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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, 1995
/ / 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)
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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 (Zip Code)
HOUSTON, TEXAS
(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
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Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES X NO
-----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. 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 February 29, 1996 was approximately $65,500,000 based on the
closing price of the Units on the New York Stock Exchange as reported in The
Wall Street Journal.
As of February 29, 1996, 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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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......................................... 26
Item 2. Properties.................................................................. 28
Item 3. Legal Proceedings........................................................... 28
Item 4. Submission of Matters to a Vote of Unit Holders............................. 28
PART II
Item 5. Market for the Registrant's Units and Related Unit Holder Matters........... 28
Item 6. Selected Financial Data..................................................... 28
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, 1995, 1994 and 1993.................... 33
Statements of Assets, Liabilities and Trust Corpus:
As of December 31, 1995 and 1994........................................ 33
Statements of Changes in Trust Corpus:
For the years ended December 31, 1995, 1994 and 1993.................... 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, 1995 and the estimated future net income of the Trust, see the
report by Ryder Scott Company Petroleum Engineers contained on pages 10 through
15 hereof, (ii) financial condition and results of operations of the Trust, see
Item 7 appearing on pages 30 through 32 hereof and (iii) financial statements
and supplementary data of the Trust, see Item 8 appearing on pages 33 through
40, 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
(FMOG), a division of FTX, 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
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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 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 $0.5 million for 1996. The Trustee, in
accordance with the Trust Indenture, established an expense reserve of
approximately $2.4 million to cover Trust expenses as discussed in Note
7 -- Establishment of an Expense Reserve. 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 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
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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. 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 cash receipts for
each of three successive years are less than $3 million, thereby terminating the
Trust pursuant to (i) above. Upon the termination of the Trust under (ii) above,
the Trustee will sell the Royalty (or will cause the Partnership to sell all of
the assets of the Partnership). The Trustee will as promptly as possible
distribute the proceeds of any such sales according to the respective interests
and
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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.
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 the Working Interest Owner is permitted to farmout interests in
the Royalty Properties and to reduce the Royalty proportionately. See "THE
ROYALTY PROPERTIES AND THE ROYALTY -- General and -- Production and Drilling
Activities". The Working Interest Owner does not have an obligation to produce
any specific amounts of oil and gas from any of the Royalty Properties. It has
the right to abandon any well or lease, and upon termination of any lease the
portion of the Royalty relating thereto will be extinguished. The amount of
revenues attributable to the Royalty may be affected by operating agreements and
unitization and pooling arrangements. The realization of the ultimate value of
the Royalty is subject to all the risks associated with exploration on and
development of oil and gas properties and to comprehensive regulation by
governmental authorities.
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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.
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
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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 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
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Properties consist of multiple leases in multiple fields, the interest of the
Working Interest Owner in any given well or lease may not be indicative of the
interest attributable to the Trust in the Royalty Properties.
GENERAL
The map on page 9 shows the location and selected information as of
December 31, 1995 for all of the productive Royalty Properties where production
or drilling operations are currently under way. In 1985, OCS-P 0433 Tract 214 in
the Santa Maria Basin, offshore California was farmed out, with the Working
Interest Owner retaining an overriding royalty interest burdened by the Royalty.
Additionally, during 1995, the Eugene Island Block 10 field (25% working
interest) and the Vermilion Block 310 field (30% working interest) were shut-in
due to the fields reaching their economic limits. The respective leases have
expired and abandonment operations are anticipated during 1996.
In February 1996 drilling operations commenced on an exploratory well on
Breton Sound Block 55. The Working Interest Owner owns a 9.375% working interest
in the lease well. The estimated drilling cost for the well is $.8 million net
to the Trust. Additional costs may be required to complete the well and develop
it for production. Additional exploration may be proposed for certain other
Royalty Properties where geologic features have been identified through the
utilization of 3D seismic technology. After analyzing each proposal, the Working
Interest Owner will determine whether or not to participate in additional
exploratory operations.
As of December 31, 1995, there were 2 gross (0.7 net) productive oil wells
and 13 gross (2.08 net) productive gas wells on 8 of the remaining Royalty
Properties where the Working Interest Owner retains a working interest.
All remaining Royalty Properties are operated by other oil and gas
companies under joint operating agreements. Neither the Working Interest Owner
nor any operator has any contractual commitments to the Partnership or the Trust
to conduct further exploratory or development drilling on the Royalty Properties
or to maintain its ownership interest in any of the properties. See "Certain
Factors Affecting Distributions; Conflicts of Interest". However, any operator
of a Royalty Property (including the Working Interest Owner) has an obligation
to operate and develop such property in accordance with the standards of a
reasonable and prudent operator. The Working Interest Owner retains a revenue
interest in the remaining Royalty Properties and it has informed the Trustee
that it may conduct further development and exploratory activities on certain of
the Royalty Properties. See "Production and Drilling Activities" below for a
discussion of current development and exploratory activities on certain of the
Royalty Properties.
RESERVES
A study of the proved oil and gas reserves attributable to the Royalty
Properties as of December 31, 1995, 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, 1995, but the timing of inclusion of
production and costs
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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 1996
attributable to sales of oil and gas produced in the fourth quarter of 1995,
volumes of natural gas sold by other parties pursuant to certain gas balancing
arrangements and the effect of the excess Class A cost carry-forward at December
31, 1995. 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,
1995. Of the total discounted present value of future net cash flows
attributable to the Royalty estimated by Ryder Scott, approximately 4 percent
are under contract with Transcontinental Gas Pipeline Co. (Transco), a purchaser
of natural gas, and approximately 96 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 identifying the location
of the Trust's productive properties by block number, including gross and net
acreage and working interest percentage for each block, as of December 31,
1995.]
<TABLE>
<CAPTION>
Worklog
Property Interest%* Gross Acres Net 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
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
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
</TABLE>
* The Royalty Trust owns 99.9% of a 90% net profits interest in the Working
Interest for each block.
<PAGE> 12
[RYDER SCOTT COMPANY LETTERHEAD]
February 21, 1996
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, 1995. 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.
Eleven 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
eleven 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 eleven included in our evaluation have a material
effect on the overall revenues or liabilities of the Partnership.
The estimated reserve quantities and future income quantities presented
in this report are related to hydrocarbon prices. December 1995 hydrocarbon
prices were used in the preparation of this report as required by SEC
guidelines; however, actual future prices may vary significantly from December
1995 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
February 21, 1996
Page 2
SEC PARAMETERS
Estimated Net Reserve and Income Data
Freeport-McMoRan Oil and Gas Royalty Partnership
As of December 31, 1995
------------------------------------------------
<TABLE>
<CAPTION>
Proved Proved Total
Developed Undeveloped Proved
--------- ----------- ------
<S> <C> <C> <C>
Remaining Reserves
Oil/Condensate -- Barrels 34,597 616,946 651,543
Gas -- MMCF 690 2,953 3,643
Future Net Income (FNI)
1996 $1,214,392 -$ 6,181,754 -$ 4,967,362
1997 629,758 5,936,083 6,565,841
1998 80,142 2,308,945 2,389,087
---------- ----------- -----------
Sub-Total (1996-1998) $1,924,292 $ 2,063,274 $ 3,987,566
Remaining 319,499 15,383,703 15,703,202
---------- ----------- -----------
Total $2,243,791 $17,446,977 $19,690,768
Discounted FNI @ 10% $2,003,093 $ 9,600,864 $11,603,957
(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 and by a yearly
amount necessary for the Working Interest Owner to accrue the balance of the
abandonment costs over the remaining life of the Subject Properties. The
adjusted annual income resulting from subtracting the overhead charge and
prorated abandonment costs was multiplied by a factor of 90 percent to arrive
at the annual future net income of the Partnership.
