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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER: 1-8424
SABINE ROYALTY TRUST
(Exact name of registrant as specified in its charter)
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TEXAS 75-6297143
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
TRUST DIVISION
BANK OF AMERICA, N.A.
BANK OF AMERICA PLAZA
17TH FLOOR
901 MAIN STREET
DALLAS, TEXAS 75202
(Address of principal executive offices) (Zip Code)
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Registrant's telephone number, including area code: (214) 209-2400
Securities registered pursuant to Section 12(b) of the Act:
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NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON 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 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]
At March 15, 2000, there were 14,579,345 units of beneficial interest
outstanding and the aggregate market value of such units (based on the closing
sale price on the New York Stock Exchange) held by non-affiliates of the
registrant was approximately $207,755,666.
DOCUMENTS INCORPORATED BY REFERENCE
None
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TABLE OF CONTENTS
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PART I
Item 1. Business.................................................... 1
Description of the Trust.................................... 1
Assets of the Trust......................................... 2
Liabilities of the Trust.................................... 2
Duties and Limited Powers of Trustee........................ 2
Liabilities of Trustee...................................... 3
Duration of Trust........................................... 3
Voting Rights of Unit Holders............................... 3
Description of Units........................................ 4
Distributions of Net Income................................. 4
Transfer.................................................... 4
Reports to Unit Holders..................................... 4
Liability of Unit Holders................................... 5
Possible Divestiture of Units............................... 5
Federal Taxation............................................ 6
State Law and Tax Considerations............................ 7
Regulation and Prices....................................... 8
Regulation.................................................. 8
Prices...................................................... 9
Item 2. Properties.................................................. 10
Title....................................................... 10
Reserves.................................................... 11
Item 3. Legal Proceedings........................................... 16
Item 4. Submission of Matters to a Vote of Security Holders......... 16
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 17
Item 6. Selected Financial Data..................................... 17
Item 7. Trustee's Discussion and Analysis of Financial Condition and
Results of Operations....................................... 17
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 19
Item 8. Financial Statements and Supplementary Data................. 20
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 30
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 30
Item 11. Executive Compensation...................................... 30
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 30
Item 13. Certain Relationships and Related Transactions.............. 30
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 31
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PART I
ITEM 1. BUSINESS.
DESCRIPTION OF THE TRUST
Sabine Royalty Trust (the "Trust") is an express trust formed under the
laws of the State of Texas by the Sabine Corporation Royalty Trust Agreement
(the "Trust Agreement") made and entered into effective as of December 31, 1982,
between Sabine Corporation, as trustor, and InterFirst Bank Dallas, N.A.
("InterFirst"), as trustee. The current trustee of the Trust is Bank of America,
N.A. (as successor to NationsBank, N.A.) ("Bank of America"). In accordance with
the successor trustee provisions of the Trust Agreement, Bank of America, as
trustee of the Trust (the "Trustee"), is subject to all the terms and conditions
of the Trust Agreement. The principal office of the Trust (sometimes referred to
herein as the "Registrant") is located at Bank of America Plaza, 17th Floor, 901
Main Street, Dallas, Texas 75202. The telephone number of the Trust is (214)
209-2400.
On November 12, 1982, the shareholders of Sabine Corporation approved and
authorized Sabine Corporation's transfer of royalty and mineral interests,
including landowner's royalties, overriding royalty interests, minerals (other
than executive rights, bonuses and delay rentals), production payments and any
other similar, nonparticipatory interest, in certain producing and proved
undeveloped oil and gas properties located in Florida, Louisiana, Mississippi,
New Mexico, Oklahoma and Texas (the "Royalty Properties") to the Trust. The
conveyances of the Royalty Properties to the Trust were effective with respect
to production as of 7:00 a.m. (local time) on January 1, 1983.
In order to avoid uncertainty under Louisiana law as to the legality of the
Trustee's holding record title to the Royalty Properties located in that state,
title to such properties is held by a separate trust formed under the laws of
Louisiana, the sole beneficiary of which is the Trust. Sabine Louisiana Royalty
Trust is a passive entity, with the trustee thereof, Hibernia National Bank in
New Orleans, having only such powers as are necessary for the collection of and
distribution of revenues from and the protection of the Royalty Properties
located in Louisiana and the payment of liabilities of Sabine Louisiana Royalty
Trust. A separate trust also was established to hold record title to the Royalty
Properties located in Florida. Legislation was adopted in Florida in 1992 that
eliminated the provision of Florida law that prohibited the Trustee from holding
record title to the Royalty Properties located in that state. In November 1993,
record title to the Royalty Properties held by the trustee of Sabine Florida
Land Trust was transferred to the Trustee. As used herein, the term "Royalty
Properties" includes the Royalty Properties held directly by the Trust and the
Royalty Properties located in Louisiana and Florida that are or were held
indirectly through the Trust's ownership of 100 percent beneficial interest of
Sabine Louisiana Royalty Trust and Sabine Florida Land Trust. In discussing the
Trust, this report disregards the technical ownership formalities described in
this paragraph, which have no effect on the tax or accounting treatment of the
Royalty Properties, since the observance thereof would significantly complicate
the information presented herein without any corresponding benefit to Unit
holders.
Certificates evidencing units of beneficial interest (the "Units") in the
Trust were mailed on December 31, 1982 to the shareholders of Sabine Corporation
of record on December 23, 1982, on the basis of one Unit for each outstanding
share of common stock of Sabine Corporation. The Units are listed and traded on
the New York Stock Exchange under the symbol "SBR".
