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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-8581
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FREEPORT-McMoRan OIL AND GAS ROYALTY TRUST
(Exact Name of Registrant as Specified in Its Charter)
<TABLE>
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TEXAS 72-6108468
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
TEXAS COMMERCE BANK NATIONAL ASSOCIATION, TRUSTEE 77002
712 MAIN STREET
HOUSTON, TEXAS (Zip Code)
(Address of Principal Executive Offices)
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Registrant's telephone number, including area code: (713) 216-5447
Securities registered pursuant to Section 12(b) of the Act:
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NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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Units of Beneficial Interest New York Stock Exchange
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES X NO
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
-----
The aggregate market value of the 14,975,390 Units of Beneficial Interest
in Freeport-McMoRan Oil and Gas Royalty Trust held by non-affiliates of the
registrant on March 27, 1995 was approximately $56,157,712.50 based on the
closing price of the Units on the New York Stock Exchange as reported in The
Wall Street Journal.
As of March 27, 1995, 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........................................... 27
Item 2. Properties.................................................................. 28
Item 3. Legal Proceedings........................................................... 28
Item 4. Submission of Matters to a Vote of Unit Holders............................. 29
PART II
Item 5. Market for the Registrant's Units and Related Unit Holder Matters........... 29
Item 6. Selected Financial Data..................................................... 29
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.................................................................. 30
Item 8. Financial Statements and Supplementary Data................................. 33
Statements of Royalty Proceeds and Distributable Cash:
For the years ended December 31, 1994, 1993 and 1992........................ 33
Statements of Assets, Liabilities and Trust Corpus:
As of December 31, 1994 and 1993............................................ 33
Statements of Changes in Trust Corpus:
For the years ended December 31, 1994, 1993 and 1992........................ 33
Notes to Financial Statements............................................... 34
Report of Independent Public Accountants.................................... 40
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.................................................................. 41
PART III
Item 10. Directors and Executive Officers of the Registrant.......................... 41
Item 11. Executive Compensation...................................................... 41
Item 12. Security Ownership of Certain Beneficial Owners and Management.............. 41
Item 13. Certain Relationships and Related Transactions.............................. 41
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............. 42
Signature.............................................................................. 43
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PART I
ITEM 1. BUSINESS.
DESCRIPTION OF THE TRUST
Freeport-McMoRan Oil and Gas Royalty Trust (the Trust) was created under
the laws of the State of Texas. Texas Commerce Bank National Association (Texas
Commerce) serves as Trustee of the Trust. The Trustee maintains its offices at
712 Main Street, Houston, Texas 77002. The telephone number of the Trustee is
(713) 216-5447.
For a discussion of the (i) estimated reserves owned by the Trust as of
December 31, 1994 and the estimated future net income of the Trust, see the
report by Ryder Scott Company Petroleum Engineers contained on pages 10 through
16 hereof, (ii) financial condition and results of operations of the Trust, see
Item 7 appearing on pages 30 through 32 hereof and (iii) financial statements
and supplementary data of the Trust, see Item 8 appearing on pages 33 through
39, with special reference to Note 10 thereto appearing on pages 37 through 39
hereof.
Units of beneficial interest (the Units) in the Trust are traded on the New
York Stock Exchange under the trading symbol "FMR". The term "Company", as used
herein, includes Freeport-McMoRan Inc. (FTX), its divisions, direct and indirect
subsidiaries and affiliates, except as otherwise indicated by the context. The
term "Working Interest Owner" includes Freeport-McMoRan Oil & Gas Company, a
division of FTX (FMOG), and the successors and assigns of its oil and gas
working interests to the extent the context requires.
The Units are not an interest in or an obligation of the Company, the
Working Interest Owner or any successor Working Interest Owner although they
represent indirect interests in the Royalty Properties (as defined below). The
following information and the information set forth under "DESCRIPTION OF THE
UNITS" are subject to the detailed provisions of the Royalty Trust Indenture
entered into between FTX and the Trustee (the Trust Indenture) and the First
Amended and Restated Articles of General Partnership of Freeport-McMoRan Oil and
Gas Royalty Partnership (the Partnership) entered into between McMoRan Offshore
Management Co., formerly an indirect wholly owned subsidiary of FTX, and the
Trustee (the Partnership Agreement). The Trust Indenture and the Partnership
Agreement are among the exhibits to this report. The provisions governing the
Trust and the Partnership are complex and extensive, and no attempt has been
made below to describe all of such provisions. The following is a general
description of the basic framework of the Trust and the Partnership, and
reference is made to the Trust Indenture and the Partnership Agreement for
detailed provisions concerning the Trust and the Partnership.
CREATION AND TRANSFER OF THE ROYALTY
On September 30, 1983, pursuant to the terms of the Overriding Royalty
Conveyance (the Conveyance), the Company transferred, for the benefit of FTX's
stockholders, a net overriding royalty interest (the Royalty) in what then
represented 18 productive (the Productive Properties) and 12 undeveloped (the
Undeveloped Properties) oil and gas leases offshore Louisiana, Texas and
California equal to 90 percent of the net proceeds from the Company's working
interests in such properties. See "THE ROYALTY PROPERTIES AND THE
ROYALTY -- Computation of the Royalty". The Productive Properties and the
Undeveloped Properties are referred to herein jointly as the "Royalty
Properties".
FTX assigned the Royalty to the Partnership in exchange for a 99.9 percent
interest therein. Immediately thereafter, FTX assigned its 99.9 percent general
partnership interest in the Partnership to the Trust in exchange for the Units.
Units were then distributed to FTX's stockholders.
THE PARTNERSHIP
Title to the Royalty is held by the Partnership, a general partnership
formed under the laws of the State of Texas and in which the Trustee, for the
benefit of the Unit holders, has a 99.9 percent general
<PAGE> 4
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. FMOG
provides the staff and facilities to carry out the administrative duties for and
on behalf of ARPMC and FTX has indemnified the Partnership for the obligations
of ARPMC in connection with its duties and responsibilities as Managing General
Partner.
THE TRUST
Under the Trust Indenture the Trustee holds an interest in the Partnership
for the benefit of the Unit holders. The terms of the Trust Indenture provide,
among other things, that (1) the Trustee cannot engage in any business or
investment activity and cannot acquire any asset other than its interest in the
Partnership and cash being held for payment of liabilities or distribution to
Unit holders; (2) the Royalty can be sold in whole or in part for cash 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 power with
respect to the operation of the Royalty Properties. The Trust is a passive
trust, and the Trust Indenture requires the Trustee (a) to receive all income
and proceeds of the Royalty net of other Partnership expenses and net of amounts
attributable to the Managing General Partner's 0.1 percent interest in the
Partnership, (b) to pay or provide for the payment of expenses, charges,
liabilities and obligations of the Trust and (c) to distribute to Unit holders
the remaining revenues attributable to the Royalty.
Texas Commerce, which also acts as Trustee of the Trust, and its parent,
Chemical Banking Corporation, have banking relationships with the Company.
The Trust has no employees. Administrative functions of the Trust are
performed by the Trustee, which is compensated for its services and reimbursed
for specified charges for transfer agency and distribution functions out of
Trust assets. The Trustee is also entitled to reimbursement for its out-of-
pocket expenses. Due to the passive nature of the Trust assets and the
restrictions on the power of the Trustee to incur obligations, the only
liabilities which the Trustee ordinarily incurs are those for routine
administrative expenses, such as Trustee's fees and accounting, legal and other
professional fees. The costs and expenses of the Trust (including the Trustee's
fees) are currently estimated to be $0.6 million for 1995. In addition, the
Trustee, in accordance with the Trust Indenture, is establishing an expense
reserve of approximately $2.4 million to cover approximately 3 years of Trust
expenses as discussed in Note 7 -- Establishment of an Expense Reserve. This
reserve was partially funded with $1.9 million from the January 1994 settlement
payment described in Note 6 -- Gas Contract Settlement, and a portion has been
funded from Royalty income. The remaining $0.3 million will be funded from
future Royalty income received by the Trust prior to making any distributions to
Unit holders. The costs of the Partnership are expected to be minimal. 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 professional 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
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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 holders of the Units, 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. Any such sale must be for cash, and the Trustee must distribute the
net proceeds of such sale (after satisfaction of any outstanding liabilities) to
the Unit holders.
The Trustee is also authorized to agree to modifications of the terms of
the Partnership Agreement or to cause the Partnership to agree to modifications
of the terms of the Conveyance or to settle disputes with respect thereto, so
long as such modifications or settlements do not (i) alter the nature of the
Royalty as a right to receive a share of the proceeds of minerals produced from
the Royalty Properties, free of any expense or other cost and without any
operating rights, or (ii) alter the Partnership Agreement so as to change the
purposes or scope of activities of the Partnership. Furthermore, the Trustee may
not agree to any distribution from the Partnership of the Royalty, or any other
asset of the Partnership, which would cause the interest of the holders of Units
to be treated as other than an intangible personal property interest.
LIABILITIES OF THE TRUSTEE
The Trustee may act in its discretion and will be personally or
individually liable only for fraud, gross negligence or bad faith. The Trustee
will be indemnified from the Trust assets for any liability, expense, claim,
damage or other loss incurred in performing its duties, unless resulting from
fraud, gross negligence or bad faith, and will have a lien upon the assets of
the Trust as security for such indemnification and for reimbursements and
compensation to which it is entitled. The Trustee will not be entitled to
indemnification from Unit holders.
TERMINATION OF THE TRUST
The Trust Indenture provides generally that the Trust shall terminate upon
the first to occur of: (i) the sale of all the Trust's interest in the
Partnership, or the sale by the Partnership of all 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
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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 for cash the Royalty Properties
(or will cause the Partnership to sell for cash 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.
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
The Trustee determines for each month 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. There were no cash distributions to
the Unit holders for the year ended December 31, 1994.
Because the Trust is classified for tax purposes as a "grantor trust" and
the Partnership is classified for tax purposes as a partnership (see "FEDERAL
INCOME TAX CONSIDERATIONS") and is required to use the accrual method of
accounting, the net taxable income from the Royalty (other than interest earned
on Monthly Distribution Amounts) will be realized by the Unit holders for tax
purposes in the month accrued by the Partnership, rather than in the month
distributed by the Trust. Thus, a Unit holder may be required to report income
attributable to his Units without receiving distributions directly corresponding
to such income.