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
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
11
<PAGE> 14
Freeport-McMoRan Oil and Gas Royalty Trust
February 21, 1996
Page 3
additional factors that influence the prices at which oil and gas properties
are bought and sold and 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 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
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
12
<PAGE> 15
Freeport-McMoRan Oil and Gas Royalty Trust
February 21, 1996
Page 4
dissolved gas. An appropriate reduction in gas reserves has been made for the
expected removal of natural gas liquids, for lease and plant fuel, and for the
exclusion of non-hydrocarbon gases if they occur in significant quantities and
are removed prior to sale.
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.
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.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
13
<PAGE> 16
Freeport-McMoRan Oil and Gas Royalty Trust
February 21, 1996
Page 5
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, 1995 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, 1995 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 1995, 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, 1995 were not considered in this study.
GAS
The Working Interest Owner has furnished us with gas prices in effect
at December 1995 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 $2.015 per MMBTU was used in this
study for all uncontracted gas and for gas produced subsequent to the
expiration of gas contracts.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
14
<PAGE> 17
Freeport McMoRan Oil and Gas Royalty Trust
February 21, 1996
Page 6
COSTS
The current operating, development, abandonment, and overhead costs were
held constant throughout the life of the properties. The estimated net cost of
abandonment after salvage was used in our estimates of future revenue from the
Subject Properties since these costs are relatively large in offshore areas. The
estimates of the net abandonment costs for the Subject Properties were furnished
by the Working Interest Owner and were accepted without independent
verification.
All operating, development, abandonment, and overhead costs used in this
study were furnished by the Working Interest Owner. The operating costs are
based on the operating expense reports of the Working Interest Owner 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 1995.
The future prices received for the sale of production may be higher or
lower than the prices used in this report as described above, and the operating
costs and other costs related to such production may also increase or decrease
from existing levels; however, such possible changes in prices and costs were,
in accordance with rules adopted by the Securities and Exchange Commission,
omitted from consideration in preparing our report.
Neither Ryder Scott Company nor any of its employees has any interest in
the Subject Properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future income for
the Subject Properties.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/ Kent A. Williamson
------------------------
Kent A. Williamson, P.E.
Group Vice President
KAW/im
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
15
<PAGE> 18
Of the total discounted present value of future net cash flows attributable
to the Royalty estimated by Ryder Scott, approximately 83 percent was accounted
for by West Cameron Block 498 and 6 percent by West Cameron Block 215.
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.
16
<PAGE> 19
The Ryder Scott estimates were prepared on the basis of estimated
production and Costs accrued after December 31, 1995. Thus, amounts received by
the Working Interest Owner after November 30, 1995 attributable to production
during 1995 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
1995. The Working Interest Owner has estimated that if Ryder Scott had taken
into account the 1996 Gross Proceeds from 1995 production, the total estimated
future net cash flow and the discounted present value of such estimate in the
Ryder Scott letter would have been approximately $0.7 million higher (net to the
Trust's interest). In addition, because Ryder Scott's estimates for the
remaining period are based on estimated production and Costs accrued during each
such period and because actual Gross Proceeds and Costs will not be based on
production and Costs during the same period, the estimates for various time
periods will not in any event correspond to the amount of payments pursuant to
the Royalty during such periods.
Ryder Scott gave no effect in its estimates to amounts to which the Working
Interest Owner is entitled as a result of gas imbalances for certain production
(see Note 5 -- Gas Balancing Arrangements and Note 10 -- Supplementary Proved
Oil and Gas Reserve Information). Pursuant to the Conveyance, proceeds from gas
produced from the Royalty Properties but sold by other parties pursuant to gas
balancing arrangements between the Working Interest Owner and others
(underproduction) are not included in Gross Proceeds for purposes of calculating
the Royalty. In the future the Working Interest Owner will be entitled to sell
volumes equal to such underproduction or receive cash settlements. The amounts
the Working Interest Owner will receive from the future sale of such
underproduction may be more or less than those amounts received by third parties
because of price fluctuations.
The estimated future net cash flows shown in Ryder Scott's letter have not
been reduced for any capital expenditures on Productive Properties in excess of
amounts estimated to be necessary to develop proved reserves attributed thereto.
See "Computation of the Royalty" below. Similarly, such future net cash flows
have not been reduced for costs and expenses of the Trust, which are currently
estimated at $0.5 million per year, or of the Partnership, which are expected to
be minimal. Ryder Scott also did not take into account the Class A cost
carryforward of $1.9 million net to the Trust, as of December 31, 1995.
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
17
<PAGE> 20
received (on a cash basis) during a particular month over Costs incurred (on an
accrual basis) during such month. Generally, such Costs include any excess of
Costs over Gross Proceeds carried forward from the previous month, together with
interest on such excess. Amounts equal to 90 percent of the Net Proceeds for any
month are payable by the Working Interest Owner to the Partnership on the last
business day of the following month.
"Gross Proceeds" means the amount received from sales of hydrocarbons
produced from the Royalty Properties that are attributable to the working
interests subject to the Royalty, net of lessor royalties and production
payments existing at the time of the creation of the Trust which burdened the
Royalty Properties prior to the effective date of the Conveyance, and subject to
farmouts and certain other adjustments.
"Costs" means, generally, (i) all costs incurred by the Working Interest
Owner in producing and operating the Royalty Properties (lease operating
expenses), (ii) all capital costs incurred, or projected to be incurred, by the
Working Interest Owner in drilling and completing exploratory and development
wells and in connection with the installation of platforms, pipelines and other
production facilities, (iii) an overhead charge and (iv) amounts recovered by
the Working Interest Owner as estimated Abandonment Costs ("Abandonment Costs"
means, generally, the future costs to be incurred by the Working Interest Owner
to plug and abandon wells and dismantle and remove platforms, pipelines and
other production facilities from the Royalty Properties).
The Working Interest Owner is entitled to accrue certain estimated future
costs in accordance with a formula set forth in the Conveyance. The accrual
formula provides that, for any month and with respect to a specific item of
future costs, the Working Interest Owner may include in its costs an amount
calculated by multiplying (a) the excess of (i) the total estimated amount of
such item of future cost over (ii) the aggregate amount accrued in previous
months with respect to such item, by (b) a fraction, the numerator of which is
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
18
<PAGE> 21
been held in escrow or, conversely, may have their distributions reduced or
eliminated as a result of controversies about amounts which may have been
collected. Within 30 days following the close of each calendar quarter, the
Working Interest Owner is required to deliver to the Partnership a statement of
the computation of Net Proceeds attributable to the quarter.
If a default occurs under the Conveyance, the holder of the Royalty may
pursue any legal or equitable remedies available to it, including seeking
specific performance of any covenant that has been breached. Defaults under the
Conveyance include (1) failure on the part of the Company to observe or perform
any covenant contained in the Conveyance, which failure materially adversely
affects the interests of the holder of the Royalty, and (2) certain events of
bankruptcy or insolvency relating to the Working Interest Owner.