In May 1988, Sabine Corporation was acquired by Pacific Enterprises, a
California corporation. Through a series of mergers, Sabine Corporation was
merged into Pacific Enterprises Oil Company (USA) ("Pacific (USA)"), a
California corporation and a wholly owned subsidiary of Pacific Enterprises,
effective January 1, 1990. This acquisition and the subsequent mergers had no
effect on the Units. Pacific (USA), as successor to Sabine Corporation, assumed
by operation of law all of Sabine Corporation's rights and obligations with
respect to the Trust. References herein to Pacific (USA) shall be deemed to
include Sabine Corporation where appropriate.
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In connection with the transfer of the Royalty Properties to the Trust upon
its formation, Sabine Corporation had reserved to itself all executive rights,
including rights to execute leases and to receive bonuses and delay rentals. In
January 1993, Pacific (USA) completed the sale of substantially all of Pacific
(USA)'s producing oil and gas assets to Hunt Oil Company. The sale did not
include the executive rights relating to the Royalty Properties, and Pacific
(USA)'s ownership of such rights was not affected by the sale.
The following summaries of certain provisions of the Trust Agreement are
qualified in their entirety by reference to the Trust Agreement itself, which is
an exhibit to the Form 10-K and available upon request from the Trustee. The
definitions, formulas, accounting procedures and other terms governing the Trust
are complex and extensive and no attempt has been made below to describe all
such provisions. Capitalized terms not otherwise defined herein are used with
the meanings ascribed to them in the Trust Agreement.
ASSETS OF THE TRUST
The Royalty Properties are the only assets of the Trust, other than cash
being held for the payment of expenses and liabilities and for distribution to
the Unit holders. Pending such payment of expenses and distribution to Unit
holders, cash may be invested by the Trustee only in certificates of deposit,
United States government securities or repurchase agreements secured by United
States government securities. See "Duties and Limited Powers of Trustee" below.
LIABILITIES OF THE TRUST
Because of the passive nature of the Trust's assets and the restrictions on
the power of the Trustee to incur obligations, it is anticipated that the only
liabilities the Trust will incur are those for routine administrative expenses,
such as insurance and trustee's fees, and accounting, engineering, legal and
other professional fees. The total general and administrative expenses of the
Trust for 1999 were $1,434,829 of which, pursuant to the terms of the Trust
Agreement, $219,408 was paid to Bank of America, as Trustee, and $658,234 was
paid to Bank of America, as escrow agent.
DUTIES AND LIMITED POWERS OF TRUSTEE
The duties of the Trustee are specified in the Trust Agreement and by the
laws of the State of Texas. The basic function of the Trustee is to collect
income from the Trust properties, to pay out of the Trust's income and assets
all expenses, charges and obligations, and to pay available income to Unit
holders. Since Pacific (USA) has retained the executive rights with respect to
the minerals included in the Royalty Properties and the right to receive any
future bonus payments or delay rentals resulting from leases with respect to
such minerals, the Trustee is not required to make any investment or operating
decision with respect to the Royalty Properties.
The Trust has no employees. Administrative functions of the Trust are
performed by the Trustee.
The Trustee has the discretion to establish a cash reserve for the payment
of any liability that is contingent or uncertain in amount or that otherwise is
not currently due and payable. The Trustee has the power to borrow funds
required to pay liabilities of the Trust as they become due and pledge or
otherwise encumber the Trust's properties if it determines that the cash on hand
is insufficient to pay such liabilities. Borrowings must be repaid in full
before any further distributions are made to Unit holders. All distributable
income of the Trust is distributed on a monthly basis. The Trustee is required
to invest any cash being held by it for distribution on the next Distribution
Date or as a reserve for liabilities in certificates of deposit, United States
government securities or repurchase agreements secured by United States
government securities. The Trustee furnishes Unit holders with periodic reports.
See "Item 1 -- Description of Units -- Reports to Unit Holders".
The Trust Agreement grants the Trustee only such rights and powers as are
necessary to achieve the purposes of the Trust. The Trust Agreement prohibits
the Trustee from engaging in any business, commercial or, with certain
exceptions, investment activity of any kind and from using any portion of the
assets of the Trust to acquire any oil and gas lease, royalty or other mineral
interest other than the Royalty
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Properties. The Trustee may sell Trust properties only as authorized by a vote
of the Unit holders, or when necessary to provide for the payment of specific
liabilities of the Trust then due or upon termination of the Trust. Pledges or
other encumbrances to secure borrowings are permitted without the authorization
of Unit holders if the Trustee determines such action is advisable. Any sale of
Trust properties must be for cash unless otherwise authorized by the Unit
holders or unless the properties are being sold to provide for the payment of
specific liabilities of the Trust then due, and the Trustee is obligated to
distribute the available net proceeds of any such sale to the Unit holders.
LIABILITIES OF TRUSTEE
The Trustee is to be indemnified out of the assets of the Trust for any
liability, expense, claim, damage or other loss incurred by it in the
performance of its duties unless such loss results from its negligence, bad
faith or fraud or from its expenses in carrying out such duties exceeding the
compensation and reimbursement it is entitled to under the Trust Agreement. The
Trustee can be reimbursed out of the Trust assets for any liability imposed upon
the Trustee for its failure to ensure that the Trust's liabilities are
satisfiable only out of Trust assets. In no event will the Trustee be deemed to
have acted negligently, fraudulently or in bad faith if it takes or suffers
action in good faith in reliance upon and in accordance with the advice of
parties considered to be qualified as experts on the matters submitted to them.