NATURE OF THE UNITS
The Units are not an interest in or obligation of the Company, the Working
Interest Owner or any successor Working Interest Owner. However, the ultimate
value of the Royalty is dependent to a large extent upon the ability of the
Working Interest Owner to produce oil and gas from the Royalty Properties. There
is no requirement that the Working Interest Owner expend any specific amounts
with respect to the Royalty Properties. The Working Interest Owner is free to
transfer its working interest (burdened by the Royalty) to third parties. In
certain cases (involving properties which have not been producing) 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 Development Drilling Activities". The
Working Interest Owner does not have an obligation to produce any specific
amounts of oil and gas from any of the
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Royalty Properties. It has the right to abandon any well or lease, and upon
termination of any lease the portion of the Royalty relating thereto will be
extinguished. The amount of revenues attributable to the Royalty may be affected
by operating agreements and unitization and pooling arrangements. The
realization of the ultimate value of the Royalty is subject to all the risks
associated with exploration on and development of oil and gas properties and to
comprehensive regulation by governmental authorities.
TRANSFER OF THE UNITS
Units are transferable on the records of the Trustee or transfer agent upon
the surrender of any certificate representing Units in proper form for transfer
as required by the Trustee. No service charge is made to the transferor or
transferee for any transfer of a Unit, but the Trustee may require payment of a
sum sufficient to cover any tax or other governmental charge that may be imposed
in connection with such transfer.
PERIODIC REPORTS
As promptly as practicable following the end of each quarter, the Trustee
is required to mail to each person who was a Unit holder of record on the
Monthly Record Date for any month during such quarter a report which shows in
reasonable detail the assets and liabilities and receipts and disbursements of
the Trust for such quarter and for each month in such quarter. As promptly as
practicable following the end of each fiscal year, the Trustee is required to
mail to Unit holders of record as of a date to be selected by the Trustee an
annual report containing audited financial statements of the Trust.
The Trustee is required to file such returns for federal income tax
purposes as in its judgment are required to comply with applicable law and to
permit each Unit holder to report correctly his share of the income and
deductions of the Trust. The Trustee will treat all income and deductions
recognized during each month as reportable by Unit holders of record on the
Monthly Record Date of such month unless otherwise advised by counsel or the
Internal Revenue Service.
The Conveyance provides that the Working Interest Owner maintain books and
records sufficient to determine the amounts payable to the owner of the Royalty.
On the eleventh day prior to the last business day of each month the Working
Interest Owner is required to provide the Partnership with information regarding
the amount of the Royalty payment to be made on the next Monthly Record Date.
The Working Interest Owner is also required to provide material information
regarding the Royalty Properties.
The Trustee has no duty to secure, file or disseminate information to which
it is not expressly afforded access under the terms of the instruments creating
the Trust or which it is unable to obtain without unreasonable effort and
expense.
LIABILITY OF OWNERS OF UNITS
Regarding the Unit holders, the Trust Indenture provides that the Trustee
will be fully liable if the Trustee incurs any liability, except with respect to
the income tax and oil and gas pricing matters described in the next paragraph,
without taking reasonable steps to ensure that such liability will be
satisfiable only out of the Trust assets (regardless of whether the assets are
adequate to satisfy the liability) and in no event out of amounts distributed to
or other assets owned by, Unit holders. However, under the laws of Texas (and
perhaps California, if applicable), it is unclear whether a Unit holder would be
jointly and severally liable for any liability of the Trust in the event that
both of the following conditions were to occur: (a) the satisfaction of such
liability was not by contract limited to the assets of the Trust, and (b) the
assets of the Trust were insufficient to discharge such liability. Each Unit
holder should weigh this potential exposure in deciding whether to retain or
transfer his Units. In that connection, Unit holders should consider the value
and passive nature of the Trust assets and the restrictions on the power of the
Trustee to incur liabilities.
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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 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.
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
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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 locations of the Royalty Properties in which the Trust continues to
have an interest are shown on the map on page 9. Certain information concerning
such Royalty Properties as of December 31, 1994 is shown below:
<TABLE>
<CAPTION>
WORKING GROSS NET
PROPERTY INTEREST%(1) ACRES ACRES
-------- ------------ ----- -----
<S> <C> <C> <C>
ROYALTY PROPERTIES --
Offshore Louisiana:
Breton Sound Blk. 54/55.............................. 18.75 6,946 1,302
East Cameron Blk. 336................................ 28.00 5,000 1,400
Eugene Island Blk. 10................................ 25.00 2,302 576
Vermilion Blk. 21.................................... 4.17 4,139 172
Vermilion Blk. 22.................................... 4.17 5,000 208
Vermilion Blk. 58.................................... 22.50 5,000 1,125
Vermilion Blk. 310................................... 30.00 5,000 1,500
West Cameron Blk. 65................................. 4.17 5,000 208
West Cameron Blk. 215................................ 31.28 5,000 1,564
West Cameron Blk. 498................................ 23.08 5,000 1,154
West Delta Blk. 34................................... 30.00 2,500 750
Offshore Texas:
High Island Blk. A-552(2)............................ 35.00 3,600 1,260
Offshore California:
Santa Maria Basin
OCS-P 0433 Tract 214............................... --(3) 5,693 --
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60,180 11,219
====== ======
</TABLE>
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(1) The working interest shown represents only that portion of the working
interest that is subject to the Royalty.
(2) The Working Interest Owner has farmed out its interest in a nonproductive
portion of High Island Block A-552, retaining an overriding royalty
interest burdened by the Royalty in the portion farmed out. The working
interest percentage and net acres reflect its interest in the portion of
the block not subject to the farm out.
(3) In 1985, Tract 214 in the Santa Maria Basin was farmed out, with the Working
Interest Owner retaining an overriding royalty interest burdened by the
Royalty.
As of December 31, 1994, there were 6 gross (1.45 net) productive oil wells
and 30 gross (6.92 net) productive gas wells on 13 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
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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 substantial revenue interest in all but
three of 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 Development Drilling Activities" below
for a discussion of current development and exploratory activities on certain of
the Royalty Properties.
RESERVES
A study of the proved oil and gas reserves attributable to the Royalty
Properties as of December 31, 1994, 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, 1994, 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 1995 attributable to sales of oil and gas produced in the fourth quarter of
1994. 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,
1994. Of the total discounted present value of future net cash flows
attributable to the Royalty estimated by Ryder Scott, approximately 46 percent
are under contract with Transcontinental Gas Pipeline Co. (Transco), a purchaser
of natural gas, and approximately 54 percent are expected to be sold on the spot
market. 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).
8
<PAGE> 11
[The map shows the fields offshore Louisiana and Texas with an inset map of
California identifying the location of the Trust's Royalty Properties listed on
page 7 by block or tract number as of December 31, 1994.]
9
<PAGE> 12
[RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERHEAD]
March 28, 1995
Freeport-McMoRan Oil and Gas Royalty Trust
c/o Texas Commerce Bank National Association, Trustee
600 Travis Street, Suite 1150
Houston, Texas 77002
Gentlemen:
At the request of Freeport-McMoRan Oil & Gas Company (FMOG), a
division of Freeport-McMoRan Inc. (FTX), we have prepared estimates of the
proved reserves and future production and income attributable to a net
overriding royalty interest in certain offshore leases as of December 31, 1994.
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 and offshore California. This net overriding royalty interest (Royalty)
is the property that FTX transferred to Freeport-McMoRan Oil and Gas Royalty
Partnership (Partnership), a partnership which is owned 99.9 percent by
Freeport-McMoRan Oil and Gas Royalty Trust. The term "Working Interest Owner"
includes FMOG and the successors and assigns of its oil and gas working
interests to the extent the context requires.
Thirteen 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 thirteen 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 thirteen included in our
evaluation have a material effect on the overall revenues or liabilities of the
Partnership.
FMOG has informed us that two exploratory wells have been
drilled in one of the Subject Properties (West Cameron Block 498) that
discovered oil and gas pay in multiple reservoir sands. These two wells (West
Cameron 498 No. 2 and No. 3) were drilled in 1994 and were temporarily
abandoned. FMOG also informed us that the operator and other working interest
owners (including FMOG) are participating in a 3D seismic survey on this block,
which will not be completed and interpreted until the second quarter of 1995.
The results of this survey will be used to optimize the location and extent of
future drilling. At the request of FMOG, we have not included any estimated
reserves from these wells at this time, pending interpretation of the 3D
seismic data and any future drilling.
The estimated reserve quantities and future income quantities
presented in this report are related to hydrocarbon prices. December 1994
hydrocarbon prices were used in the preparation of this report as required by
SEC guidelines; however, actual future prices may vary significantly from
December 1994 prices. Therefore, volumes of reserves actually recovered and
amounts of income actually received may differ significantly from the estimated
quantities presented in this report. The results of this study are summarized
as follows:
10
<PAGE> 13
Freeport-McMoRan Oil and Gas Royalty Trust
March 28, 1995
Page 2
SEC PARAMETERS
Estimated Net Reserve and Income Data
Freeport-McMoRan Oil and Gas Royalty Partnership
As of December 31, 1994
<TABLE>
<CAPTION>
Total
Proved
Developed
---------
<S> <C>
Remaining Reserves
Oil/Condensate - Barrels 53,568
Gas - MMCF 828
Future Net Income (FNI)
1995 $1,712,012
1996 488,081
1997 5,779
----------
Sub-Total $2,205,872
Remaining 1,458,563
----------
Total $3,664,435
Discounted FNI at 10% $2,931,152
(Compounded Annually)
</TABLE>
Liquid hydrocarbons are expressed in standard 42 gallon barrels.
All gas volumes are sales gas expressed in millions of cubic feet (MMCF) at 60
degrees Fahrenheit and 15.025 pounds per square inch absolute.
The reserve volumes and income values shown above for the
properties transferred to the Partnership were estimated from projections of
reserves and income attributable to the combined interests consisting of the
Royalty and the interest of the Working Interest Owner in the Subject
Properties. Interests related to non-consent operations and interests acquired
subsequent to the conveyance of the Royalty to the Partnership are excluded
from the calculation of Partnership income.
The future net income attributable to the Royalty was estimated
on a yearly basis from a projection of the combined Working Interest Owner and
Partnership future net income. Combined future net income values were
calculated by deducting operating expenses and capital costs from the future
gross revenue of the combined interests. Only those expenses and capital costs
necessary for the development and production of proved reserves were taken into
consideration. The annual income values for each property were further reduced
by an overhead charge furnished by the Working Interest Owner. The adjusted
annual income resulting from subtracting the overhead charge was multiplied by
a factor of 90 percent to arrive at the annual future net income of the
Partnership.