CERTAIN FACTORS AFFECTING DISTRIBUTIONS; CONFLICTS OF INTEREST
The amount of cash payable on account of the Royalty, and thus the amount
of cash available for distribution to Unit holders, depends upon numerous
factors and may vary substantially from month to month. In addition, conflicts
of interest may arise between the Working Interest Owner and the Trust. These
factors and potential conflicts include the following:
Timing of Collections by the Working Interest Owner. An alteration in
the timing of the receipt of payment for proceeds of production from the
Royalty Properties from the collection pattern normally anticipated can
occur for a number of reasons beyond the Working Interest Owner's control.
Such altered timing can result in: (1) wide swings in Monthly Distribution
Amounts, and (2) 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, subsequent capital
expenditures required to explore for, develop and produce the reserves
could be of such magnitude that they would result in the elimination or
reduction of distributions to Unit holders for a substantial period of
time. See "Production and Drilling Activities" below.
Oil and Gas Surplus and Other Marketing Factors. The prices of crude
oil have fluctuated significantly in recent years 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. Gas market
conditions are affected by gas price competition, competition from
alternative fuels, energy conservation and a variety of other factors.
Variation of Partnership's Interest. Although the Royalty conveyed to
the Partnership is set forth in the Conveyance, the actual amount of
revenues from the Royalty Properties may be increased or reduced as a
result of future farmouts, unit agreements and unit operating agreements.
Certain portions of the Royalty have been and other portions of the Royalty
may be extinguished as leases expire as a result of the failure to
establish or maintain commercial production or to pay annual rentals. In
addition, the Working Interest Owner's right to revenues from a well to be
drilled in the future may be extinguished or suspended as a result of "non-
consent" provisions of present or future operating agreements with other
working interest owners. See "Operating Agreements" below. Since the
Royalty was conveyed out of working interests, distributions to the Trust
will be reduced, extinguished or suspended as, when and to the
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extent the Working Interest Owner's right to revenues from a well is
reduced, extinguished or suspended.
Operating Hazards. Operation of the Royalty Properties is subject to
all the risks incident to offshore exploration for and production of oil
and gas, including blowouts, cratering, fires and marine perils such as
capsizing, collision and adverse weather and seas. Any of these events
could result in damage to or destruction of oil and gas wells or producing
facilities, suspension of operations and pollution damage. Although losses
and liabilities arising from such events would not require payment by the
Trust of funds previously received, they would reduce the proceeds payable
thereafter with respect to the Royalty.
Ownership of Adjacent Properties. The Working Interest Owner may own
interests in offshore tracts that are adjacent to or in the vicinity of,
but not included in, the Royalty Properties, and it may in the future
acquire additional such tracts. Drilling conducted on the Royalty
Properties may provide the Working Interest Owner or any successor with
valuable information regarding such other tracts, which it would then be
free to develop unburdened by the Royalty and which in some cases could
drain oil and gas from the Royalty Properties. In the second quarter of
1995, McMoRan Oil & Gas Co. (MOXY), a former affiliate of the Working
Interest Owner, acquired a 25% undivided interest in West Cameron Block
519, a tract which is adjacent to West Cameron Block 498, one of the
Royalty Properties in which the Working Interest Owner owns an
approximately 23% interest. The Royalty will not apply to this tract just
as it would not have applied had it been purchased by the Working Interest
Owner. No drilling has occurred on West Cameron Block 519. The Working
Interest Owner is not the operator of West Cameron 498 and MOXY is not the
operator of West Cameron 519. Neither the Working Interest Owner nor MOXY
has the voting interest necessary to determine the nature or timing of
operations on either of these tracts.
Negotiation and Amendment of Contracts. The Working Interest Owner and
the purchasers of gas from the Royalty Properties have the right to enter
into and amend contracts for the sale of production without the consent of
the Trustee. In addition, the Working Interest Owner is responsible for the
marketing of its working interest share of any commercial quantities of oil
or gas produced from the Royalty Properties. Although the Working Interest
Owner is generally expected to seek the highest prices obtainable for the
production, its negotiations regarding future contracts and possible
revisions to existing contracts may be affected by factors which are of
economic significance to it but not to the Unit holders, such as the
existence or anticipation of other contractual arrangements between the
Working Interest Owner and the purchaser. The Working Interest Owner is
entitled to make arrangements for the marketing of its share of production
from the Royalty Properties independently of other working interest owners.
Transfer of Working Interest; Abandonment. The Working Interest Owner
is free to transfer all or a portion of its working interest in any Royalty
Property (burdened by the Royalty) to any third party in sound financial
condition. The Working Interest Owner is also free to enter into farmouts
on the Royalty Properties, whereby it would transfer a portion of its
interest (unburdened by the Royalty) while retaining a lesser interest
(burdened by the Royalty) in return for the transferee's obligation to
drill a well on the Royalty Property; however, it may not enter into such
farmouts on the Productive Properties except with respect to exploratory
wells. The Working Interest Owner has the right to abandon any well or
lease if, in its opinion, such well or lease ceases to produce or is not
capable of producing in paying quantities, and upon termination of any
lease, the portion of the Royalty relating thereto will be extinguished.
Should a lease on one of the Royalty Properties expire, the Working
Interest Owner would thereafter be free to acquire a new lease on the same
block, unburdened by the Royalty.
PRODUCTION AND DRILLING ACTIVITIES
Of the 11 remaining Royalty Properties, 8 are currently producing. For a
discussion concerning the oil and gas production from such properties in 1995,
as well as information concerning drilling
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<PAGE> 23
activities on such properties during 1995, see Item 7 -- Management's Discussion
and Analysis of Financial Condition and Results of Operations beginning on page
31 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 the amount of capital and
operating expenditures and vary the receipt of revenues from the sale of
production. For example, the "non-consent" provisions of the operating
agreements allow other joint interest owners to propose the drilling of wells
and thereby require the Working Interest Owner to elect either to pay its share
of the cost of drilling such wells or suffer a "non-consent" penalty. The
particulars of non-consent penalties on the Royalty Properties vary somewhat
between operating agreements, but generally require the forfeiture to the
participating parties of a significant interest if the party elects not to
participate in the drilling of certain exploratory wells. If a party elects not
to participate in a development well on any of the Royalty Properties (other
than Vermilion Block 21/22 and West Cameron Block 65), that party's right to
receive a share of production from such development well is suspended until such
time as the participating parties have recovered an amount ranging from
approximately 400 percent to approximately 600 percent of the cost of drilling,
testing, completing and equipping the development well. With respect to
Vermilion Block 21/22 and West Cameron Block 65, the non-consenting party must
assign all its working interest in the previously designated development area,
subject to retention by that party of its interest in wells previously drilled
in such area and an overriding royalty interest in all subsequent wells drilled
in such area. The loss of revenues from any failure by the Working Interest
Owner to participate in a development well would reduce the aggregate proceeds
from the Royalty in the event such development well produced in paying
quantities in excess of the cost of drilling, testing, completing and equipping
such well. Neither the Partnership nor the Trustee is entitled to compel the
Working Interest Owner to participate in any operation on a Royalty Property if
the Working Interest Owner makes a "non-consent" election with respect thereto.