The Trustee is not entitled to indemnification from Unit holders except in
certain limited circumstances related to the replacement of mutilated,
destroyed, lost or stolen certificates. See "Item 1 -- Description of Units --
Liability of Unit Holders".
DURATION OF TRUST
The Trust is irrevocable and Pacific (USA) has no power to terminate the
Trust or, except with respect to certain corrective amendments, to alter or
amend the terms of the Trust Agreement. The Trust will exist until it is
terminated by (i) two successive fiscal years in which the Trust's gross
revenues from the Royalty Properties are less than $2,000,000 per year, (ii) a
vote of Unit holders as described below under "Voting Rights of Unit Holders" or
(iii) operation of provisions of the Trust Agreement intended to permit
compliance by the Trust with the "rule against perpetuities". Upon the
termination of the Trust, the Trustee will continue to act in such capacity
until all the assets of the Trust are distributed. The Trustee will sell all
Trust properties for cash (unless the Unit holders authorize the sale for a
specified non-cash consideration, in which event the Trustee may, but is not
obligated to, consummate such non-cash sale) in one or more sales and, after
satisfying all existing liabilities and establishing adequate reserves for the
payment of contingent liabilities, will distribute all available proceeds to the
Unit holders.
VOTING RIGHTS OF UNIT HOLDERS
Although Unit holders possess certain voting rights, their voting rights
are not comparable to those of shareholders of a corporation. For example, there
is no requirement for annual meetings of Unit holders or for annual or other
periodic re-election of the Trustee.
The Trust Agreement may be amended by the affirmative vote of a majority of
the outstanding Units at any duly called meeting of Unit holders. However, no
such amendment may alter the relative rights of Unit holders unless approved by
the affirmative vote of 100 percent of the Unit holders and by the Trustee. In
addition, certain special voting requirements can be amended only if such
amendment is approved by the holders of at least 80 percent of the outstanding
Units and by the Trustee.
Removal of the Trustee requires the affirmative vote of the holders of a
majority of the Units represented at a duly called meeting of Unit holders. In
the event of a vacancy in the position of Trustee or if the Trustee has given
notice of its intention to resign, a successor trustee of the Trust may be
appointed by similar voting approval of the Unit holders.
The sale of all or any part of the assets of the Trust must be authorized
by the affirmative vote of the holders of a majority of the outstanding Units.
However, the Trustee may, without a vote of the Unit holders, sell all or any
part of the Trust assets upon termination of the Trust or otherwise if necessary
to
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provide for the payment of specific liabilities of the Trust then due. The Trust
can be terminated by the Unit holders only if the termination is approved by the
holders of a majority of the outstanding Units.
Meetings of Unit holders may be called by the Trustee at any time at its
discretion and must be called by the Trustee at the written request of holders
of not less than 10 percent of the then outstanding Units. The presence of a
majority of the outstanding Units is necessary to constitute a quorum and Unit
holders may vote in person or by proxy.
Notice of any meeting of Unit holders must be given not more than 60 nor
less than 20 days prior to the date of such meeting. The notice must state the
purposes of the meeting and no other matter may be presented or acted upon at
the meeting.
DESCRIPTION OF UNITS
Each Unit represents an equal undivided share of beneficial interest in the
Trust and is evidenced by a transferable certificate issued by the Trustee. Each
Unit entitles its holder to the same rights as the holder of any other Unit, and
the Trust has no other authorized or outstanding class of equity security. At
March 15, 2000, there were 14,579,345 Units outstanding.
The Trust may not issue additional Units unless such issuance is approved
by the holders of at least 80 percent of the outstanding Units and by the
Trustee. Under limited circumstances, Units may be redeemed by the Trust and
canceled. See "Possible Divestiture of Units" below.
DISTRIBUTIONS OF NET INCOME
The identity of Unit holders entitled to receive distributions of Trust
income and the amounts thereof are determined as of each Monthly Record Date.
Unit holders of record as of the Monthly Record Date (the 15th day of each
calendar month except in limited circumstances) are entitled to have distributed
to them the calculated Monthly Income Amount for the related Monthly Period no
later than 10 business days after the Monthly Record Date. The Monthly Income
Amount is the excess of (i) revenues from the Trust properties plus any decrease
in cash reserves previously established for contingent liabilities and any other
cash receipts of the Trust over (ii) the expenses and payments of liabilities of
the Trust plus any increase in cash reserves for contingent liabilities.
TRANSFER
Units are transferable on the records of the Trustee upon surrender of any
certificate in proper form for transfer and compliance with such reasonable
regulations as the Trustee may prescribe. 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 governmental charge that may be
imposed in relation to such transfer. Until any such transfer, the Trustee may
conclusively treat the holder of a Unit shown by its records as the owner of
that Unit for all purposes. Any such transfer of a Unit will, as to the Trustee,
vest in the transferee all rights of the transferor at the date of transfer,
except that the transfer of a Unit after the Monthly Record Date for a
distribution will not transfer the right of the transferor to such distribution.
The transfer of Units by gift and the transfer of Units held by a
decedent's estate, and distributions from the Trust in respect thereof, may be
restricted under applicable state law. See "Item 1 -- State Law and Tax
Considerations".
Chase Mellon Shareholder Services serves as transfer agent and registrar
for the Units.