More than a sufficient amount of income has been accrued as of
December 31, 1994 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 future abandonment
costs.
11
<PAGE> 14
Freeport-McMoRan Oil and Gas Royalty Trust
March 28, 1995
Page 3
The future net income calculated for the Partnership is before
the deduction of state and federal income taxes and does not include any
adjustment for cash on hand or undistributed income. No attempt has been made
to quantify or otherwise account for any accumulated gas imbalances that may
exist. In accordance with Securities and Exchange Commission regulations,
discounted future net income values shown above were calculated by discounting
the future net income at the rate of 10 percent per year; however, such rate is
not necessarily the most appropriate discount rate. At the request of the
Working Interest Owner, annual compounding was used in the computation of
discounted future net income. Discounted future net income should not be
construed as Ryder Scott Company's estimate of fair market value since no
consideration was given to the additional factors that influence the prices at
which oil and gas properties are bought and sold, such as taxes on income,
allowance for return on investments and business risks.
It should be noted that, although the Partnership will not be
directly subject to the aforementioned deductions (operating costs, capital
costs, and overhead charges), these deductions will affect the future net
income of the Partnership as described above. Therefore, the estimated net
income attributable to the Partnership will change if actual costs differ from
those used in our estimates.
Estimates of reserves attributable to the Partnership are shown
above as required by the Securities and Exchange Commission; however, there is
no precise method of allocating estimates of physical quantities of reserves
between the Working Interest Owner and the Partnership, since the Royalty is a
net profits interest, and the Partnership does not own, and is not entitled to
receive, any specific volume of reserves. Net reserves attributable to the
Royalty were estimated by allocating to the Partnership a portion of the
estimated combined net reserves of the Subject Properties using a formula based
on future income. The quantities of reserves indicated by such formula will be
affected by future changes in various economic factors utilized in estimating
future gross revenues and net income from the Subject Properties. Therefore,
the estimates of reserves set forth above are to a large extent hypothetical
and are not comparable to estimates of reserves attributable to a working
interest At the request of the Working Interest Owner, the following formula
was used on a yearly basis to estimate the required net reserves attributable
to the Royalty of each property:
Royalty Future Net Income
Partnership Interest Net Reserves = --------------------------
Price per Unit of Reserves
The price per unit of reserves was calculated by dividing combined future gross
revenues by combined net reserves.
Reserve Definitions
The proved reserves presented in this report comply with the
Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission's Staff Accounting Bulletins, and are based
on the following definitions and criteria:
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from
known reservoirs under existing operating conditions using the cost and price
parameters discussed in other sections of this report. Reservoirs are
considered proved if economic producibility is supported by actual production
or formation tests. In certain instances, proved reserves are assigned on the
basis of a combination of core analysis and electrical and other type logs
which indicate the reservoirs
12
<PAGE> 15
Freeport-McMoRan Oil and Gas Royalty Trust
March 28, 1995
Page 4
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. Proved reserves are estimates of
hydrocarbons to be recovered from a given date forward. They may be
revised as hydrocarbons are produced and additional data become
available. Proved natural gas reserves are comprised of
non-associated, associated and dissolved gas. An appropriate
reduction in gas reserves has been made for the expected removal of
natural gas liquids, for lease and plant fuel, and for the exclusion
of nonhydrocarbon gases if they occur in significant quantities and
are removed prior to sale.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Estimates of proved reserves do not include crude oil, natural gas, or
natural gas liquids being held in underground or surface storage.
Depending on the status of development these proved reserves are
further subdivided into:
(i) "developed reserves" which are those proved reserves
reasonably expected to be recovered through existing wells
with existing equipment and operating methods, including (a)
"developed producing reserves" which are those proved
developed reserves reasonably expected to be produced from
existing completion intervals now open for production in
existing wells, and (b) "developed non-producing reserves"
which are those proved developed reserves which exist behind
the casing of existing wells which are reasonably expected to
be produced through these wells in the predictable future
where the cost of making such hydrocarbons available for
production should be relatively small compared to the cost of
a new well; and
(ii) "undeveloped reserves" which are those proved reserves
reasonably expected to be recovered from new wells on
undrilled acreage, from existing wells where a relatively
large expenditure is required, and from acreage for which an
application of fluid injection or other improved recovery
technique is contemplated where the technique has been proved
effective by actual tests in the area in the same reservoir.
Reserves from undrilled acreage are limited to those drilling
units offsetting productive units that are reasonably certain
of production when drilled. Proved reserves for other
undrilled units are included only where it can be demonstrated
with reasonable certainty that there is continuity of
production from the existing productive formation.
All proved reserves included in this report are classified as
developed.
13
<PAGE> 16
Freeport-McMoRan Oil and Gas Royalty Trust
March 28, 1995
Page 5
Estimates of Reserves
In general, the reserves included herein were estimated by
performance methods or the volumetric method; however, other methods were used
in certain cases where characteristics of the data indicated such other methods
were more appropriate in our opinion. The reserves estimated by the
performance method utilized extrapolations of various historical data in those
cases where such data were definitive in our opinion. Reserves were estimated
by the volumetric method in those cases where there were inadequate historical
performance data to establish a definitive trend or where the use of production
performance data as a basis for the reserve estimates was considered to be
inappropriate.
The reserves included in this report are estimates only and
should not be construed as being exact quantities. They may or may not be
actually recovered, and if recovered, the revenues therefrom and the actual
costs related thereto could be more or less than the estimated amounts.
Moreover, estimates of reserves may increase or decrease as a result of future
operations.
Future Production Rates
Initial production rates are based on the current producing
rates for those wells now on production. Test data and other related
information were used to estimate the anticipated initial production rates for
those wells or locations which are not currently producing. If no production
decline trend has been established, future production rates were held constant,
or adjusted for the effects of curtailment where appropriate, until a decline
in ability to produce was anticipated. An estimated rate of decline was then
applied to depletion of the reserves. If a decline trend has been established,
this trend was used as the basis for estimating future production rates. For
reserves not yet on production, sales were estimated to commence at an
anticipated date furnished by FMOG.
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
FMOG furnished us with prices in effect at December 31, 1994 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, 1994 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 1994, 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, 1994 were not considered in this study.
14
<PAGE> 17
Freeport-McMoRan Oil and Gas Royalty Trust
March 28, 1995
Page 6
Gas
The Working Interest Owner has furnished us with gas prices in
effect at December 1994 and with its forecasts of future gas prices which take
into account SEC guidelines, current market prices, contract prices and fixed
and determinable price escalations where applicable. 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. For gas sold under contract, the contract gas price including fixed and
determinable escalations, exclusive of inflation adjustments, was used until
the contract expires and then was adjusted to the current market price for the
area and held at this adjusted price to depletion of the reserves. At the
request of the Working Interest Owner, a market price of $1.49 per MMBTU was
used in this study for all uncontracted gas and for gas produced subsequent to
the expiration of gas contracts.
Costs
The current operating, development and overhead costs were held
constant throughout the life of the properties. The estimated net cost of
abandonment after salvage was used in our estimates of future revenue from the
Subject Properties since these costs are relatively large in offshore areas.
The estimates of the net abandonment costs for the Subject Properties were
furnished by the Working Interest Owner and were accepted without independent
verification.
All operating, development 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 and 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 1994.
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.
15
<PAGE> 18
Freeport-McMoRan Oil and Gas Royalty Trust
March 28, 1995
Page 7
Neither Ryder Scott Company nor any of its employees has any
interest in the Subject Properties and neither the employment to make this
study nor the compensation is contingent on our estimates of reserves and
future income for the Subject Properties.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Kent A. Williamson, P. E.
Group Vice President
KAW/sw
16
<PAGE> 19
Of the total discounted present value of future net cash flows attributable
to the Royalty estimated by Ryder Scott, approximately 29 percent was accounted
for by West Delta Block 34, 39 percent by West Cameron Block 215 and 16 percent
by West Cameron Block 65.
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. See "Computation of the Royalty" below.
The Ryder Scott estimates were prepared on the basis of estimated
production and Costs accrued after December 31, 1994. Thus, amounts received by
the Working Interest Owner after November 30,
17
<PAGE> 20
1994 attributable to production during 1994 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 1994. The Working Interest Owner has estimated that if
Ryder Scott had taken into account the 1995 Gross Proceeds from 1994 production,
the total estimated future net cash flow in the Ryder Scott letter would have
been approximately $1.1 million higher and the discounted present value of such
estimate would have been approximately $0.9 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
or proceeds to be received in connection with the Transco gas settlement (see
Note 5 -- Gas Balancing Arrangements, Note 6 -- Gas Contract Settlement, 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 not been reduced for costs and expenses of the Trust, which are currently
estimated at $0.6 million per year, or of the Partnership, which are expected to
be minimal. Ryder Scott also did not take into account the approximately $4
million of funds retained by the Working Interest Owner in a suspense account,
as described in Note 6 -- Gas Contract Settlement.
COMPUTATION OF THE ROYALTY
The following information is subject to the detailed provisions of the
Conveyance that created the Royalty. The definitions, formulas, accounting
procedures and other terms governing the computation of the Royalty are complex
and extensive, and no attempt has been made below to describe all of such
provisions. The following is a general description of the computation of the
Royalty, and reference is made to the Conveyance, which is an exhibit to this
report and is available from the Trustee upon request, for detailed provisions
concerning such computation.
The Royalty is a property interest which was carved out of working
interests in leases or portions thereof owned by the Company immediately prior
to the creation of the Royalty. Therefore, the obligation to calculate and pay
amounts attributable to the Royalty under the Conveyance is the obligation of
the owner of the working interest out of which the Royalty was carved. The
Working Interest Owner is free to transfer any portion of its working interest,
burdened by the Royalty, and in the case of such transfer, the transferred
interest will be treated as a separate property for purposes of computation of
amounts payable pursuant to the Royalty. Until such transfer takes place, all of
the Royalty Properties will be treated as one property for purposes of
computation of amounts payable under the Conveyance.