The Working Interest Owner may choose to conduct exploration and
development operations on one or more of the Royalty Properties without the
participation of some, or all, of the other joint interest owners by assuming
the obligations of non-consenting parties. If the Working Interest Owner elects
to assume a share of the costs associated with any non-consenting party's
interest, such costs and the production, if any, attributable to the assumption
of such interest will not be taken into account in the computation of the Net
Proceeds.
The receipt of revenues from the sale of gas production could be delayed
for extended periods of time by gas balancing arrangements which allow other
joint interest owners to take gas production in excess of their ownership
percentage if the Working Interest Owner is unable to take all or a part of its
share of production. On the other hand, if the Working Interest Owner takes gas
production in excess of its ownership percentage, the revenues attributable to
the excess production will not be included in Gross Proceeds except to the
extent such excess is offset by prior or subsequent deficits created after
October 1, 1983 by the Working Interest Owner taking less than its ownership
percentage share of gas production. If a source of gas supply depletes before
the Working Interest Owner has balanced all deficits created after October 1,
1983 with excess production volumes, the Working Interest Owner will be entitled
to receive a cash settlement for such deficits from those joint interest owners
with excess production totals. All such settlement receipts will be included in
Gross Proceeds. See "Reserves" above.
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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 1995 was approximately 13 percent
higher than the average price received during 1994. 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 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 8 of
the 11 remaining Royalty Properties. Gas production from West Delta Block 34,
which accounted for approximately 33 percent of the Working Interest Owner's
revenues from the Royalty Properties during 1995, is subject to a gas purchase
contract with Transco. Gas sales to Transco accounted for approximately 43
percent, 48 percent and 53 percent of the Working Interest Owner's revenues
attributable to oil and gas production from the Royalty Properties in 1995, 1994
and 1993, 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 (NGA) and the
Natural Gas Policy Act (NGPA). The Natural Gas Wellhead Decontrol Act of 1989
amended both the price and non-price control provisions of the NGPA for the
purpose of providing complete decontrol of first sales of natural gas by January
1, 1993. 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
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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 reversed
in whole or in part. With Order No. 636 subject to court review, it is difficult
to predict with precision its ultimate effects.
FERC has 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 Working Interest Owner only indirectly,
the FERC's current rules and policy statements may have the effect of enhancing
competition in natural gas markets by, among other things, encouraging
non-producer natural gas marketers to engage in certain purchase and sale
transactions. The Working Interest Owner cannot predict what action the FERC
will take on these matters, nor can it accurately predict whether the FERC's
actions will achieve the goal of increasing competition in markets in which the
Working Interest Owner's natural gas is sold. However, the Working Interest
Owner does not believe that it will be affected by any action taken materially
differently than other natural gas producers and marketers with which it
competes.
Recently, the FERC issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. While this policy
statement affects the Working Interest Owner only indirectly, in its present
form, the new policy should enhance competition in natural gas markets and
facilitate construction of gas supply laterals. However, requests for rehearing
of this policy statement are currently pending. The Working Interest Owner
cannot predict what action the FERC will take on these requests.
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, or may require, pipelines to make rate
changes to track changes in the Producer Price Index for Finished Goods, minus
one percent, became effective January 1, 1995. 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. 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
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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.
Operations the Working Interest Owner conducts relating to the Royalty
Properties are on federal oil and gas leases, which the Minerals Management
Service (MMS) administers. The MMS issues such leases through competitive
bidding. These leases contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the OCSLA (which
are subject to change by the MMS). For offshore operations, lessees must obtain
MMS approval for exploration plans and development and production plans prior to
the commencement of such operations. In addition to permits required from other
agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has promulgated regulations
requiring offshore production facilities located on the OCS to meet stringent
engineering and construction specifications. The MMS has recently proposed
additional safety-related regulations concerning the design and operating
procedures for OCS production platforms and pipelines. These proposed
regulations were withdrawn pending further discussion among interested federal
agencies. 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 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 the settlement, approximately $4 million of the funds initially retained
for possible royalty obligations remained. The Working Interest Owner informed
the Trustee that it anticipated expenditures for the development operations on
the Royalty Properties in excess of $4 million and, accordingly, proposed to
retain the funds remaining in the suspense account for use as payments of these
anticipated expenditures, as sufficient funds may not be otherwise available.
The Trustee and the Working Interest Owner evaluated the legal, tax and other
issues relating to retaining such amounts for use in the exploratory and
development operations on the Royalty Properties and concluded that the funds
should be paid to the Trust. Such funds, including interest, were included in
the April 1995 Net Proceeds as a special payment resulting in a distribution of
$0.28794 per Unit.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time-to-time by Congress, the FERC, state
regulatory bodies, and the courts. The Working Interest Owner cannot predict
when or if any such proposals might become effective, or their effect, if any,
on the Trust. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.
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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 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, including
proof of financial responsibility to cover a substantial portion of
environmental cleanup and restoration costs that could be incurred by
governmental entities in connection with an oil spill. In August 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. However, in May
1995 the U.S. House of Representatives passed a bill that would reduce the level
of financial responsibility required under OPA to $35 million. In November 1995
the U.S. Senate adopted similar but slightly different legislation that must be
reconciled with the House of Representative's bill before either bill can be
submitted to the President for approval. The final form of any financial
responsibility rule that may be adopted pursuant to OPA cannot be predicted at
this time; however, any 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
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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 requirements under the Resource Conservation and
Recovery Act. Any reclassification of oil and gas exploration and production
wastes from non-hazardous to hazardous could have a significant impact on the
operating costs of the Working Interest Owner, as well as the oil and gas
industry in general. Initiatives to further regulate the disposal of oil and gas
wastes are also pending in certain states, and these various initiatives could
have a similar impact on the Working Interest Owner.
TITLE TO PROPERTIES
The Conveyance is subject to customary interests and burdens, to the terms
and provisions of the underlying leases, to liens and other provisions of
farmout, operating, pooling and unitization agreements and to minor
encumbrances, easements and restrictions. The Royalty Properties are also
subject to the 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
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stockholders to the Partnership in exchange for interests therein, followed
in turn by the contribution by the stockholders of the interests in the
Partnership to the Trust in exchange for the Units.
4. FTX will recognize no gain or loss upon the transfer of the
Royalty to its stockholders.
5. Each Unit holder will be entitled to deduct cost depletion with
respect to its pro rata interest in the Royalty computed with reference to
the Unit holder's basis in the Units.
6. The Royalty will be considered an economic interest in oil and gas
in place, and the Royalty will constitute a single property within the
meaning of Section 614(a) of the Internal Revenue Code of 1954, as amended,
as in effect when the transaction was consummated.
AREAS OF POTENTIAL TAX CONTROVERSY
Information Return Filing Requirements. Under the Internal Revenue Code of
1986, as amended (the Code), any partner who sells or exchanges (other than
through a broker) an interest in a partnership holding "unrealized receivables"
within the meaning of Section 751 of the Code is required to notify the
partnership of such transaction in accordance with Treasury regulations. Any
such partner who fails to so notify the partnership may be subject to a $50
penalty for each such failure. Furthermore, on a sale or exchange of Units,
other than through a broker, the partnership is required to notify the Service
of any such sale or exchange (of which it has notice) of a partnership interest
after December 31, 1984, and to report the name and address of the transferee
and the transferor who were parties to such transaction, along with all other
information required by applicable Treasury Regulations. The partnership must
also provide this information to the transferor and the transferee. If the
partnership fails to furnish any such notification, it may be subjected to a
penalty of $50 per failure, up to an annual maximum of $100,000. Final Treasury
regulations exempt partnerships from the requirement to report any sales which
are reported by a broker on Form 1099-B.