REPORTS TO UNIT HOLDERS
As promptly as practicable following the end of each fiscal year, the
Trustee mails to each person who was a Unit holder on any Monthly Record Date
during such fiscal year, a report showing in reasonable detail on a cash basis
the receipts and disbursements and income and expenses of the Trust for federal
and state tax purposes for each Monthly Period during such fiscal year and
containing sufficient information to
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enable Unit holders to make all calculations necessary for federal and state tax
purposes. As promptly as practicable following the end of each of the first
three fiscal quarters of each year, the Trustee mails a report for such fiscal
quarter showing in reasonable detail on a cash basis the assets and liabilities,
receipts and disbursements, and income and expenses of the Trust for such fiscal
quarter to Unit holders of record on the last Monthly Record Date immediately
preceding the mailing thereof. Within 120 days following the end of each fiscal
year, or such shorter period as may be required by the New York Stock Exchange,
the Trustee mails to Unit holders of record on the last Monthly Record Date
immediately preceding the mailing thereof, an annual report containing audited
financial statements of the Trust and an audited statement of fees and expenses
paid by the Trust to Bank of America, as Trustee and escrow agent. See "Federal
Taxation" below.
Each Unit holder and his or her duly authorized agent has the right, during
reasonable business hours at his or her own expense, to examine and make audits
of the Trust and the records of the Trustee, including lists of Unit holders,
for any proper purpose in reference thereto.
LIABILITY OF UNIT HOLDERS
As regards the Unit holders, the Trustee, in engaging in any activity or
transaction that results or could result in any kind of liability, will be fully
liable if the Trustee fails to take reasonable steps necessary to ensure that
such liability is satisfiable only out of the Trust assets (even if the assets
are inadequate to satisfy the liability) and in no event out of amounts
distributed to, or other assets owned by, Unit holders. However, the Trust might
be held to constitute a "joint stock company" under Texas law, which is
unsettled on this point, and therefore a Unit holder may be jointly and
severally liable for any liability of the Trust if the satisfaction of such
liability was not contractually limited to the assets of the Trust and the
assets of both the Trust and the Trustee are not adequate to satisfy such
liability. In view of the substantial value and passive nature of the Trust
assets, the restrictions on the power of the Trustee to incur liabilities and
the required financial net worth of any trustee of the Trust, the imposition of
any liability on a Unit holder is believed to be extremely unlikely.
POSSIBLE DIVESTITURE OF UNITS
The Trust Agreement imposes no restrictions based on nationality or other
status of the persons or entities which are eligible to hold Units. However, the
Trust Agreement provides that if at any time the Trust or the Trustee is named a
party in any judicial or administrative proceeding seeking the cancellation or
forfeiture of any property in which the Trust has an interest because of the
nationality, or any other status, of any one or more Unit holders, the following
procedure will be applicable:
1. The Trustee will give written notice to each holder whose
nationality or other status is an issue in the proceeding of the existence
of such controversy. The notice will contain a reasonable summary of such
controversy and will constitute a demand to each such holder that he or she
dispose of his or her Units within 30 days to a party not of the
nationality or other status at issue in the proceeding described in the
notice.
2. If any holder fails to dispose of his or her Units in accordance
with such notice, the Trustee shall have the preemptive right to redeem and
shall redeem, at any time during the 90-day period following the
termination of the 30-day period specified in the notice, any Unit not so
transferred for a cash price equal to the closing price of the Units on the
stock exchange on which the Units are then listed or, in the absence of any
such listing, the mean between the closing bid and asked prices for the
Units in the over-the-counter market, as of the last business day prior to
the expiration of the 30-day period stated in the notice.
3. The Trustee shall cancel any Unit acquired in accordance with the
foregoing procedures.
4. The Trustee may, in its sole discretion, cause the Trust to borrow
any amount required to redeem Units.
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FEDERAL TAXATION
In May 1983, the Internal Revenue Service (the "Service") ruled that the
Trust would be classified as a grantor trust for federal income tax purposes and
not as an association taxable as a corporation. Accordingly, the income and
deductions of the Trust are reportable directly by Unit holders for federal
income tax purposes. The Service also ruled that Unit holders would be entitled
to deduct cost depletion with respect to their investment in the Trust and that
the transfer of a Unit in the Trust would be considered to be a transfer of a
proportionate part of the properties held by the Trust.
Transferees of Units transferred after October 11, 1990 may be eligible to
use the percentage depletion deduction on oil and gas income thereafter
attributable to such Units, if the percentage depletion deduction would exceed
cost depletion. However, no Unit holders were eligible to claim percentage
depletion deductions for 1990 or any subsequent year because cost depletion has
exceeded percentage depletion.
If a taxpayer disposes of any "section 1254 property" (certain oil, gas,
geothermal or other mineral property), and if the adjusted basis of such
property includes adjustments for deductions for depletion under section 611 of
the Internal Revenue Code (the "Code"), the taxpayer generally must recapture
the amount deducted for depletion in ordinary income (to the extent of gain
realized on the disposition of the property). This depletion recapture rule
applies to any disposition of property that was placed in service by the
taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1
through 1.1254-6 of the United States Treasury regulations govern dispositions
of property after March 13, 1995. The Service will likely take the position that
a Unit holder who purchases a Unit subsequent to December 31, 1986 must
recapture depletion upon the disposition of that Unit.
In order to facilitate creation of the Trust and to avoid the
administrative expense and inconvenience of daily reporting to Unit holders by
the Trustee, the conveyances by Sabine Corporation of the Royalty Properties
located in five of the six states provided for the execution of an escrow
agreement by Sabine Corporation and InterFirst (the initial trustee of the
Trust), in its capacities as trustee of the Trust and as escrow agent. The
conveyances by Sabine Corporation of the Royalty Properties located in Louisiana
provided for the execution of a substantially identical escrow agreement by
Sabine Corporation and Hibernia National Bank in New Orleans, in the capacities
of escrow agent and of trustee of Sabine Louisiana Royalty Trust.