The Royalty entitles the holder thereof to 90 percent of the Net Proceeds
realized from the sale of oil, gas and other hydrocarbons, as, if, and when
produced from the working interests subject to the Royalty. Under the
Conveyance, "Net Proceeds" generally means the excess of Gross Proceeds received
(on a cash basis) during a particular month over Costs incurred (on an accrual
basis) during such month. Generally, such Costs include any excess of Costs over
Gross Proceeds carried forward
18
<PAGE> 21
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
equal to Adjusted Gross Proceeds for such month and the denominator of which is
total estimated future Adjusted Gross Proceeds for such month and all future
months. For this purpose, "Adjusted Gross Proceeds" means Gross Proceeds for a
month less all Class A Costs for such month, such costs that were not covered in
the previous month and interest thereon. Class A Costs are all costs that are
not Class B Costs. Class B Costs for a month are (a) costs incurred to discover
or develop minerals on certain leases, (b) any monthly future cost accruals, (c)
such costs that were not covered by proceeds in the previous month and (d)
interest thereon.
If Costs exceed Gross Proceeds for any month, the excess will be recovered
by the Working Interest Owner, with interest at the prime rate (as defined in
the Conveyance), compounded monthly, out of future Gross Proceeds prior to the
making of further payments to the Partnership, but the Partnership and the
Trustee are not liable for any operating, capital or other costs or liabilities
attributable to the Royalty Properties or hydrocarbons produced therefrom. Such
recovery will apply to Class B Costs as well. The Partnership and the Trustee
are not obligated to return any Royalty income received in any period, but
overpayments made by the Working Interest Owner would reduce future amounts
payable.
The Working Interest Owner is required to maintain books and records
sufficient to determine the amounts payable under the Conveyance. Additionally,
in the event of a controversy between the Working Interest Owner and any
purchaser as to the correct sales price of any production, amounts received by
the Working Interest Owner and promptly deposited by it with an escrow agent
shall not be considered as having been received by the Working Interest Owner,
and therefore shall not be included as Gross Proceeds, until the controversy is
resolved, but all amounts thereafter paid to the Working Interest Owner by the
escrow agent shall be considered Gross Proceeds. Similarly, Costs will include
any amounts the Working Interest Owner is required to pay as a refund, interest
or penalty because the amount received by it as a sales price was in excess of
that permitted by the terms of any applicable contract, statute, regulation,
order, decree or other obligation. Because the Units are publicly traded,
purchasers of Units in the market may, as a result of such procedures, receive
distributions of amounts that would have been distributed to former holders if
such amounts had not been held in escrow or, conversely, may have their
distributions reduced or eliminated as a result of controversies about amounts
which may have been collected. Within 30 days following the close of
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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) a delay 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 which are not presently
proved, 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 Development Drilling
Activities" below.
Oil and Gas Surplus and Other Marketing Factors. The prices of crude
oil have fluctuated significantly in recent years primarily as a result of
an oversupply of crude oil on world markets. Such surplus, as well as other
factors beyond the Working Interest Owner's control may affect adversely
both the availability of a ready market for production from the Royalty
Properties and the sales prices received for such production. A surplus of
gas deliverability continues to exist in many areas of the United States.
Gas market conditions have been significantly affected by gas price
competition related to this excess deliverability, price 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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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.
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 13 remaining Royalty Properties, 12 are currently producing. For a
discussion concerning the oil and gas production from such properties in 1994,
as well as information concerning drilling activities on such properties during
1994, see Item 7 -- Management's Discussion and Analysis of Financial Condition
and Results of Operations beginning on page 30 and Note 10 -- Supplementary
Proved Oil and Gas Reserve Information.
OPERATING AGREEMENTS
All of the remaining Royalty Properties are operated by oil and gas
companies that are not affiliated with the Company. Costs attributable to the
Royalty Properties generally will be computed 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
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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.
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 1994 was approximately 16 percent
lower than the average price received during 1993. 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 has held several long-term gas purchase
contracts with Transco. By agreement effective October 1, 1988, and amended by
agreement effective October 1, 1991, the Working Interest Owner and Transco
agreed to cancel most of the existing long-term contracts and to enter into new
gas purchase contracts which provide for an initial fixed price which is below
the prices provided for in such cancelled contracts, but above then current spot
market prices, plus an agreed
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escalation to such fixed price. In consideration of the Working Interest Owner
agreeing to cancel such contracts, the Working Interest Owner received
approximately $12.3 million attributable to the Royalty Interest, of which $3.7
million was withheld for the IDC Recapture Amount and $8.6 million was included
in Gross Proceeds for the distribution attributable to Unit holders of record on
January 31, 1989, plus an obligation by Transco to pay an additional amount of
$9.3 million which was received by the Working Interest Owner and included in
Gross Proceeds for the distribution attributable to Unit holders of record on
January 31, 1992, plus the obligation by Transco to make two additional future
payments which resulted in payments received by the Working Interest Owner
attributable to the Royalty as follows: (1) $2.6 million plus interest at 10
percent per annum on or before January 2, 1993, which was included in the
distribution paid January 29, 1993 and (2) $2.6 million plus interest at 10
percent per annum on or before January 4, 1994, of which approximately $0.5
million was used to eliminate the cost carry-forward at December 31, 1993 and
approximately $1.9 million was used to partially fund the $2.4 million reserve
being established for Trust administrative expenses. See additional discussion
in Note 6 -- Gas Contract Settlement and Note 7 -- Establishment of an Expense
Reserve. The Working Interest Owner continues to sell gas at spot market prices
from those 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.
Presently Producing Properties. Gas is currently being produced from 12 of
the 13 remaining Royalty Properties. Gas production from 5 of the Royalty
Properties (including West Delta Block 34 and Vermilion Block 310, which
accounted for approximately 45 percent of the Working Interest Owner's revenues
from the Royalty Properties during 1994) is subject to gas purchase contracts
with Transco. Gas sales to Transco accounted for approximately 48 percent, 53
percent and 61 percent of the Working Interest Owner's revenues attributable to
oil and gas production from the Royalty Properties in 1994, 1993 and 1992,
respectively.
REGULATION
The production, sale and transportation of oil and gas from the Royalty
Properties are subject to various forms of regulation by federal and state
authorities, and are affected from time to time in varying degrees by political
developments.
Energy Regulation. The Working Interest Owner is subject to regulation by
the Federal Energy Regulatory Commission (FERC) with respect to various aspects
of its natural gas operations under the Natural Gas Act of 1938 and the Natural
Gas Policy Act (NGPA). The Natural Gas Wellhead Decontrol Act of 1989 amended
both the price and non-price control provisions of the NGPA for the purpose of
providing complete decontrol of first sales of natural gas by January 1, 1993.
Consequently, the Working Interest Owner believes the Trust's gas may be sold at
market prices, subject to applicable contract provisions.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, and 636-B
(Order No. 636), which require interstate pipelines to provide transportation
separate, or "unbundled", from the pipelines' sales of gas. Also, Order No. 636
requires pipelines to provide open-access transportation on a basis that is
equal for all gas supplies. Although Order No. 636 does not directly regulate
the Working Interest Owner's activities, the FERC has stated that Order No. 636
is intended to foster increased competition within all phases of the natural gas
industry. It is unclear what impact, if any, increased competition within the
natural gas industry under Order No. 636 will have on the Working Interest
Owner's activities. Although Order No. 636, assuming it is upheld in its
entirety, could provide the Working Interest Owner with additional market access
and more fairly applied transportation service rates, Order No. 636 could also
subject the Working Interest Owner to more restrictive pipeline imbalance
tolerances and greater penalties for violation of those tolerances. As of early
1995, FERC had issued final orders accepting most pipelines' Order No. 636
compliance filings, and had commenced a series of one year reviews of individual
pipeline implementations of Order No. 636. Numerous parties have filed petitions
for review of Order No. 636, as well as orders in individual pipeline
restructuring proceedings. Upon such judicial review, these orders may be
remanded or
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reversed in whole or in part. With Order No. 636 subject to court review, and
pending ongoing FERC reviews of individual pipeline restructurings, it is
difficult to predict with precision its ultimate effects.
In December 1992, the FERC issued Order No. 547, governing the issuance of
blanket marketer sales certificates to all natural gas sellers other than
interstate pipelines. The order eliminates the need for natural gas producers
and marketers to seek specific authorization under Section 7 of the NGA from the
FERC to make sales of natural gas for resale. The FERC intends Order No. 547, in
tandem with Order No. 636, to foster a competitive market for natural gas by
giving natural gas purchasers access to multiple supply sources at market-driven
prices. Order No. 547 does not apply to sales by the Trust of gas produced from
its own properties, but Order No. 547 may increase competition in markets in
which the Trust's natural gas is sold.
FERC has recently announced its intention to re-examine certain of its
transportation-related policies, including the appropriate manner in which
interstate pipelines release transportation capacity under Order No. 636, and
the use of market-based rates for interstate gas transmission. While any
resulting FERC action would affect the Company only indirectly, these inquires
are intended to further enhance competition in natural gas markets.
Commencing in October 1993, 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 pipelines to make rate changes to track
changes in the Producer Price Index for Finished Goods, minus one percent,
became effective January 1, 1995. FERC's decision in this matter is currently
the subject of various petitions for judicial review. The Working Interest Owner
is not able at this time to predict the effects of Order Nos. 561 and 561-A, if
any, on the transportation costs associated with oil production from the
interests burdened by the Royalty, or the effect of such rules on the Trust.
The Outer Continental Shelf Lands Act (OCSLA) requires that all pipelines
operating on or across the Outer Continental Shelf (OCS) provide open-access,
non-discriminatory service. Although the FERC has opted not to impose the
regulations of Order No. 509, which implements the OCSLA, on gatherers and other
non-jurisdictional entities, the FERC has retained the authority to exercise
jurisdiction over those entities if necessary to permit non-discriminatory
access to service on the OCS. In addition, gathering lines are currently exempt
from the FERC's jurisdiction, regardless of whether they are on the OCS, but the
FERC could eliminate this exemption. Commencing in May 1994, FERC issued a
series of orders in individual cases that delineate its gathering policy. Among
other matters, FERC slightly narrowed its statutory tests for establishing
gathering status and reaffirmed that, except in situations in which the gatherer
acts in concert with an interstate pipeline affiliate to frustrate FERC's
transportation policies, it does not have jurisdiction over gathering facilities
and services and that such facilities and services are properly regulated by
state authorities. This FERC action may further encourage regulatory scrutiny of
natural gas gathering by state agencies. In addition, FERC has approved several
transfers by interstate pipelines of gathering facilities to unregulated,
independent or affiliated gathering companies. This could increase competition
among gatherers in areas with more than one gatherer. In other areas, it may
eliminate federal regulatory protection previously available. Certain FERC
orders delineating its new gathering policy are subject to pending court
appeals. The policies may be revised or reversed as a result. The new gathering
policy thus far announced by FERC does not address its jurisdiction over
pipelines operating on or across the OCS pursuant to the OCSLA. If the FERC were
to apply Order No. 509 to gatherers in the OCS, eliminate the exemption of
gathering lines, and redefine its jurisdiction over gathering lines, then these
acts could result in a reduction in available pipeline space for existing
shippers in the Gulf of Mexico and elsewhere, such as the Working Interest
Owner.