The Code provides that depletion deductions subject to recapture under
Section 1254 of the Code constitute "unrealized receivables" within the meaning
of Section 751 of the Code. Section 1254 of the Code provides that for property
placed in service by a taxpayer after December 31, 1986, depletion deductions
which reduce the adjusted basis of such property must be recaptured as ordinary
income upon a disposition of the property (to the extent gain is recognized on
such disposition). It is unclear whether this recapture provision applies to any
portion of the depletion claimed with respect to the Royalty (placed in service
in 1983 by the Partnership) in the case of Units acquired after December 31,
1986. The Service has not issued any regulations or other pronouncements to
indicate its interpretation of these recapture provisions as they might affect
the transfer of partnership interests. Accordingly, Unit holders disposing of
Units acquired after December 31, 1986 (other than through a broker) may be
required to notify the Trustee in writing of such disposition and provide the
Trustee with the Unit holder's name, address, taxpayer identification number and
the date of the disposition. Failure to so notify the Trustee may subject such a
Unit holder, as well as the Trust and the Partnership, to the above-described
penalties. Without 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
27
<PAGE> 30
the federal tax reporting requirements applicable to trusts (such as the Trust)
which own interests in partnerships (such as the Partnership) and because all of
the tax attributes of the Royalty flow through the Partnership and the Trust to
the Unit holders, there is an increased likelihood that Unit holders will
violate the consistency requirement and other reporting requirements regarding
their individual federal income tax returns and the information returns of the
Trust and the Partnership. Any violations of the consistency requirements could
lead to imposition of certain penalties on the Unit holders or other adverse
results. Furthermore, the Trust or the Partnership might be subject to certain
penalties in connection with their furnishing of statements and information to
Unit holders or the government if such statements or information prove to be
inaccurate due, for example, to differences between the transfer agent's records
and actual ownership data. The Code provides reporting requirements designed to
facilitate the transfer of information between partnerships and trusts and
owners of interests therein held by nominees.
ITEM 2. PROPERTIES.
Reference is made to Item 1 of this report.
ITEM 3. LEGAL PROCEEDINGS.
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNIT HOLDERS.
No matters were submitted to a vote of Unit holders during the fourth
quarter of 1995.
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 February 29, 1996, 14,975,390 Units
were outstanding and held of record by 12,846 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 1994
and 1995 were:
<TABLE>
<CAPTION>
UNITS OF
BENEFICIAL
INTEREST DISTRIBUTABLE
QUARTER ---------------- CASH PER
ENDED HIGH LOW UNIT
----- ----- --------
<S> <C> <C> <C>
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 --
Mar. 31, 1995.......................................... 5.00 3.75 --
Jun. 30, 1995.......................................... 4.88 3.63 0.30365
Sept. 30, 1995......................................... 6.25 4.50 0.00765
Dec. 31, 1995.......................................... 5.50 3.63 --
</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
28
<PAGE> 31
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,
--------------------------------------------------------------------
1995 1994 1993 1992 1991
---------- ---------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Royalty proceeds(1)....... $5,235,068 $2,551,586 $6,797,931 $16,760,989 $32,611,061
Distributable cash(1)..... 4,662,081 -- 6,334,690 16,068,705 38,451,775(2)
Distributable cash per
Unit.................... 0.31130 -- 0.42295 1.07296 2.56760
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------------------------------------
1995 1994 1993 1992 1991
---------- ---------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Cash...................... $2,300,979 $1,977,583 $ -- $ 1,475,861 $30,779,763
Total assets.............. 2,484,192 2,190,501 260,059 1,834,623 31,932,709
Distributions payable..... -- -- -- 1,475,861 30,779,763
Trust corpus.............. 183,213 212,918 260,059 358,762 1,152,946
</TABLE>
- ------------
(1) Includes $4.3 million in 1995 related to the special payment (See Note
6 -- Gas Contract Settlement) and $2.4 million, $2.3 million, $9.3 million
and $0.8 million in 1994 through 1991, 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.
The Trust has not reported estimates of total proved net oil or gas
reserves to any federal authority or agency other than the SEC.
29
<PAGE> 32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
RESULTS OF OPERATIONS
Distributable cash for 1995 totaled $4.7 million ($0.31130 per Unit)
primarily reflecting a special payment of $4.3 million in April 1995 discussed
below. Absent this special payment, declining gas revenues and additional
capital expenditures during the remainder of 1995 resulted in no significant
cash distribution, as had been the case during 1994. Additionally, at year-end
1995 an excess Class A cost carry-forward of $1.9 million net to the Trust
existed, and Trust administrative expenses were again being recovered from the
expense reserve. The calculation of distributable cash for each year follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------
1995 1994 1993
---------- ----------- ----------
<S> <C> <C> <C>
Gross Proceeds(1)............................ $9,807,120 $12,308,657 $16,808,125
Total costs(2)............................... (6,070,921) (10,000,626) (9,496,264)
Excess Class A cost carry-forward(3)......... 2,086,366 529,902 248,957
---------- ----------- ----------
Net Proceeds................................. 5,822,565 2,837,933 7,560,818
Percentage attributable to Royalty........... 90.0% 90.0% 90.0%
---------- ----------- ----------
Amounts payable attributable to Royalty...... 5,240,309 2,554,140 6,804,736
Percentage attributable to the Trust......... 99.9% 99.9% 99.9%
---------- ----------- ----------
Royalty Proceeds............................. 5,235,068 2,551,586 6,797,931
Trust administrative expenses................ (369,101) (472,944) (640,275)
Trust administrative expense
carry-forward (recovery)(4)................ -- (153,257) 153,257
---------- ----------- ----------
4,865,967 1,925,385 6,310,913
Interest earned.............................. 119,510 52,198 23,777
Reserve for future Trust expenses(5)......... (323,396) (1,977,583) --
---------- ----------- ----------
Distributable Cash........................... $4,662,081 $ -- $6,334,690
========== =========== ==========
</TABLE>
- ---------------
(1) Gross proceeds for each year were calculated based on amounts received by
the Working Interest Owner during the twelve month period ended November 30
of such year.
(2) Total costs for each year represent amounts accrued by the Working Interest
Owner during the twelve month period ended November 30 of such year.
(3) Represents net Class A costs incurred in the applicable period that remained
outstanding as of the end of such period including accrued interest of
$26,592, $10,979 and $5,770 for 1995, 1994 and 1993, respectively.
(4) Carry-forward represents Trust administrative expenses incurred in the
applicable period that remained outstanding as of the end of such period;
recovery represents Trust administrative expenses incurred in a prior period
and recovered in the current period.
(5) Represents the net amount deposited to the Trust administrative expense
reserve for the respective period.