Pursuant to the terms of the escrow agreements and the conveyances of the
Royalty Properties, the proceeds of production from the Royalty Properties for
each calendar month, and interest thereon, are collected by the escrow agents
and are paid to and received by the Trust only on the next Monthly Record Date.
The escrow agents have agreed to endeavor to assure that they incur and pay
expenses and fees for each calendar month only on the next Monthly Record Date.
The Trust Agreement also provides that the Trustee is to endeavor to assure that
income of the Trust will be accrued and received and expenses of the Trust will
be incurred and paid only on each Monthly Record Date.
Assuming that the escrow arrangement is recognized for federal income tax
purposes and that the Trustee and the escrow agents are able to control the
timing of income and expenses, as stated above, cash and accrual basis Unit
holders should be treated as realizing income only on each Monthly Record Date.
The Trustee and the escrow agents may not be able to cause third party expenses
to be incurred on each Monthly Record Date in all instances. Cash basis Unit
holders, however, should be treated as having paid all expenses and fees only
when such expenses and fees are actually paid. Even if the escrow arrangement is
recognized for federal income tax purposes, however, accrual basis Unit holders
might be considered to have accrued expenses when such expenses are incurred
rather than on each Monthly Record Date when paid.
No ruling was requested from the Service with respect to the effect of the
escrow arrangement. Due to the absence of direct authority and the factual
nature of the characterization of the relationship among the escrow agent,
Pacific (USA) and the Trust, no opinion has been expressed by legal counsel with
respect to the tax consequences of the escrow arrangement. In the absence of the
escrow arrangement, the Unit holders would be deemed to receive or accrue income
from production from the Royalty Properties (and
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interest income) on a daily basis, in accordance with their method of
accounting, as the proceeds from production and interest thereon were received
or accrued by the Trust. If the escrow arrangement is recognized, the income
from the Royalty Properties for a calendar month and interest income thereon
will be taxed to the holder of the Unit on the next Monthly Record Date without
regard to the ownership of the Unit prior to that date. The Trustee is treating
the escrow arrangement as effective for tax purposes and has furnished tax
information to Unit holders on that basis.
The Service might take the position that the escrow arrangement should be
ignored for tax purposes. In such case, the Trustee could be required to report
the proceeds from production and interest income thereon to the Unit holders on
a daily basis resulting in a substantial increase in the administrative expense
of the Trust. In the event of a transfer of a Unit, the income and the depletion
deduction attributable to the Royalty Properties for the period up to the date
of transfer would be allocated to the transferor, and the income and depletion
deduction attributable to the Royalty Properties on and after the date of
transfer would be allocated to the transferee, even though the transferee was
the holder of the Unit on the next Monthly Record Date and, therefore, would be
entitled to the monthly income distribution. Thus, if the escrow arrangement is
not recognized, a mismatching of such income and deduction could occur between a
transferor and a transferee upon the transfer of a Unit.
Unit holders of record on each Monthly Record Date are entitled to receive
monthly distributions. See "Description of Units -- Distributions of Net Income"
above. The terms of the escrow agreements and the Trust Agreement, as described
above, seek to assure that taxable income attributable to such distributions
will be reported by the Unit holder who receives such distributions, assuming
that such holder is the holder of record on the Monthly Record Date. In certain
circumstances, however, a Unit holder may be required to report taxable income
attributable to his or her Units but the Unit holder will not receive the
distribution attributable to such income. For example, if the Trustee
establishes a reserve or borrows money to satisfy debts and liabilities of the
Trust, income used to establish such reserve or to repay such loan will be
reported by the Unit holder, even though such income is not distributed to the
Unit holder.
Interest and royalty income attributable to ownership of Units and any gain
on the sale thereof are considered portfolio income, and not income from a
"passive activity," and therefore generally may not be offset by losses from any
passive activities.
Individuals may deduct "miscellaneous itemized deductions" (including, in
general, investment expenses) only to the extent that such expenses exceed two
percent of the individual's adjusted gross income. Although the Trustee believes
that no portion of a Unit holder's share of administrative expenses of the Trust
is subject to the floor, it is possible that the Service could take such a
position.
The foregoing summary is not exhaustive, and many other provisions of the
federal tax laws may affect individual Unit holders. Each Unit holder should
consult his or her personal tax adviser with respect to the effects of his or
her ownership of Units on his or her personal tax situation.
STATE LAW AND TAX CONSIDERATIONS
The following is intended as a brief summary of certain information
regarding state income taxes and other state law matters affecting the Trust and
the Unit holders. Unit holders are urged to consult their own legal and tax
advisers with respect to these matters.
Texas. Texas does not impose an income tax. Therefore, no part of the
income produced by the Trust is subject to an income tax in Texas. However,
corporations and limited liability companies doing business in Texas are subject
to the Texas franchise tax, which includes a calculation based upon the
company's taxable income for federal income tax purposes (or comparable amounts,
in the case of limited liability companies). It is currently unclear whether the
ownership of Units would be sufficient to subject a corporate Unit holder who is
not otherwise doing business in Texas to the franchise tax. Under certain
circumstances, Texas inheritance tax may be applicable to property in Texas
(including intangible personal property such as the Units) of both resident and
nonresident decedents.