Certain operations the Working Interest Owner conducts 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
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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, and has recently proposed
additional safety-related regulations concerning the design and operating
procedures for OCS production platforms and pipelines. 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".
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 the calculation of Gross Proceeds
the payments received in connection with these settlements, net of amounts
retained in a suspense account representing settlement proceeds that were
subject to possible royalty obligations to the MMS. In December 1994, the
Working Interest Owner entered into an agreement with the MMS relating to these
gas contract settlements, resulting in a payment by the Working Interest Owner
to the MMS. After this payment, approximately $4 million of the funds retained
remain in the suspense account. The Working Interest Owner has informed the
Trustee that it anticipates expenditures within the near future for development
operations on the Royalty Properties in excess of $4 million and, accordingly,
will 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 is evaluating the legal, accounting, tax and other issues
relating to the authority of the Working Interest Owner to retain such amounts
for use in exploratory and development operations on the Royalty Properties.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time-to-time by Congress, the FERC, state
regulatory bodies, and the courts. The Working Interest Owner cannot predict
when or if any such proposals might become effective, or their effect, if any,
on the Trust. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.
Environmental Regulation. The Working Interest Owner's oil and gas
activities on the Royalty Properties are subject to existing federal, state and
local laws and regulations relating to health, safety, environmental quality and
pollution control. The Working Interest Owner has advised the Trustee that it
believes that its operations and facilities are in general compliance with
applicable health, safety, and environmental laws and regulations. Events in
recent years have, however, heightened environmental concerns about the oil and
gas industry generally, and about offshore operations in particular. As a
consequence, offshore oil and gas leases are subject to extensive governmental
regulation, including regulations that may in certain circumstances impose
absolute liability upon lessees for cost of removal of pollution and for
pollution damages resulting from their operations, and that may require lessees
to pay penalties, or even to suspend or cease operations in the affected areas.
Although the Working Interest Owner has advised the Trustee that current
environmental regulation has not had a material adverse effect on the Working
Interest Owner's present method of operations, the impact of changes in
environmental laws, such as stricter environmental regulation and enforcement
policies, cannot be predicted at this time.
The Oil Pollution Act of 1990 (OPA) and regulations promulgated pursuant
thereto impose a variety of obligations on "responsible parties" with respect to
the prevention of oil spills and liability
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for damages resulting from such spills. A "responsible party" includes the owner
or operator of a facility or vessel. For offshore facilities, the responsible
party is the lessee or permittee or holder of a right of use and easement
(granted under applicable state law or OCSLA) of the area in which the offshore
facility is located. The OPA assigns liability to each responsible party for oil
removal costs and a variety of public and private damages, including natural
resource damages. While liability limits apply in some circumstances, a
responsible party for an Outer Continental Shelf facility must pay all spill
removal costs incurred by a federal, state or local government. The OPA
establishes a liability 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. These
include proof of financial responsibility to cover at least some costs in a
potential spill. On August 25, 1993, the MMS published an advance notice of its
intention to adopt a rule under OPA that would require responsible parties for
offshore oil and gas facilities to establish evidence of $150 million in
financial responsibility. Under the MMS advance description of its future
rulemaking, financial responsibility could be established through insurance,
guaranty, indemnity, surety bond, letter of credit, qualification as a self-
insurer or a combination thereof. There is substantial opposition to the
proposed rulemaking throughout the offshore oil and gas industry, and the MMS
has informally indicated that it will not move forward with adoption of the rule
until the United States Congress has had an opportunity to reconsider financial
responsibility requirements imposed under OPA. The final form of any financial
responsibility rule that may be adopted by the MMS cannot be predicted at this
time; however, such rule has the potential to result in the imposition of
additional annual costs on the Working Interest Owner's operations.
OPA also imposes other requirements, such as preparation of an oil spill
contingency plan. A failure to comply with ongoing requirements or inadequate
cooperation in a spill event may subject a responsible party to civil or
criminal enforcement action. In short, the OPA places a burden on offshore lease
holders to conduct safe operations and take other measures to prevent oil
spills; if one occurs, the OPA then imposes liability for resulting damages.
In addition, the Outer Continental Shelf Lands Act authorizes regulations
relating to safety and environmental protection applicable to lessees and
permittees operating on the Outer Continental Shelf. Specific design and
operational standards may apply to Outer Continental Shelf vessels, rigs,
platforms, vehicles and structures. Violations of environmental related lease
conditions or regulations issued pursuant to the Outer Continental Shelf Lands
Act 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 or citizen
prosecution.
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.
At least two courts have recently 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. 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 require-
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ments 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 Outer Continental Shelf Lands Act, the regulations promulgated
thereunder and possibly certain provisions of the laws of the adjacent states.
The Conveyance contains a special warranty of title in which the Company
warranted title to the Royalty against persons claiming by, through or under the
Company, but not otherwise.
FEDERAL INCOME TAX CONSIDERATIONS
All Unit holders are urged to consult their own tax advisors regarding the
effects of acquisition, ownership and disposition of Units on their personal tax
positions.
INTERNAL REVENUE SERVICE RULINGS
The following information regarding FTX's private letter rulings 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. The Distribution will be treated for federal income tax purposes
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
27
<PAGE> 30
required to notify the Service of any such sale or exchange (of which it has
notice) of a partnership interest after December 31, 1984, and to report the
name and address of the transferee and the transferor who were parties to such
transaction, along with all other information required by applicable Treasury
Regulations. The partnership must also provide this information to the
transferor and the transferee. If the partnership fails to furnish any such
notification, it may be subjected to a penalty of $50 per failure, up to an
annual maximum of $100,000. Final Treasury regulations exempt partnerships from
the requirement to report any sales which are reported by a broker on Form
1099-B.
The Code provides that depletion deductions subject to recapture under
Section 1254 of the Code constitute "unrealized receivables" within the meaning
of Section 751 of the Code. Section 1254 of the Code provides that for property
placed in service by a taxpayer after December 31, 1986, depletion deductions
which reduce the adjusted basis of such property must be recaptured as ordinary
income upon a disposition of the property (to the extent gain is recognized on
such disposition). It is unclear whether this recapture provision applies to any
portion of the depletion claimed with respect to the Royalty (placed in service
in 1983 by the Partnership) in the case of Units acquired after December 31,
1986. The Service has not issued any regulations or other pronouncements to
indicate its interpretation of these recapture provisions as they might affect
the transfer of partnership interests. Accordingly, Unit holders disposing of
Units acquired after December 31, 1986 (other than through a broker) may be
required to notify the Trustee in writing of such disposition and provide the
Trustee with the Unit holder's name, address, taxpayer identification number and
the date of the disposition. Failure to so notify the Trustee may subject such a
Unit holder, as well as the Trust and the Partnership, to the above-described
penalties. Without notification from Unit holders, the Trust and Partnership
cannot comply with these reporting requirements because they have no other means
of determining which Units disposed of during the year were acquired by the
transferring Unit holder subsequent to December 31, 1986.
Other Possible Penalties. An owner of a security who receives income in
respect of such interest must report the character and amount of such income,
for federal tax purposes, in a manner which is consistent with the federal tax
reports of the entity which was the source of the income. The consistency
requirement is deemed to be waived if the taxpayer files a statement with the
Service identifying the inconsistency. Because of the presence of "street name"
investors and the possible existence of transfer record inaccuracies, holders of
interests which are actively traded in the securities markets may encounter
situations in which it is difficult to fully and accurately comply with the
consistency requirement and other federal tax reporting requirements. Certain
penalties could be assessed against a taxpayer that fails to comply with such
requirements. Because of the complexity of the federal tax reporting
requirements applicable to trusts (such as the Trust) which own interests in
partnerships (such as the Partnership) and because all of the tax attributes of
the Royalty flow through the Partnership and the Trust to the Unit holders,
there is an increased likelihood that Unit holders will violate the consistency
requirement and other reporting requirements regarding their individual federal
income tax returns and the information returns of the Trust and the Partnership.
Any violations of the consistency requirements could lead to imposition of
certain penalties on the Unit holders or other adverse results. Furthermore, the
Trust or the Partnership might be subject to certain penalties in connection
with their furnishing of statements and information to Unit holders or the
government if such statements or information prove to be inaccurate due, for
example, to differences between the transfer agent's records and actual
ownership data. The Code provides reporting requirements designed to facilitate
the transfer of information between partnerships and trusts and owners of
interests therein held by nominees.
ITEM 2. PROPERTIES.
Reference is made to Item 1 of this report.
ITEM 3. LEGAL PROCEEDINGS.
None.
28
<PAGE> 31
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 1994.
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, 1995, 14,975,390 Units were
outstanding and held of record by 14,419 Unit holders.
The high and low sales prices of the Units as reported on the New York
Stock Exchange and distributable cash per Unit for each quarterly period of 1993
and 1994 were:
<TABLE>
<CAPTION>
UNITS OF
BENEFICIAL
INTEREST DISTRIBUTABLE
QUARTER ---------------- CASH PER
ENDED HIGH LOW UNIT
----- ----- --------
<S> <C> <C> <C>
Mar. 31, 1993.......................................... $5.25 $4.38 $ .24739
Jun. 30, 1993.......................................... 5.13 4.50 .09726
Sept. 30, 1993......................................... 4.75 2.75 .07830
Dec. 31, 1993.......................................... 3.63 2.25 --
Mar. 31, 1994.......................................... 3.25 2.25 --
Jun. 30, 1994.......................................... 5.63 1.75 --
Sept. 30, 1994......................................... 7.75 4.38 --
Dec. 31, 1994.......................................... 6.75 4.00 --
</TABLE>
Distributable cash for any quarter is distributed to Unit holders in the
month following the close of the quarter.