Gas revenues included in Gross Proceeds totaled $3.5 million in 1995, $7
million in 1994 and $11.2 million in 1993 on volumes totaling 1.8 billion cubic
feet (bcf), 2.8 bcf and 4.4 bcf, respectively. The decline in production over
the three-year period is due primarily to the depletion of the Eugene Island
Block 10 and Vermilion Block 310 fields in 1995, the West Cameron Block 498
field and wells at West Delta Block 34 and East Cameron Block 336 in 1994 and
normal production declines. Gas volumes included make up of gas sold under
balancing agreements totaling 0.3 bcf, 0.7 bcf and 0.7 bcf for 1995, 1994 and
1993, respectively. Gas realizations averaged $1.94 per thousand cubic feet
(mcf) in 1995, $2.46 per mcf in 1994 and $2.54 per mcf in 1993, declining as a
result of increasing volumes of gas being sold on the spot market as
higher-price contracts expire.
30
<PAGE> 33
Oil revenues included in Gross Proceeds totaled $1.5 million, $2.2 million
and $2.2 million in 1995, 1994 and 1993, respectively, on volumes of 88,700
barrels, 145,800 barrels and 120,900 barrels, respectively. The decrease in 1995
when compared with 1994 resulted from the anticipated decline in oil production
at West Cameron Block 215 while the increase in 1994 compared with 1993 resulted
from increased oil production at West Cameron Block 215. Oil realizations for
the three years averaged $16.96, $14.97 and $17.92 per barrel, respectively.
Gross proceeds also include $4.3 million in 1995 related to settlement of
royalty obligations to the Minerals Management Service and receipts of $3.2
million in 1994 and $3.5 million in 1993 related to a gas contract settlement.
(See Note 6 -- Gas Contract Settlement).
The principal components of total costs are lease operating expenses,
exploration and development costs and accruals for future estimated abandonment
costs. Lease operating expenses from 1995-1993 were approximately $2.4 million
per year. Exploration and development costs were $2.5 million in 1995, $5.5
million in 1994 and $2.7 million in 1993. Two exploratory wells were drilled at
West Cameron Block 498 in 1995, two exploratory wells at West Cameron Block 498
and one exploratory well at West Cameron Block 65 were drilled and drilling and
plugging and abandonment operations at West Delta Block 34 occurred in 1994, and
two exploratory wells were drilled at West Delta Block 34 in 1993. As a result,
excess Class A cost carry-forwards of $1.9 million in 1995, $0.5 million in 1994
and $0.2 million in 1993 were generated. Accruals for future estimated
abandonment costs totaled $0.5 million, $1.5 million (including $0.5 million
related to the settlement payment) and $4 million (including $0.9 million
related to the settlement payment) for 1995, 1994 and 1993, respectively.
Royalty proceeds were $5.2 million in 1995, $2.6 million in 1994 and $6.8
million in 1993, and were reduced by Trust administrative expenses of $0.4
million, $0.5 million and $0.6 million, respectively. Royalty proceeds in 1995
and 1994 were further reduced by funding of the reserve for future Trust
administrative expenses amounting to $0.3 million and $2 million, respectively
(See Note 7 -- Establishment of an Expense Reserve). Interest earned by the
Trust on funds invested between quarterly distributions to Unit holders (and for
1995 and 1994 on funds held in the reserve for future Trust administrative
expenses) was $0.1 million in 1995, $0.05 million in 1994 and $0.02 million in
1993.
CAPITAL RESOURCES AND LIQUIDITY
All revenues received by the Trust, net of Trust administrative expenses
and liabilities, are distributed to the Unit holders in accordance with
provisions of the Trust Indenture. As a result of the cumulative excess Class A
cost carry-forward of $1.9 million net to the Trust at December 31, 1995 and the
additional development activities anticipated at West Cameron Block 498 and
exploratory drilling anticipated on other Royalty Properties, the amount and
timing of future distributions to Unit holders are presently indeterminable.
In February 1996, drilling operations commenced on an exploratory well on
Breton Sound Block 55. The Working Interest Owner owns an 18.75% working
interest in Breton Sound Block 55 and a 9.375% working interest in this well
pursuant to a codevelopment agreement with the owner of the adjacent block.
Costs and ownership of production resulting from this activity will be
retroactively adjusted based upon the location of any reserves discovered
following development of the area if commercial hydrocarbons are discovered. The
estimated drilling cost for the well is $.8 million net to the Trust. Additional
costs may be required to complete the well and develop it for production.
Additional exploration may be proposed for certain other Royalty Properties
where geologic features have been identified through the utilization of 3D
seismic technology. After analyzing each proposal, the Working Interest Owner
will determine whether or not to participate in additional exploratory
operations.
Total exploration and development costs for 1996 are presently budgeted at
approximately $8 million for the Working Interest Owner, including West Cameron
Block 498 development and exploratory drilling at Vermilion Block 58 and Breton
Sound Block 55. These cost estimates are provided by the operators of the
Royalty Properties and may vary from actual costs depending on the
31
<PAGE> 34
success of drilling, particular circumstances encountered during drilling and
many other factors outside the control of the operator. These expenditures can
be expected to reduce and could further delay resumption of distributions to
Unit holders.
The operators of the Trust properties have provided 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 1995, such estimates, net
of abandonment cost incurred, totaled $16.2 million net to the Trust, of which
$12.8 million has been withheld from distributions to Unit holders as of
December 31, 1995. Based on the revised estimated future abandonment costs,
future distributions to Unit holders will be reduced by approximately $0.22 per
Unit over the remaining productive lives of the properties, subject to future
revisions of such costs.
Exploratory drilling on West Cameron Block 498 began in June 1994 and has
resulted in 4 successful wells to date which have been saved for future
development. In its reserve report, Ryder Scott assigned to the Trust's interest
in this property estimated net proved reserves of 3 bcf of natural gas and
616,000 barrels of oil with a discounted (at 10%) estimated future net cash flow
of approximately $9.6 million. See Part 1 -- Business -- The Royalty Properties
and the Royalty -- Reserves. The activity schedule for this property, as
approved by the MMS, currently estimates that construction of the platform and
facilities will commence in June 1996 and that production will commence by the
end of March 1997.
In December 1995, the Vermilion Block 58 No. 10 exploratory well was
spudded and subsequently drilled to its objective depth. Based on an evaluation
of the results, the Working Interest Owner concluded that it would not pursue
any further development of this well.
From 1986 through 1992, the Working Interest Owner entered into several gas
contract settlements with a gas purchaser related to the Royalty Properties
which involved payments of cash by the gas purchaser to the Working Interest
Owner. The Working Interest Owner included in Gross Proceeds the payments
received in connection with these settlements, net of amounts retained in a
suspense account representing settlement proceeds that were subject to possible
royalty obligations to the MMS. In December 1994, the Working Interest Owner
entered into an agreement with the MMS relating to these gas contract
settlements, resulting in a payment by the Working Interest Owner. After the
settlement, approximately $4 million of the funds initially retained for
possible royalty obligations remained. The Working Interest Owner informed the
Trustee that it anticipated expenditures for the development operations on the
Royalty Properties in excess of $4 million and, accordingly, proposed to retain
the funds remaining in the suspense account for use as payments of these
anticipated expenditures, as sufficient funds may not be otherwise available.
The Trustee and the Working Interest Owner evaluated the legal, tax and other
issues relating to retaining such amounts for use in the exploratory and
development operations on the Royalty Properties and concluded that the funds
should be paid to the Trust. Such funds, including interest, were included in
the April 1995 Net Proceeds as a special payment resulting in a distribution of
$0.28794 per Unit.