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Louisiana. Units held by residents of Louisiana, to the extent that they
represent a proportionate share of mineral royalties from mineral interests
located in Louisiana, are subject to Louisiana inheritance and other taxes and
probate, community property, forced heirship and other rules. Units held of
record by a person who was not domiciled in Louisiana at the date of death
generally are not subject to Louisiana inheritance taxes or probate, community
property or forced heirship rules, and Units transferred inter vivos by
non-domiciliaries of Louisiana generally are not subject to Louisiana gift tax.
Income of the Units attributable to interests located in Louisiana will, subject
to applicable minimum filing requirements, be subject to Louisiana income tax,
and the Trustee is required to file with Louisiana a return reflecting the
income of the Trust attributable to mineral interests located in Louisiana.
Florida, Mississippi, New Mexico and Oklahoma. Florida imposes an income
tax on resident and nonresident corporations but not individuals. Mississippi,
New Mexico and Oklahoma each impose an income tax applicable to both resident
and nonresident individuals and corporations which will be applicable to royalty
income allocable to a Unit holder from properties located within that state.
Although the Trust may be required to file information returns with taxing
authorities in those states and provide copies of such returns to the Unit
holders, the Trust should be considered a grantor trust for state income tax
purposes and the Royalty Properties that are located in such states should be
considered economic interests in minerals for state income tax purposes.
Generally, the state income tax in these states is computed as a percentage
of taxable income attributable to the particular state. Furthermore, even though
there are variances from state to state, taxable income for state purposes is
often computed in a manner similar to the computation of taxable income for
federal income tax purposes. Some of these states give credit for taxes paid by
their residents on income from sources in other states. In certain of these
states, a Unit holder is required to file a state income tax return if income is
attributable to the Unit holder even though no tax is owed.
REGULATION AND PRICES
REGULATION
General
Exploration for and production and sale of oil and gas are extensively
regulated at the national, state and local levels. Oil and gas development and
production activities are subject to various state laws and regulations (and
orders of regulatory bodies pursuant thereto) governing a wide variety of
matters, including allowable rates of production, marketing, pricing, prevention
of waste, and pollution and protection of the environment. These laws,
regulations and orders may restrict the rate of oil and gas production below the
rate that would otherwise exist in the absence of such laws, regulations and
orders.
Laws affecting the oil and gas industry are under constant review for
amendment or expansion, frequently increasing the regulatory burden. Numerous
governmental departments and agencies are authorized by statute to issue and
have issued rules and regulations binding on the oil and gas industry which
often are difficult and costly to comply with and which carry substantial
penalties for the failure to comply.
Natural Gas
On January 1, 1993, pursuant to the Natural Gas Wellhead Decontrol Act of
1989, the maximum lawful prices prescribed for the sale of natural gas under the
Natural Gas Policy Act of 1978 were eliminated. Consequently, prices for the
sale of natural gas, like the sale of other commodities, are governed by the
marketplace and the provisions of applicable gas sales contracts.
The Federal Energy Regulatory Commission ("FERC") has taken significant
steps in the implementation of a policy to restructure the natural gas pipeline
industry to promote full competition in the sales of natural gas, so that all
natural gas suppliers, including pipelines, can compete equally for sales
customers. This policy, set forth principally in Order 636, issued on April 8,
1992, and its progeny, is being
8
<PAGE> 11
implemented largely through restructuring proceedings for each pipeline. These
factors make the future effect of that order upon the natural gas markets
uncertain.
There are many other statutes, rules, regulations and orders that affect
the pricing or transportation of natural gas. Some of the provisions are and
will be subject to court or administrative review. Consequently, uncertainty as
to the ultimate impact of these regulatory provisions on the prices and
production of natural gas from the Royalty Properties is expected to continue
for the foreseeable future.
Environmental Regulation
General. Activities on the Royalty Properties are subject to existing
federal, state and local laws (including case law), rules and regulations
governing health, safety, environmental quality and pollution control. It is
anticipated that, absent the occurrence of an extraordinary event, compliance
with existing federal, state and local laws, rules and regulations regulating
health, safety, the release of materials into the environment or otherwise
relating to the protection of the environment will not have a material adverse
effect upon the Trust or Unit holders. The Trustee cannot predict what effect
additional regulation or legislation, enforcement policies thereunder, and
claims for damages to property, employees, other persons and the environment
resulting from operations on the Royalty Properties could have on the Trust or
Unit holders. Even if the Trust were not directly liable for costs or expenses
related to these matters, increased costs of compliance could result in wells
being plugged and abandoned earlier in their productive lives, with a resulting
loss of reserves and revenues to the Trust.
Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "superfund" law, imposes liability,
regardless of fault or the legality of the original conduct, on certain classes
of persons that contributed to the release of a "hazardous substance" into the
environment. These persons include the current or previous owner and operator of
a site and companies that disposed, or arranged for the disposal, of the
hazardous substance found at a site. CERCLA also authorizes the Environmental
Protection Agency and, in some cases, private parties to take actions in
response to threats to the public health or the environment and to seek recovery
from such responsible classes of persons of the costs of such action. In the
course of operations, the working interest owner and/or the operator of Royalty
Properties may have generated and may generate wastes that may fall within
CERCLA's definition of "hazardous substances". The operator of the Royalty
Properties or the working interest owners may be responsible under CERCLA for
all or part of the costs to clean up sites at which such substances have been
disposed. Although the Trust is not the operator of any Royalty Properties, or
the owner of any working interest, its ownership of royalty interests could
cause it to be responsible for all or part of such costs to the extent CERCLA
imposes responsibility on parties as "owners".