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,
----------------------------------------------------------------------
1994 1993 1992 1991 1990
---------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Royalty proceeds(1).... $2,551,586 $ 6,797,931 $16,760,989 $32,611,061 $15,919,684
Distributable
cash(1).............. -- 6,334,690 16,068,705 38,451,775(2) 15,279,175
Distributable cash per
Unit................. -- .42295 1.07296 2.56760 1.02023
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------------------------------------
1994 1993 1992 1991 1990
---------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Cash................... $1,977,583 $ -- $ 1,475,861 $30,779,763 $ 2,465,414
Total assets........... 2,190,501 260,059 1,834,623 31,932,709 19,961,610
Distributions
payable.............. -- -- 1,475,861 30,779,763 2,465,414
Trust corpus........... 212,918 260,059 358,762 1,152,946 17,496,196
</TABLE>
------------
(1) Includes $2.4 million, $2.3 million, $9.3 million, $0.8 million and $5.5
million in 1994, 1993, 1992, 1991 and 1990, respectively, related to
various gas contract settlements. Also includes $22.1 million in 1991
related to the reversal of the IDC recapture charges previously deducted.
(2) Includes $6.3 million paid to the Trust for interest on the IDC Recapture
reversal.
29
<PAGE> 32
The Trust has not reported estimates of total proved net oil or gas
reserves to any federal authority or agency other than the SEC.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
RESULTS OF OPERATIONS
During 1994, The Trust's portion of Royalty proceeds attributable to
production from the Royalty Properties amounted to $2.6 million. After giving
effect to interest income of $0.05 million and Trust administrative expenses of
$0.63 million, the remaining $2.0 million was applied to the funding of a
reserve for future Trust administrative expenses (See Note 7 -- Establishment of
an Expense Reserve) resulting in no distribution to Unit holders.
There were no cash distributions to the Unit holders for the year ended
December 31, 1994 compared with $6.3 million, or $0.42295 per Unit, for 1993.
The reduced cash available for distribution was caused primarily by lower gas
production, higher capital expenditures and the funding of the reserve for Trust
administrative expenses partially offset by lower abandonment accruals.
Gas revenues included in the 1994 Royalty proceeds totaled $6.3 million
compared with $10 million for 1993. Gas volumes decreased 36 percent to 2.8
billion cubic feet (bcf) in 1994 from 4.4 bcf in 1993 primarily because of the
depletion of wells at West Delta Block 34 and East Cameron Block 336 and the
depletion of the West Cameron Block 498 field, as well as normal production
declines at other properties. The average gas price realization for 1994 was
$2.46 per thousand cubic feet (mcf), compared with $2.54 per mcf in 1993. Gas
volumes included make up of gas sold under balancing agreements totaling 0.7 bcf
in both 1994 and 1993.
Oil revenues of $2 million and $1.9 million were included in Royalty
proceeds for 1994 and 1993, respectively. Oil volumes increased 21 percent to
145,800 barrels (bbls) in 1994 from 120,900 bbls in 1993, primarily as a result
of increased oil production at West Cameron 251. The increase in oil volumes was
partially offset by a decrease in the average oil price realization to $14.97
per bbl in 1994 compared with $17.92 per bbl in 1993.
Capital costs reduced 1994 Royalty proceeds by $4.3 million, or $0.28964
per Unit, compared to a $2.4 million, or $0.16052 per Unit, reduction in 1993.
This increase in capital costs for 1994 was the result of costs incurred in
connection with exploratory drilling on West Delta Block 34, West Cameron Block
65 and West Cameron Block 498.
Accruals for future estimated abandonment costs reduced Royalty proceeds by
$1.4 million, or $0.09188 per Unit, in 1994 compared with $3.6 million, or
$0.23764 per Unit in 1993.
Cash distributions to Unit holders for the year ended December 31, 1993
amounted to $6.3 million or $0.42295 per Unit, compared to $16.1 million or
$1.07296 per Unit, for 1992. The 1993 distribution reflects a 61 percent
decrease, primarily due to the lower settlement payments received from a gas
purchaser, higher abandonment accruals, higher capital expenditures and lower
gas production in 1993.
Settlement payments received by the Trust from a natural gas purchaser (see
Note 6 -- Gas Contract Settlement) totaled $2.3 million, or $0.15315 per Unit,
in January 1993 compared to $9.3 million, or $0.61744 per Unit, in January 1992.
As a result of the need to increase accruals for future estimated abandonment
costs, distributions were reduced by $3.6 million, or $0.23764 per Unit, in 1993
compared to $1.2 million, or $0.07820 per Unit, in 1992. Capital costs reduced
1993 Royalty proceeds by $2.4 million, or $0.16052 per Unit, compared to a $0.7
million, or $0.04890 per Unit, reduction in 1992 distributions. The increase in
capital costs in 1993 was the result of costs incurred in connection with
exploratory drilling on West Delta Block 34.
Distributable cash for 1993 included gas revenues of $10 million compared
to $10.7 million for 1992. Gas volumes decreased 13 percent to 4.4 bcf in 1993
from 5.1 bcf in 1992. This decrease was primarily due to a decrease in
production on West Delta Block 34 because of platform maintenance and repairs,
the depletion of a well at West Cameron Block 494 and a well at High Island
Block A-552,
30
<PAGE> 33
together with normal production declines. This decrease was mitigated by an
increase in production on a recompleted gas well at West Cameron Block 215 and
an $0.18 per mcf increase in the average gas price realization to $2.54 per mcf
in 1993 compared to $2.36 per mcf in 1992. Gas volumes included make-up of gas
sold under certain balancing agreements totaling 0.7 bcf in 1993 and 0.6 bcf in
1992.
Oil revenues of $1.9 million and $1.1 million were included in
distributable cash for 1993 and 1992, respectively. Oil volumes increased to
120,900 bbls in 1993 from 64,300 bbls in 1992, primarily as a result of the
increased production from a recompleted well at West Cameron Block 215. The
increase in oil production was partially offset by a decrease in the average oil
price realization to $17.92 per bbl in 1993 compared to $19.37 per bbl in 1992.
CAPITAL RESOURCES AND LIQUIDITY
All revenues received by the Trust, net of Trust administrative expenses
and liabilities, are generally distributed to the Unit holders in accordance
with provisions of the Trust Indenture. Primarily as a result of costs
associated with additional seismic and exploratory drilling activity anticipated
at West Cameron Block 498 and the continued funding of the reserve for Trust
administrative expenses, the amount and timing of future distributions to Unit
holders is presently indeterminable.
Capital expenditures associated with the exploratory activities at West
Cameron Block 498 for 1995 are currently estimated to be $3.5 million net to the
Trust, including the cost of the 3D seismic survey begun in November 1994. Total
capital expenditures for 1995 are presently budgeted at $3.9 million net to
Trust, including West Cameron Block 498 activities. However, the extent of
additional future capital expenditures will depend upon the seismic and drilling
results at West Cameron Block 498. Actual expenditures could vary significantly
from the estimate. 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 the calculation
of Gross Proceeds the payments received in connection with these settlements,
net of amounts retained in a suspense account representing settlement proceeds
that were subject to possible royalty obligations to the MMS. In December 1994,
the Working Interest Owner entered into an agreement with the MMS relating to
these gas contract settlements, resulting in a payment by the Working Interest
Owner to the MMS. After this payment, approximately $4 million of the funds
retained remain in the suspense account. The Working Interest Owner has informed
the Trustee that anticipates expenditures within the near future for development
operations on the Royalty Properties in excess of $4 million and, accordingly,
will 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 is evaluating the legal, accounting, tax and other issues
relating to the authority of the Working Interest Owner to retain such amounts
for use in exploratory and development operations on the Royalty Properties.
These cost estimates are provided by the outside operators and may vary
from actual costs depending on the success of drilling, difficulties incurred
and numerous other factors outside the control of the operator. The operators of
the Trust properties are analyzing other capital expenditures for exploration
and development activities. These expenditures would serve to reduce and could
further delay resumption of distributions to Unit holders.
West Delta Block 34 Well Nos. 10 and 11 were plugged and abandoned during
the first quarter of 1994 due to unexpected adverse results from production
tests which were below the minimum requirements for the wells to sustain
commercial production. Total capital expenditures associated with these two
wells equaled $4.6 million net to the Trust, of which $2.5 million were incurred
in 1994. No further drilling is presently anticipated on West Delta Block 34.
As a result of plugging and abandoning West Delta Block 34 Well No. 10, the
estimated net proved undeveloped reserves of approximately 1.7 bcf of natural
gas and approximately 3,000 bbls of oil, having discounted (at 10%) estimated
future net cash flows of approximately $9.2 million included in
31
<PAGE> 34
the Trust's total proved reserves at December 31, 1993, have been eliminated
from the Trust's total proved reserves at December 31, 1994.
Exploratory drilling on West Cameron Block 65, which began in March 1994,
was successfully completed resulting in a commercial discovery. The Well No. 7,
went on production in November 1994. Estimated net proved reserves of 160,000
mcf of natural gas and 2,500 bbls of oil, having discounted (at 10%) estimated
future net cash flows of approximately $0.5 million were assigned to this well.
In June 1994, an exploratory well at West Cameron Block 498, Well No. 2,
was drilled and temporarily abandoned after discovering approximately 760 feet
of net hydrocarbon pay. In July 1994, a second exploratory well, No. 3, was
drilled and temporarily abandoned after penetrating a separate fault block and
encountering approximately 150 feet of net hydrocarbon pay from multiple sand
reservoirs, some of which were encountered by the No. 2 Well. All the Working
Interest Owners of West Cameron Block 498 are participating in a 3D seismic
survey of the block which is expected to be completed during the second quarter
of 1995. The results of this survey will be used to optimize the location and
extent of future drilling. The results of this additional drilling will help
determine the location, size and capacity of the platform and facilities
required to produce and market these reserves. At December 31, 1994, costs
associated with the exploration activities at West Cameron Block 498 resulted in
a cumulative cost carry-forward of $476,435. In February 1995, Royalty proceeds
were more than sufficient to eliminate the then cumulative cost carry-forward of
$281,912 with the excess being applied towards the funding of the reserve for
future Trust administrative expenses bringing the balance of the reserve to $2.1
million at February 28, 1995.
Due to the lack of Royalty income in late 1993 and 1994, the Trust was
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 in
January 1994 a $2.4 million Trust administrative expense reserve to pay such
expenses (see Note 7 -- Establishment of an Expense Reserve), of which $2
million had been funded through December 1994.