At certain times since late 1993, the Trust has been unable to pay its
ongoing administrative expenses. To permit the Trust to pay its administrative
expenses during the time the Trust incurs a Class A cost deficit, the Trustee,
in accordance with the Trust Indenture, established 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 $2.3 million remained at December
1995.
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. The Trustee must distribute the net proceeds of such sale (after
satisfaction of any outstanding liabilities) to the Unit holders.
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,
----------------------------------------
1995 1994 1993
---------- ---------- ----------
<S> <C> <C> <C>
Royalty proceeds................................... $5,235,068 $2,551,586 $6,797,931
Trust administrative expenses...................... (369,101) (626,201) (487,018)
Interest income.................................... 119,510 52,198 23,777
Reserve for future Trust expenses.................. (323,396) (1,977,583) --
---------- ---------- ----------
Distributable cash................................. $4,662,081 $ -- $6,334,690
========== ========== ==========
Distributable cash per Unit........................ $ 0.31130 $ -- $ 0.42295
========== ========== ==========
Units outstanding.................................. 14,975,390 14,975,390 14,975,390
========== ========== ==========
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1995 1994
------------ ------------
<S> <C> <C>
ASSETS
Cash........................................................... $ 2,300,979 $ 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..................................................... (164,260,985) (164,231,280)
------------ ------------
Total assets................................................... $ 2,484,192 $ 2,190,501
============ ============
LIABILITIES AND TRUST CORPUS
Distributions payable to Unit holders.......................... $ -- $ --
Reserve for future Trust expenses.............................. 2,300,979 1,977,583
Trust corpus (14,975,390 Units of Beneficial Interest
authorized, issued and outstanding).......................... 183,213 212,918
------------ ------------
Total liabilities and trust corpus............................. $ 2,484,192 $ 2,190,501
============ ============
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------------
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Trust corpus, beginning of year................. $ 212,918 $ 260,059 $ 358,762
Royalty proceeds and interest earned, net of
trust administrative expenses and reserve for
future Trust expenses......................... 4,662,081 -- 6,334,690
Distributions payable to Unit holders........... (4,662,081) -- (6,334,690)
Amortization of net overriding royalty
interest...................................... (29,705) (47,141) (98,703)
----------- ----------- -----------
Trust corpus, end of year....................... $ 183,213 $ 212,918 $ 260,059
=========== =========== ===========
</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.
The Trust Indenture provides generally that the Trust shall terminate upon
the first to occur of: (i) the sale of all the Trust's interest in the
Partnership, or the sale by the Partnership of all the assets of the Partnership
including the Royalty, or (ii) a decision to terminate the Trust by the
affirmative vote of Unit holders representing a majority of the Units. As noted
above, the Trustee is required to sell the Trust's interest in the Partnership,
or cause the Partnership to sell the Royalty, if the Trust's cash receipts for
each of three successive years are less than $3 million, thereby terminating the
Trust pursuant to (i) above. Upon the termination of the Trust under (ii) above,
the Trustee will sell the Royalty (or will cause the Partnership to sell all of
the assets of the Partnership). The Trustee will as promptly as possible
distribute the proceeds of any such sales according to the respective interests
and rights of the Unit holders after discharging all of the liabilities of the
Trust and, if necessary, setting up reserves in such amounts as the Trustee in
its discretion deems appropriate for contingent liabilities.
2. THE ROYALTY
Freeport-McMoRan Oil & Gas Company (FMOG), a 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.
34
<PAGE> 37
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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, 1995 is necessarily indicative of the fair
market value of the Royalty held by the Trust.
Because the Trust is a grantor trust which is not a taxable entity, no
income taxes are reported in the Trust's financial statements. The tax
consequences of owning Units are included in the federal, state and local income
tax returns of the individual Unit holders.
4. DISTRIBUTIONS TO UNIT HOLDERS
A cumulative excess Class A cost carry-forward of $476,435 as of December
31, 1994 was eliminated in February 1995 and funding of a $2.4 million Trust
administrative expense reserve (Note 7) was completed in April 1995 by means of
the settlement payment (Note 6). As a result of the capital costs associated
with the drilling on West Cameron Block 498 during the second half of 1995,
there was a cumulative excess Class A cost carry-forward of $1,875,852 as of
December 31, 1995 and $99,021 of the Trust administrative expense reserve was
utilized. The excess Class A cost carry-forward is subject to interest due the
Working Interest Owner at the prime rate, which averaged 8.75 percent in 1995.
The carry-forward includes $23,909 in accumulated interest. This excess Class A
cost carry-forward must be recouped out of future Net Proceeds before
distribution to the Unit holders can be resumed.
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, 1995, the
unrecovered quantity of gas sold by third parties pursuant to such gas balancing
arrangements since inception of the Trust through September 30, 1995 was
approximately 1.7 billion cubic feet (bcf), net to the Trust. 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, a settlement payment of
$2.3 million (approximately $0.15 per Unit) was included in the distribution
paid to Unit holders of record on January 29, 1993. 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.
35
<PAGE> 38
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
From 1986 through 1992, the Working Interest Owner entered into several gas
contract settlements with a gas purchaser related to the Royalty Properties
which involved payments of cash by the gas purchaser to the Working Interest
Owner. The Working Interest Owner included in Gross Proceeds the payments
received in connection with these settlements, net of amounts retained in a
suspense account representing settlement proceeds that were subject to possible
royalty obligations to the Minerals Management Service (the MMS). In December
1994, the Working Interest Owner entered into an agreement with the MMS relating
to these gas contract settlements, resulting in a payment by the Working
Interest Owner. After the settlement, approximately $4 million of the funds
initially retained for possible royalty obligations remained. The Working
Interest Owner informed the Trustee that it anticipated expenditures for the
development operations on the Royalty Properties in excess of $4 million and,
accordingly, proposed to retain the funds remaining in the suspense account for
use as payments of these anticipated expenditures, as sufficient funds may not
be otherwise available. The Trustee and the Working Interest Owner evaluated the
legal, tax and other issues relating to retaining such amounts for use in the
exploratory and development operations on the Royalty Properties and concluded
that the funds should be paid to the Trust. Such funds, including interest, were
included in the April 1995 Net Proceeds as a special payment resulting in a
distribution of $0.28794 per Unit.
7. ESTABLISHMENT OF AN EXPENSE RESERVE
Because of the decline in Royalty income, at certain times since late 1993
the Trust has been unable to pay its ongoing administrative expenses. To permit
the Trust to pay its routine administrative expenses during the time the Trust
incurs a Class A cost deficit, the Trustee, in accordance with the Trust
Indenture, established an expense reserve of approximately $2.4 million. This
reserve was funded with $1.9 million from a January 1994 settlement payment,
$0.3 million from Royalty income and $0.2 million from the April 1995 special
payment (Note 6). Because of the cumulative excess Class A cost carry-forward as
of December 31, 1995 (Note 4), $99,021 was withdrawn from the expense reserve to
pay current Trust administrative expenses. There will be tax consequences to the
Unit holders for such reserve as described in Note 8 below.
The funding for this reserve is deposited with Texas Commerce Bank and
invested in Texas Commerce Bank collateralized certificates of deposit. The
average interest rate earned on these funds was 3.7 percent for 1995 and 2.8
percent for 1994.