Solid and Hazardous Waste. The Royalty Properties have produced oil and/or
gas for many years, and, although the Trust has no knowledge of the procedures
followed by the operators of the Royalty Properties in this regard, hydrocarbons
or other solid or hazardous wastes may have been disposed or released on or
under the Royalty Properties by the current or previous operators. Federal,
state and local laws applicable to oil- and gas-related wastes and properties
have become increasingly more stringent. Under these laws, removal or
remediation of previously disposed wastes or property contamination could be
required.
PRICES
Oil
Crude oil prices are affected by a variety of factors. Since domestic crude
oil price controls were lifted in 1981, the principal factors influencing the
prices received by producers of domestic crude oil have been the pricing and
production of the members of the Organization of Petroleum Exporting Countries
("OPEC").
The Trust's average per barrel oil price increased from $12.72 in 1998 to
$15.50 in 1999. The Trustee believes that the higher average price per barrel of
crude oil realized by the Trust in 1999 can be attributed to a worldwide
increase in oil prices that continued throughout 1999.
9
<PAGE> 12
Natural Gas
Substantial competition in the natural gas marketplace continued in 1999.
Competition with alternative fuels and excess gas supplies persists. Natural gas
prices, which once were determined largely by governmental regulations, are now
being generally governed by the marketplace. The average price received by the
Trust in 1999 on natural gas volumes sold of $1.88 per Mcf represented a
decrease from the $1.96 per Mcf received in 1998, due largely to a relatively
mild winter and declining gas prices in the latter part of 1999.
FERC is the federal agency responsible for implementing regulations
governing the natural gas industry. The current policy of FERC is designed to
promote increased competition among gas industry participants. Accordingly,
Order 636 and various other orders have been proposed and implemented to
encourage nondiscriminatory open-access transportation by interstate pipelines,
to provide for the release of natural gas dedicated to long-term contracts but
not required by pipelines to meet near-term system supply needs, and to provide
for the unbundling of pipeline services so that such services may also be
furnished by nonpipeline suppliers on a competitive basis. Certain of these
orders have been or will be challenged in the courts, and no prediction can be
made regarding the future impact on the industry of FERC's current or proposed
regulations.
ITEM 2. PROPERTIES.
The assets of the Registrant consist principally of the Royalty Properties,
which constitute interests in gross production of oil, gas and other minerals
free of the costs of production. The Royalty Properties consist of royalty and
mineral interests, including landowner's royalties, overriding royalty
interests, minerals (other than executive rights, bonuses and delay rentals),
production payments and any other similar, nonparticipatory interest, in certain
producing and proved undeveloped oil and gas properties located in Florida,
Louisiana, Mississippi, New Mexico, Oklahoma and Texas. These properties are
represented by approximately 5,400 tracts of land. Approximately 2,950 of the
tracts are in Oklahoma, 1,750 in Texas, 330 in Louisiana, 200 in New Mexico, 150
in Mississippi and 12 in Florida.
The following table summarizes total developed and proved undeveloped
acreage represented by the Royalty Properties at December 31, 1999.
<TABLE>
<CAPTION>
MINERAL AND ROYALTY
---------------------------
STATE GROSS ACRES NET ACRES
- ----- ----------- ---------
<S> <C> <C>
Florida.................................... 5,448 697
Louisiana.................................. 244,391 23,682
Mississippi................................ 75,489 9,713
New Mexico................................. 112,294 9,141
Oklahoma................................... 381,538 67,558
Texas...................................... 1,273,132 105,760
--------- -------
Total............................ 2,092,292 216,551
========= =======
</TABLE>
Detailed information concerning the number of wells on royalty properties
is not generally available to the owner of royalty interests. Consequently, the
Registrant does not have an accurate count of the number of wells located on the
Royalty Properties and cannot readily obtain such information.
TITLE
The conveyances of the Royalty Properties to the Trust covered the royalty
and mineral properties located in the six states that were vested in Sabine
Corporation on the effective date of the conveyances and that were subject to
existing oil, gas and other mineral leases other than properties specifically
excluded in the conveyances. Since Sabine Corporation may not have had available
to it as a royalty owner information as to whether specific lands in which it
owned a royalty interest were subject to an existing lease, minimal
10
<PAGE> 13
amounts of nonproducing royalty properties may also have been conveyed to the
Trust. Sabine Corporation did not warrant title to the Royalty Properties either
expressly or by implication.
RESERVES
The Registrant has obtained from DeGolyer and MacNaughton, independent
petroleum engineering consultants, a study of the proved oil and gas reserves
attributable as of January 1, 2000 to the Royalty Properties. The following
letter report summarizes such reserve study and sets forth information as to the
assumptions, qualifications, procedures and other matters relating to such
reserve study. See Note 8 of the Notes to Financial Statements in Item 8 hereof
for additional information regarding the proved oil and gas reserves of the
Trust.
11
<PAGE> 14
DEGOLYER AND MACNAUGHTON
ONE ENERGY SQUARE
DALLAS, TEXAS 75206
March 3, 2000
Bank of America, N.A.
P.O. Box 830650
Dallas, Texas 75283-0650
Gentlemen:
Pursuant to your request, we have prepared estimates of the extent and
value of the proved crude oil, condensate, natural gas liquids (NGL), and
natural gas reserves, as of January 1, 2000, of certain royalty interests owned
by Sabine Royalty Trust (the Trust). The properties appraised consist of
royalties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma, and
Texas. Bank of America, N.A. (Bank of America) acts as trustee of the Trust.