In January 1994, the Trust received from the Working Interest Owner $2.9
million representing the Trust's share of the final scheduled payment pursuant
to the gas contract settlement. After a reduction for an allocable portion of
estimated future abandonment costs, $0.5 million of the remaining $2.4 million
was used to eliminate the cumulative cost carry-forward at December 31, 1993,
and $1.9 million was used to partially fund the reserve for Trust administrative
expenses. Accordingly, no distribution was made to Unit holders for the month of
January 1994. Unit holders should be aware of the tax consequences regarding
these matters. Additional discussion can be found in Note 6 -- Gas Contract
Settlement, Note 7 -- Establishment of an Expense Reserve and Note 8 -- Federal
Income Tax Matters.
The operators of the Trust properties have provided escalated estimates of
future costs to abandon the Trust properties upon their depletion. See Note
9 -- Reserve for Future Estimated Abandonment Costs and Note 10 -- Supplementary
Proved Oil and Gas Reserve Information. In December 1994, such estimates, net of
abandonment cost incurred, totaled $13.6 million net to the Trust, of which
$12.8 million net to the Trust has been withheld from distributions to Unit
holders as of December 31, 1994. Based on the revised estimated future
abandonment costs, future distributions to Unit holders will be reduced by
approximately $0.05 per Unit over the remaining productive lives of the
properties, subject to future revisions of such costs. In the first quarter of
1995, $0.01066 per Unit was deducted for estimated abandonment costs.
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,
----------------------------------------
1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>
Royalty proceeds................................... $2,551,586 $6,797,931 $16,760,989
Trust administrative expenses...................... (626,201) (487,018) (785,388)
Interest income.................................... 52,198 23,777 93,104
Reserve for future Trust expenses.................. (1,977,583) -- --
---------- ---------- ----------
Distributable cash................................. $ -- $6,334,690 $16,068,705
========== ========== ==========
Distributable cash per Unit........................ $ 0.00000 $ .42295 $ 1.07296
========== ========== ==========
Units outstanding.................................. 14,975,390 14,975,390 14,975,390
========== ========== ==========
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1994 1993
------------ ------------
<S> <C> <C>
ASSETS
Cash........................................................... $ 1,977,583 $ --
Net overriding royalty interest in oil and gas properties...... 189,875,741 189,875,741
Less, adjustment to recorded cost of net overriding royalty
interest in oil and gas properties........................... (25,431,543) (25,431,543)
Less, accumulated amortization of net overriding royalty
interest..................................................... (164,231,280) (164,184,139)
------------ ------------
Total assets................................................... $ 2,190,501 $ 260,059
============ ============
LIABILITIES AND TRUST CORPUS
Distributions payable to Unit holders.......................... $ -- $ --
Reserve for future Trust expenses.............................. 1,977,583 --
Trust corpus (14,975,390 Units of Beneficial Interest
authorized, issued and outstanding).......................... 212,918 260,059
------------ ------------
Total liabilities and trust corpus............................. $ 2,190,501 $ 260,059
============ ============
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------
1994 1993 1992
----------- ----------- -----------
<S> <C> <C> <C>
Trust corpus, beginning of year................. $ 260,059 $ 358,762 $ 1,152,946
Royalty proceeds and interest earned, net of
trust administrative expenses and reserve for
future Trust expenses......................... -- 6,334,690 16,068,705
Distributions payable to Unit holders........... -- (6,334,690) (16,068,705)
Amortization of net overriding royalty
interest...................................... (47,141) (98,703) (794,184)
----------- ----------- -----------
Trust corpus, end of year....................... $ 212,918 $ 260,059 $ 358,762
=========== =========== ===========
</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 (Partnership) equal to 90 percent of the Net
Proceeds (as defined in the Conveyance referred to below) from FTX's working
interests in such properties and conveyed a 99.9 percent general partnership
interest in the Partnership to the Trust. See "The Royalty Properties and the
Royalty -- Computation of the Royalty". Such net overriding royalty interest is
referred to herein as the "Royalty". The Overriding Royalty Conveyance which
created the Royalty is referred to herein as the "Conveyance". The Trust is
passive, with Texas Commerce Bank National Association as Trustee. The Trustee
has only such powers as are necessary for the collection and distribution of
revenues attributable to the Royalty, the payment of Trust liabilities and the
protection of Trust assets.
2. THE ROYALTY
Freeport-McMoRan Oil & Gas Company (FMOG), Division of FTX (the Working
Interest Owner), presently owns the oil and gas interests burdened by the
Royalty. The Conveyance provides that the owner of the interests burdened by the
Royalty will calculate and pay monthly to the Partnership an amount equal to 90
percent of the net proceeds for the preceding month. Net proceeds generally
consist of the excess of gross revenues received from the Royalty Properties
(Gross Proceeds), on a cash basis, over operating costs, capital expenditures
and other charges, on an accrual basis (Net Proceeds).
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Trust financial statements, which reflect the Trust's 99.9 percent
interest in the Partnership as though the Partnership did not exist, are
prepared on the cash basis of accounting for reporting revenues and expenses.
Therefore, revenues and expenses are recognized only as cash is received or paid
and the associated receivables, payables and accrued expenses are not reflected
in the accompanying financial statements. Under generally accepted accounting
principles, revenues and expenses would be recognized on an accrual basis.
The initial carrying amount of the Royalty represents FTX's net book value
applicable to the interest in the properties conveyed to the Trust on the date
of creation of the Trust. Amortization of the Royalty is charged directly
against trust corpus using the future net revenue method. This method provides
for calculating amortization by dividing the unamortized portion of the Royalty
by estimated future net revenues from proved reserves and applying the resulting
rate to the Trust's share of royalty proceeds.
The carrying value of the Royalty is limited to the discounted present
value (at 10 percent) of estimated future net cash flows (as set forth in Note
10). Any excess carrying value is reduced and the adjustment is charged directly
against trust corpus. Neither the initial carrying value nor the remaining
unamortized balance at December 31, 1994 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.
34
<PAGE> 37
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
4. DISTRIBUTIONS TO UNIT HOLDERS
As a result of the capital costs associated with drilling on West Delta
Block 34, West Cameron Block 65 and West Cameron Block 498 as well as the
funding of a reserve for Trust administrative expenses (Note 7), there were no
distributions during 1994. At December 31, 1994 there was a cumulative excess
Class A cost carry-forward of $476,435 net to the Trust, related to the drilling
on West Cameron Block 498.
5. GAS BALANCING ARRANGEMENTS
As a result of past curtailments in gas takes by the principal purchaser of
production from the Royalty Properties, certain quantities of gas have been sold
by other parties with interests in the Royalty Properties pursuant to gas
balancing arrangements. Proceeds from gas produced from the Royalty Properties
but sold by other parties pursuant to such balancing arrangements
(underproduction) are not included in Adjusted Gross Proceeds for purposes of
calculating the Royalty. In the future, the Working Interest Owner will be
entitled to sell volumes equal to such underproduction or receive cash
settlements. On certain of the Royalty Properties, a cash settlement may be
required, depending on future results, due to the lack of sufficient remaining
reserves from which to makeup any underproduction. As of December 31, 1994, the
unrecovered quantity of gas sold by third parties pursuant to such gas balancing
arrangements during the period from October 1, 1983 through September 30, 1994
was approximately 2 billion cubic feet (bcf), net to the Trust. Under the terms
of the Conveyance, Adjusted Gross Proceeds will be increased in future periods
when the Working Interest Owner is compensated either through the sale of gas or
through cash settlements, the amount and timing of which is uncertain.
6. GAS CONTRACT SETTLEMENT
Pursuant to a gas contract settlement agreement effective October 1, 1988,
and amended by an agreement effective October 1, 1991, settlement payments of
$9.3 million (approximately $0.62 per Unit) and $2.3 million (approximately
$0.15 per Unit) were included in distributions paid to Unit holders of record on
January 31, 1992 and January 29, 1993, respectively. In January 1994, the Trust
received from the Working Interest Owner $2.9 million representing the Trust's
share of the final scheduled payment resulting from this settlement. After a
reduction for an allocable portion of estimated future abandonment costs, the
remaining $2.4 million, approximately $0.16 per Unit, was used to eliminate the
cumulative cost carry-forward at December 31, 1993 and to partially fund the
reserve for Trust administrative expenses described in Note 7 below. As a
result, no distribution was made to Unit holders in connection with this
settlement payment.
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 the calculation of 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 to the MMS. After this payment, approximately $4
million of the funds retained remain in the suspense account. The Working
Interest Owner has informed the Trustee that it anticipates expenditures within
the near future for development operations on the Royalty Properties in excess
of $4 million and, accordingly, will 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 is evaluating the legal,
accounting, tax and other issues relating to the
35
<PAGE> 38
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
authority of the Working Interest Owner to retain such amounts for use in
exploratory and development operations on the Royalty Properties.
7. ESTABLISHMENT OF AN EXPENSE RESERVE
Because of the lack of current Royalty income, 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, is establishing an expense
reserve of approximately $2.4 million to cover approximately 3 years of Trust
expenses. This reserve was partially funded with $1.9 million from the January
1994 settlement payment described in Note 6 above, and a portion has been funded
from Royalty income. The remaining $0.3 million will be funded from future
Royalty income received by the Trust prior to making any distribution to Unit
holders. As a result of the capital expenditures described in "Capital Resources
and Liquidity" above and the continued funding of the Trust administrative
expense reserve the amount and timing of future distributions to Unit holders is
presently indeterminable. In addition, there will be tax consequences for the
Unit holders as described in Note 8 below.
The funding for this reserve is deposited with Texas Commerce Bank and
invested in Texas Commerce Bank collateralized certificates of deposit.
The average interest rate earned on these funds for 1994 was 2.8 percent.