8. FEDERAL INCOME TAX MATTERS
Unit holders will be required to report taxable income for Royalty income
received by the Trust and deposited to the expense reserve even if no
distributions were received by the Unit holders. The expense reserve established
for Trust administrative expenses described in Note 7 above, however, will give
rise to future tax deductions as additional administrative expenses are incurred
and paid with funds deposited in the reserve.
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 1995
estimate, net of abandonment costs incurred, totals $16.2 million net to the
Trust, of which $12.8 million has been withheld from distributions to Unit
holders as of December 31, 1995. The actual costs to abandon the 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 future distributable cash.
36
<PAGE> 39
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
10. SUPPLEMENTARY PROVED OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Pursuant to the Financial Accounting Standards Board's (FASB) disclosure
standards for oil and gas producing activities, the Trust is required to include
as supplementary information estimates of quantities of proved oil and gas
reserves attributable to the Trust. Since the Royalty is a net profits interest,
the Partnership does not own and is not entitled to receive any specific volume
of reserves. Reserves attributable to the Partnership have been estimated based
on projections of reserves and future net cash flows attributable to the
combined interests of the Working Interest Owner and the Partnership, and a
formula based upon estimates of future net cash flows. As a result of estimating
reserve volumes by using a formula based upon estimates of future net cash
flows, such reserves are necessarily affected by changes in various economic
factors including prices, costs and the level and timing of capital expenditures
on the properties. Therefore, the reserve volume estimates set forth below are
hypothetical and are not comparable to estimates of reserves attributable to a
working interest.
The reserve volume and cash flow amounts set forth below are for the
interest in the Royalty attributable to the Trust, based on the Trust's 99.9
percent interest in the Partnership. Estimates of proved oil and gas reserves
attributable to the Trust's interest are based on reports of Ryder Scott Company
Petroleum Engineers (Ryder Scott). In preparing its estimates, Ryder Scott did
not take into account (a) revenues received after November 30, attributable to
production during the fourth quarter of the respective year, (b) as of December
31, 1995, 1994 and 1993, approximately 1.7 bcf, 2.0 bcf, and 2.7 bcf sold by
other parties pursuant to certain gas balancing arrangements, (c) as of December
31, 1993 approximately $2.6 million plus interest to be received in connection
with the Transco gas contract settlement and (d) an excess Class A cost
carry-forward of $1.9 million, $0.5 million and $0.2 million at December 31,
1995, 1994 and 1993, respectively. In connection with the Transco Gas Contract
settlement, $2.3 million, net of $0.8 million withheld for estimated future
abandonment costs, was included in distributions paid to Unit holders of record
January 29, 1993. 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. For purposes of the reserve volume and cash flow
amounts set forth below, the Trustee adjusted the estimates of Ryder Scott to
take into account the foregoing factors, based on calculations supplied by the
Working Interest Owner.
As discussed in Note 9, based on escalated estimates of costs to abandon
the Trust properties, approximately $3.4 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.
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, 1995, 1994 and 1993.
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>
1995 1994 1993
------------- ------------- ---------------
OIL GAS OIL GAS OIL GAS
--- ------ --- ------ ---- -------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of year..... 79 3,243 116 8,258 75 7,968
Revisions of previous estimates(1)... (24) 430 (3) (4,464) 98 789
Extensions and discoveries(2)........ 616 2,950 3 160 3 1,669
Production........................... (68) (1,382) (37) (711) (60) (2,168)
--- ------ --- ------ ---- -------
Proved reserves, at end of year........ 603 5,241 79 3,243 116 8,258
=== ====== === ====== ==== =======
</TABLE>
(See notes on following page)
37
<PAGE> 40
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
- ------------
(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 Cameron Block
498 in 1995, the West Cameron Block 65 No. 7 well in 1994 and the West
Delta Block 34 No. 10 well in 1993, which was plugged and abandoned in
April 1994 after unsuccessful attempts to complete the well.
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).
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.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED OIL AND GAS
RESERVES:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------------
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Future cash flows.............................. $21,753,000 $ 8,693,000 $29,876,000 (1)
Discount for estimated timing of cash flows (10
percent discount rate)....................... (9,457,000 ) (1,624,000 ) (3,733,000 )
------------ ------------ ------------
Standardized measure of discounted future net
cash flows from proved oil and gas
reserves..................................... $12,296,000 $ 7,069,000 $26,143,000
============ ============ ============
</TABLE>
38
<PAGE> 41
FREEPORT-MCMORAN OIL AND GAS ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM
PROVED OIL AND GAS RESERVES:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------------------
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Discounted future net cash flows,
beginning of year............................ $ 7,069,000 $26,143,000 $21,560,000
Royalty proceeds............................. (5,235,000 ) (2,552,000 ) (6,798,000 )
Revisions of previous estimates:
Changes in prices and other(2)............ 164,000 (19,594,000 ) 46,000
Extensions and discoveries(3)............. 9,591,000 458,000 9,179,000
Accretion of discount(4).................. 707,000 2,614,000 2,156,000
------------ ------------ ------------
Discounted future net cash flows, end of
year......................................... $12,296,000 $ 7,069,000 $26,143,000
============ ============ ============
</TABLE>
- ------------
(1) Includes approximately $2.6 million plus interest at December 31, 1993
related to a gas contract settlement (See Note 6 above).
(2) 1995 includes $4.3 million related to the special payment in April 1995 and
1994 includes the effect of unsuccessful attempts to complete the West
Delta Block 34 No. 10 well.
(3) Includes discounted future net cash flow related to West Cameron Block 498
in 1995, the West Cameron Block 65 No. 7 well in 1994 and the West Delta
Block 34 No. 10 well in 1993, which was plugged and abandoned in April 1994
after unsuccessful attempts to complete the well.
(4) "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, 1995 and 1994, 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,
1995. 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, 1995 and 1994, and
the royalty proceeds and distributable cash, and changes in trust corpus for
each of the three years in the period ended December 31, 1995, on the cash basis
of accounting described in Note 3.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana,
February 28, 1996
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.
- -----------
<S> <C>
4.1* -- Overriding Royalty Conveyance from McMoRan-Freeport Oil
Company to McMoRan Oil & Gas Co. (attached as Annex I to
Exhibit 4.4).
4.2* -- Royalty Trust Indenture for Freeport-McMoRan Oil and Gas
Royalty Trust between Freeport-McMoRan Inc. ("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 1995.
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: /s/ MICHAEL J. ULRICH
--------------------------------------
Michael J. Ulrich
Senior Vice President and Trust
Officer
March 18, 1996
The Registrant, Freeport-McMoRan Oil and Gas Royalty Trust, has no
principal executive officer, principal financial officer, principal accounting
officer, board of directors or persons performing similar functions.
Accordingly, no additional signatures are required.
43
<PAGE> 46
INDEX TO EXHIBITS
27 -- Financial Data Schedule.
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<CASH> 2,300,979
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 2,300,979
<PP&E> 189,875,741
<DEPRECIATION> 189,692,528
<TOTAL-ASSETS> 2,484,192
<CURRENT-LIABILITIES> 2,300,979
<BONDS> 0
<COMMON> 0
0
0
<OTHER-SE> 183,213
<TOTAL-LIABILITY-AND-EQUITY> 2,484,192
<SALES> 5,235,068
<TOTAL-REVENUES> 5,354,578
<CGS> 0
<TOTAL-COSTS> 369,101
<OTHER-EXPENSES> 323,396
<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>
