To permit
the Trust to pay its routine administrative expenses during the time the Trust
incurs a Class A cost deficit, the Trustee, in accordance with the Trust
Indenture, established an expense reserve of $2.4 million of which $1,705,582
remained as of December 31, 1997. Because of the cumulative excess Class A cost
carry-forward, $277,990 was withdrawn from the expense reserve during 1997 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 4.3 percent for 1997, 3.7
percent for 1996, and 3.7 percent for 1995.
8. FEDERAL INCOME TAX MATTERS
Unit holders will be required to report taxable income for Royalty income
received by the Trust and deposited to the expense reserve even if no
distributions were received by the Unit holders. The expense reserve established
for Trust administrative expenses described in Note 7 above, however, gives rise
to tax deductions as additional administrative expenses are incurred and paid
with funds deposited in the reserve.
36
<PAGE> 39
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
9. RESERVE FOR FUTURE ESTIMATED ABANDONMENT COSTS
Estimated future abandonment costs are accrued over the life of the Trust's
properties based on current laws and regulations. During the 1997 fourth quarter
an updated assessment of estimated future abandonment costs was undertaken,
taking into consideration current 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, 1997, the estimated remaining aggregate
abandonment costs to be incurred for all of the Trust's properties totaled $9.5
million net to the Trust, 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. 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). 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, 1997, 1996 and 1995, approximately 1.4 bcf, 1.6 bcf, and 1.7 bcf sold by
other parties pursuant to certain gas balancing arrangements and (c) an excess
Class A cost carry-forward of $17.4 million, $2.5 million and $1.9 million at
December 31, 1997, 1996 and 1995, respectively. For purposes of the reserve
volume and cash flow amounts set forth below, the Trustee adjusted the estimates
of Ryder Scott to take into account the foregoing factors, based on calculations
supplied by the Working Interest Owner. In accordance with the requirements of
the FASB, the reserve disclosures below were calculated using year-end oil and
gas prices being received and current operating and abandonment cost levels.
As discussed in Note 9, based on escalated estimates of costs to abandon
the Trust properties, 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
has not considered the escalated estimates of these costs, nor has the Trustee
adjusted Ryder Scott's estimates, as the Trust is required to present the
supplementary information assuming no escalation in costs.
37
<PAGE> 40
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Proved Oil and Gas Reserves. The following table sets forth estimates of
the interest attributable to the Trust in proved oil and gas reserves and
changes in such estimates. Oil, including crude oil, condensate and natural gas
liquids, is stated in thousands of barrels; gas is stated in millions of cubic
feet.
<TABLE>
<CAPTION>
1997 1996 1995
------------------- ------------------- -------------------
OIL GAS OIL GAS OIL GAS
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of year.... 804 6,490 603 5,241 79 3,243
Changes in prices and other
revisions to previous estimates,
including impact of Class A cost
carryforward(1).................. (746) (5,969) 220 1,788 (24) 430
Extensions and discoveries(2)....... -- -- 47 360 616 2,950
Production.......................... (58) (521) (66) (899) (68) (1,382)
---- ------ --- ------ ---- -------
Proved reserves, end of year.......... -- -- 804 6,490 603 5,241
==== ====== === ====== ==== =======
</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, 1997, 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, 1997 attributable to the Trust.
(2) Includes reserves related to West Cameron Block 215 and the Breton Sound
Block 55 No. 4 well in 1996 and West Cameron Block 498 in 1995.
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, 1997 (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
38
<PAGE> 41
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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,
------------------------------------------
1997 1996 1995
----------- ------------ -----------
<S> <C> <C> <C>
Future cash flows................................. $ -- $ 44,031,000 $21,753,000
Discount for estimated timing of cash flows (10
percent discount rate).......................... (--) (18,834,000) (9,457,000)
----------- ------------ -----------
Standardized measure of discounted future net cash
flows from proved oil and gas reserves.......... $ -- $ 25,197,000 $12,296,000
=========== ============ ===========
</TABLE>
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM
PROVED OIL AND GAS RESERVES:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Discounted future net cash flows,
beginning of year......................... $25,197,000 $12,296,000 $ 7,069,000
Royalty proceeds.......................... -- -- (5,235,000)
Changes in prices and other revisions to
previous estimates, including impact of
Class A cost carryforward(1)........... (27,717,000) 9,911,000 164,000
Extensions and discoveries(2)............. -- 1,760,000 9,591,000
Accretion of discount..................... 2,520,000 1,230,000 707,000
------------ ----------- -----------
Discounted future net cash flows, end of
year...................................... $ -- $25,197,000 $12,296,000
============ =========== ===========
</TABLE>
- ------------
(1) Revisions for 1997 reflect the impact of lower oil and gas prices, negative
reserve quantity revisions and the effect of the Class A cost 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. Additionally, 1996 reflects the effects of increased oil and
gas prices from December 31, 1995 levels, while 1995 includes $4.3 million
related to the special payment (Note 6).
(2) Includes increased reserves at West Cameron Block 215 and the addition of
the Breton Sound Block 55 No. 4 well in 1996, and the discounted future net
cash flow related to West Cameron Block 498 in 1995.