8. FEDERAL INCOME TAX MATTERS
The Working Interest Owner began accruing an estimate of IDC Recapture
Amount pursuant to the Conveyance effective with the May 1987 distribution. The
IDC Recapture Amount is intangible drilling cost (IDC) recapture income (IDC
Recapture Income) recognized (or considered to be incurred, pursuant to the
Conveyance) by the Company in connection with the original distribution of the
Units, but not to exceed $13.9 million plus interest and penalties attributable
thereto (IDC Recapture Amount). In September 1991, the tax issue with the
Internal Revenue Service (Service) relating to the recapture of IDC in
connection with the creation of the Trust was resolved in a manner favorable to
the Trust. As a result, the royalty amounts paid to the Trust on October 31,
1991 were based on a computation which took into account the reversal of IDC
recapture charges previously deducted, plus associated interest, and therefore
$28,398,517, or $1.89634 per Unit, was included as part of the Trust's October
distribution amount, to which Unit holders of record at October 31, 1991 were
entitled. The October distribution amount plus interest was paid to such Unit
holders on January 10, 1992, the regular quarterly payment date. For tax
purposes such distribution was deemed received by Unit holders in 1991. In
computing royalty amounts payable in future months, no IDC recapture charges
will be deducted.
In January 1994, the Trust received from the Working Interest Owner its
share of the final scheduled payment made pursuant to the gas contract
settlement as described in Note 6 above. Unit holders will be required to report
taxable income attributable to the gas contract settlement payment even though
no distributions attributable to such payment were received by the Unit holders.
The expense reserve established for Trust administrative expenses described in
Note 7 above, however, will give rise to future tax deductions as additional
administrative expenses are incurred.
9. RESERVE FOR FUTURE ESTIMATED ABANDONMENT COSTS
The operators of the Trust properties have provided estimates of future
costs to abandon the Trust properties upon their depletion. The December 1994
escalated estimate, net of abandonment costs incurred, totals $13.6 million net
to the Trust, of which $12.8 million net to the Trust had been withheld from
distributions to Unit holders as of December 31, 1994. The actual costs to
abandon the
36
<PAGE> 39
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Trust properties may vary from these estimates. Any excess will reduce future
distributions and, to the extent that actual costs are less than amounts
withheld, amounts will be added to distributable cash.
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) as of December 31, 1994, 1993 and 1992. The
reports were based on estimated production and costs after December 31, 1994,
1993 and 1992, respectively. In preparing its December 31, 1994, 1993 and 1992
estimates, Ryder Scott did not take into account (a) revenues received after
November 30, 1994, 1993 and 1992 attributable to production during the fourth
quarter of the respective year, (b) as of December 31, 1994, 1993 and 1992,
approximately 2.0 bcf, 2.7 bcf and 3.4 bcf sold by other parties pursuant to
certain gas balancing arrangements and (c) as of December 31, 1993 and December
31, 1992 approximately $2.6 million plus interest and $5.2 million plus
interest, respectively, to be received in connection with the Transco gas
contract settlement. In connection with such settlement, $2.3 million, net of
$0.8 million withheld for estimated future abandonment costs, and $9.3 million
were included in distributions paid to Unit holders of record January 29, 1993
and January 31, 1992, respectively. In addition, $2.9 million, approximately
$2.4 million after a reduction for an allocable portion of estimated future
abandonment costs, was received in January 1994. A portion of such amount was
used to eliminate the cumulative cost carry-forward at December 31, 1993 and the
remaining $1.9 million was used to partially fund the $2.4 million reserve being
established for Trust administrative expenses, resulting in no distribution to
Unit holders for the month of January 1994. For purposes of the reserve volume
and cash flow amounts set forth below, the Trustee adjusted the December 31,
1994, 1993 and 1992, estimates of Ryder Scott to take into account the foregoing
factors, based on calculations supplied by the Working Interest Owner.
As discussed in Note 9, based on escalated estimates of costs to abandon
the Trust properties, approximately $0.8 million remains to be deducted from
future distributions to cover abandonment costs. For purposes of the reserve
volume and cash flow amount set forth below, Ryder Scott has not considered
these future deductions based on escalated estimates, nor has the Trustee
adjusted Ryder Scott's estimates, as the Trust is required to present the
supplementary information assuming no escalation in costs.
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 for the years ended December 31, 1994, 1993 and 1992,
respectively. 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>
1994 1993 1992
------------- ------------- ---------------
OIL GAS OIL GAS OIL GAS
--- ------ --- ------ ---- -------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of period... 116 8,258 75 7,968 50 12,850
Revisions of previous estimates(1)... (3) (4,464) 98 789 107 1,548
Extensions and Discoveries(2)........ 3 160 3 1,669 -- --
Production........................... (37) (711) (60) (2,168) (82) (6,430)
--- ------ --- ------ ---- -------
Proved reserves, at end of period...... 79 3,243 116 8,258 75 7,968
=== ====== === ====== ==== =======
</TABLE>
Although the exploratory drilling at West Cameron Block 498 resulted in the
discovery of significant hydrocarbons, the block is considered unevaluated as of
December 31, 1994 and therefore, no proved reserves have been assigned. Further
drilling based on the results of the 3D seismic survey will help to determine
the extent of these reserves.
------------
(1) Revisions of previous estimates confirm that 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.
(2) Extensions and discoveries include reserves related to West Delta Block 34
No. 10 in 1993, which was plugged and abandoned in April 1994 after
unsuccessful attempts to complete the well and reserves related to West
Cameron Block 65 No. 7 in 1994.
Standardized Measure of Discounted Future Net Cash Flows from Proved Oil
and Gas Reserves. The supplementary information presented below reflects
estimates of discounted future net cash flows from proved oil and gas reserves
and changes in such estimates prepared in accordance with requirements
prescribed by the FASB.
Future cash flows are determined by multiplying the estimated future net
cash flows attributable to the combined interests of the Partnership and the
Working Interest Owner by a factor of 90 percent (the Partnership's Royalty).
The resulting amount is then multiplied by a factor of 99.9 percent reflecting
the Trust's interest in the Partnership. Future net cash flows also include the
proceeds to be received from underdelivered gas (see Note 5 above) and the
proceeds received from the 1994 Transco gas contract settlement payment (see
Note 6 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.
38
<PAGE> 41
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED OIL AND GAS
RESERVES:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------------
1994 1993 1992
------------ ------------ ------------
<S> <C> <C> <C>
Future cash flows.............................. $ 8,693,000 $29,876,000(1) $23,607,000(1)
Discount for estimated timing of cash flows
(10 percent discount rate).................... (1,624,000) (3,733,000) (2,047,000)
------------ ------------ ------------
Standardized measure of discounted future net
cash flows from proved oil and gas
reserves..................................... $ 7,069,000 $26,143,000 $21,560,000
============ ============ ============
</TABLE>
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM
PROVED OIL AND GAS RESERVES:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------
1994 1993 1992
------------ ------------ ------------
<S> <C> <C> <C>
Discounted future net cash flows,
beginning of year............................ $26,143,000 $21,560,000 $33,051,000
Royalty proceeds............................. (2,552,000) (6,798,000) (16,761,000)
Revisions of previous estimates:
Changes in prices and other(2)............ (19,594,000) 46,000 1,964,900
Extensions and Discoveries(2)............. 458,000 9,179,000 --
Accretion of discount(3).................. 2,614,000 2,156,000 3,305,100
------------ ------------ ------------
Discounted future net cash flows, end of
year......................................... $ 7,069,000 $26,143,000 $21,560,000
============ ============ ============
</TABLE>
------------
(1) Includes approximately $2.6 million plus interest and $5.2 million plus
interest at December 31, 1993 and December 31, 1992, respectively, related
to a gas contract settlement (See Note 6 above).
(2) Extensions and Discoveries include discounted future net cash flow related
to West Delta Block 34 No. 10 in 1993, which was plugged and abandoned in
April 1994 after unsuccessful attempts to complete the well and in 1994 is
reflected in Changes in Prices and other. Extensions and Discoveries for
1994 include discounted future net cash flow related to West Cameron Block
65 No. 7 in 1994.
(3) "Accretion of discount" reflects the change in discounted present value due
to the passage of time.
39
<PAGE> 42
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Texas Commerce Bank National Association (Trustee)
and the Unit Holders of Freeport-McMoRan
Oil and Gas Royalty Trust:
We have audited the statements of assets, liabilities and trust corpus of
Freeport-McMoRan Oil and Gas Royalty Trust as of December 31, 1994 and 1993, 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,
1994. 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, 1994 and 1993, and
the royalty proceeds and distributable cash, and changes in trust corpus for
each of the three years in the period ended December 31, 1994, on the cash basis
of accounting described in Note 3.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana,
March 3, 1995
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 holders of the Units.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
No person is known by the Trustee to own beneficially more than 5
percent of the Units.
(B) SECURITY OWNERSHIP OF MANAGEMENT
Texas Commerce Bank National Association, as Trustee of the Trust, owns
no Units. Texas Commerce Bank National Association in its individual
capacity also owns no Units.
(C) CHANGE IN CONTROL
The Trust knows of no arrangements, including the pledge of Units of the
Trust, the operation of which may at a subsequent date result in a
change in control of the Trust.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Texas Commerce Bank National Association, which also acts as Trustee of the
Trust, and its parent, Chemical Banking 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.
-----------
<C> <C> <S>
4.1* -- Overriding Royalty Conveyance from McMoRan-Freeport Oil
Company to McMoRan Oil & Gas Co. (attached as Annex I to
Exhibit 4.4).
4.2* -- Royalty Trust Indenture for Freeport-McMoRan Oil and Gas
Royalty Trust between Freeport-McMoRan Inc. ("FMI") 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 FMI.
4.5* -- Act of Assignment and Assumption and Mortgage from FMI
to Freeport-McMoRan Oil and Gas Royalty Partnership (for
omitted attachments see Exhibit 4.4).
27 -- Financial Data Schedule.
</TABLE>
------------
* Incorporated by reference to Exhibits of like designation to the registrant's
Annual Report on Form 10-K for the period ended December 31, 1983.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by the registrant during the fourth
quarter of 1994.
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: TEXAS COMMERCE BANK
NATIONAL ASSOCIATION, Trustee
By: _________________________________
Michael J. Ulrich
Vice President and Trust Officer
March 27, 1995
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
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<CASH> 1,977,583
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,977,583
<PP&E> 189,875,741
<DEPRECIATION> 189,662,823
<TOTAL-ASSETS> 2,190,501
<CURRENT-LIABILITIES> 1,977,583
<BONDS> 0
<COMMON> 0
0
0
<OTHER-SE> 212,918
<TOTAL-LIABILITY-AND-EQUITY> 2,190,501
<SALES> 2,551,586
<TOTAL-REVENUES> 2,603,784
<CGS> 0
<TOTAL-COSTS> 626,201
<OTHER-EXPENSES> 1,977,583
<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>