39
<PAGE> 42
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Chase Bank of Texas, National Association (Trustee)
and the Unit Holders of Freeport-McMoRan
Oil and Gas Royalty Trust:
We have audited the statements of assets, liabilities and trust corpus of
Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 1997 and 1996, 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,
1997. 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, 1997 and 1996, and
the royalty proceeds and distributable cash, and changes in trust corpus for
each of the three years in the period ended December 31, 1997, on the cash basis
of accounting described in Note 3.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana,
March 30, 1998
40
<PAGE> 43
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There are no directors or executive officers of the Registrant, and to the
Trustee's knowledge no person beneficially owns more than 5 percent of the
outstanding Units. The Trustee is a corporate trustee which may be removed by
the majority vote of the of the Unit holders.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
No person is known by the Trustee to own beneficially more than 5
percent of the Units.
(b) SECURITY OWNERSHIP OF MANAGEMENT
Chase Bank of Texas, National Association, as Trustee of the Trust, owns
no Units. Chase Bank of Texas, National Association in its individual
capacity also owns no Units.
(c) CHANGE IN CONTROL
The Trust knows of no arrangements, including the pledge of Units of the
Trust, the operation of which may at a subsequent date result in a
change in control of the Trust.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The parent of ChaseTexas, Chase Manhattan Corporation, have banking
relationships with the Company.
41
<PAGE> 44
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a)1. FINANCIAL STATEMENTS
Reference is made to Item 8 of this Form 10-K.
(a)2. SCHEDULES
Schedules have been omitted because they are not required, not applicable
or the information required has been included elsewhere herein.
(a)3. EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NO.
-------
<S> <C> <C>
4.1* -- Overriding Royalty Conveyance from McMoRan-Freeport Oil
Company to McMoRan Oil & Gas Co. (attached as Annex I to
Exhibit 4.4).
4.2* -- Royalty Trust Indenture for Freeport-McMoRan Oil and Gas
Royalty Trust between Freeport-McMoRan Inc. ("FTX") and
First City National Bank of Houston, as Trustee.
4.3* -- First Amended and Restated Articles of General
Partnership of Freeport-McMoRan Oil and Gas Royalty
Partnership between McMoRan Offshore Management Co. and
First City National Bank of Houston, as Trustee.
4.4* -- Act of Assignment and Assumption and Mortgage from
McMoRan Oil & Gas Co. to FTX.
4.5* -- Act of Assignment and Assumption and Mortgage from FTX
to Freeport-McMoRan Oil and Gas Royalty Partnership (for
omitted attachments see Exhibit 4.4).
27 -- Financial Data Schedule.
</TABLE>
- ------------
* Incorporated by reference to Exhibits of like designation to the registrant's
Annual Report on Form 10-K for the period ended December 31, 1983.
(b) REPORTS ON FORM 8-K
One report on Form 8-K and one report on Form 8-K/A, both reporting events
under Item 5 as of February 3, 1998, were filed by the registrant prior to the
filing of this Form 10-K.
42
<PAGE> 45
SIGNATURE
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
FREEPORT-McMoRan OIL AND GAS
ROYALTY TRUST
By: CHASE BANK OF TEXAS,
NATIONAL ASSOCIATION, Trustee
By: /s/ PETE FOSTER
------------------------------------
Pete Foster
Senior Vice President and Trust
Officer
March 31, 1998
The Registrant, Freeport-McMoRan Oil and Gas Royalty Trust, has no
principal executive officer, principal financial officer, principal accounting
officer, board of directors or persons performing similar functions.
Accordingly, no additional signatures are required.
43
<PAGE> 46
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NO.
-------
<S> <C> <C>
4.1* -- Overriding Royalty Conveyance from McMoRan-Freeport Oil
Company to McMoRan Oil & Gas Co. (attached as Annex I to
Exhibit 4.4).
4.2* -- Royalty Trust Indenture for Freeport-McMoRan Oil and Gas
Royalty Trust between Freeport-McMoRan Inc. ("FTX") and
First City National Bank of Houston, as Trustee.
4.3* -- First Amended and Restated Articles of General
Partnership of Freeport-McMoRan Oil and Gas Royalty
Partnership between McMoRan Offshore Management Co. and
First City National Bank of Houston, as Trustee.
4.4* -- Act of Assignment and Assumption and Mortgage from
McMoRan Oil & Gas Co. to FTX.
4.5* -- Act of Assignment and Assumption and Mortgage from FTX
to Freeport-McMoRan Oil and Gas Royalty Partnership (for
omitted attachments see Exhibit 4.4).
27 -- Financial Data Schedule.
</TABLE>
- ------------
* Incorporated by reference to Exhibits of like designation to the registrant's
Annual Report on Form 10-K for the period ended December 31, 1983.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS AS OF DECEMBER 31, 1997 AND
THE STATEMENT OF ROYALTY PROCEEDS AND DISTRIBUTABLE CASH FOR THE YEAR ENDED
DECEMBER 31, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 1,705,582
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,705,582
<PP&E> 189,875,741
<DEPRECIATION> 189,875,741
<TOTAL-ASSETS> 1,705,582
<CURRENT-LIABILITIES> 1,705,582
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 1,705,582
<SALES> 0
<TOTAL-REVENUES> 78,890
<CGS> 0
<TOTAL-COSTS> 356,880
<OTHER-EXPENSES> 277,990
<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>