Information used in the preparation of this report was obtained from Bank
of America, from records on file with the appropriate regulatory agencies, and
from public sources. During this investigation, we consulted freely with
officers and employees of Bank of America and were given access to such
accounts, records, geological and engineering reports, and other data as were
desired for examination. In the preparation of this report we have relied,
without independent verification, upon information furnished by Bank of America
with respect to property interests owned by the Trust, production from such
properties, current prices for production, agreements relating to current and
future operations and sale of production, and various other information and data
that were accepted as represented. It was not considered necessary to make a
field examination of the physical condition and operation of the properties in
which the Trust owns interests.
Our reserves estimates are based on a detailed study of the properties and
were prepared by the use of standard geological and engineering methods
generally accepted by the petroleum industry. The method or combination of
methods used in the analysis of each reservoir was tempered by experience with
similar reservoirs, consideration of the stage of development, and the quality
and completeness of basic data. The Trust owns several thousand royalty
interests. In view of the limited information available to a royalty owner and
the small reserves attributable to many of these interests, certain of them
representing approximately 46 percent of the total reserves of the properties
included herein were summarized by state or field and worked in total rather
than being appraised individually. Historical records of net production and
revenue and experience with similar properties were used in analyzing these
properties.
Reserves estimated in this report are expressed as gross and net reserves.
Gross reserves are defined as the total estimated petroleum to be produced from
these properties after December 31, 1999. Net reserves are defined as that
portion of the gross reserves attributable to the interests owned by the Trust
after deducting royalties and other interests held by others. Gas volumes shown
herein are sales gas volumes and are expressed at a temperature base of 60
degrees Fahrenheit and at the legal pressure bases of the states in which the
interests are located. Sales gas is defined as the total gas to be produced from
the reservoirs, measured at the point of delivery, after reduction for fuel
usage, flare, and shrinkage resulting from field separations and processing.
Condensate reserves estimated herein are those to be obtained from normal
separator recovery. NGL reserves are those attributed to the leasehold interests
according to processing agreements.
Petroleum reserves included in this report are classified as proved and are
judged to be economically producible in future years from known reservoirs under
existing economic and operating conditions and assuming continuation of current
regulatory practices using conventional production methods and equipment. In the
analyses of production-decline curves, reserves were estimated only to the limit
of economic rates of production under existing economic and operating conditions
using prices and costs as of the date the estimate is made, including
consideration of changes in existing prices provided only by
12
<PAGE> 15
contractual arrangements but not including escalations based upon future
conditions. The petroleum reserves are classified as follows:
Proved -- Reserves that have been proved to a high degree of certainty
by analysis of the producing history of a reservoir and/or by volumetric
analysis of adequate geological and engineering data. Commercial
productivity has been established by actual production, successful testing,
or in certain cases by favorable core analyses and electrical-log
interpretation when the producing characteristics of the formation are
known from nearby fields. Volumetrically, the structure, areal extent,
volume, and characteristics of the reservoir are well defined by a
reasonable interpretation of adequate subsurface well control and by known
continuity of hydrocarbon-saturated material above known fluid contacts, if
any, or above the lowest known structural occurrence of hydrocarbons.
Developed -- Reserves that are recoverable from existing wells with
current operating methods and expenses.
Developed reserves include both producing and nonproducing reserves.
Estimates of producing reserves assume recovery by existing wells producing
from present completion intervals with normal operating methods and
expenses. Developed nonproducing reserves are in reservoirs behind the
casing or at minor depths below the producing zone and are considered
proved by production from other wells in the field, by successful
drill-stem tests, or by core analyses from the particular zones.
Nonproducing reserves require only moderate expense to be brought into
production.
Undeveloped -- Reserves that are recoverable from additional wells yet
to be drilled.
Undeveloped reserves are those considered proved for production by
reasonable geological interpretation of adequate subsurface control in
reservoirs that are producing or proved by other wells but are not
recoverable from existing wells. This classification of reserves requires
drilling of additional wells, major deepening of existing wells, or
installation of enhanced recovery or other facilities.
Reserves recoverable by enhanced recovery methods, such as injection of
external fluids to provide energy not inherent in the reservoirs, may be
classified as proved developed or proved undeveloped reserves depending upon the
extent to which such enhanced recovery methods are in operation. These reserves
are considered to be proved only in cases where a successful fluid-injection
program is in operation, a pilot program indicates successful fluid injection,
or information is available concerning the successful application of such
methods in the same reservoir and it is reasonably certain that the program will
be implemented.
The development status shown herein represents the status applicable on
January 1, 2000. In the preparation of this study, data available from wells
drilled on the appraised properties through December 31, 1999, were used in
estimating gross ultimate recovery. When applicable, gross production estimated
to January 1, 2000, was deducted from gross ultimate recovery to arrive at the
estimates of gross reserves as of January 1, 2000. In some fields, this required
that the production rates be estimated for up to 6 months since production data
were available only through June 1999.
Future oil, condensate, NGL, and gas producing rates estimated for this
report are based on production rates considering the most recent figures
available. The rates used for future production are rates that we feel are
within the capacity of the well or reservoir to produce. This information has
been considered in arriving at the rates projected.
13
<PAGE> 16
Net proved reserves, as of January 1, 2000, attributable to the Trust from
the properties appraised are estimated in barrels (bbl) or thousands of cubic
feet (Mcf) as follows:
<TABLE>
<CAPTION>
PROVED DEVELOPED PROVED UNDEVELOPED
RESERVES RESERVES
------------------------ ---------------------
OIL, OIL,
CONDENSATE, SALES CONDENSATE, SALES
AND NGL GAS AND NGL GAS
STATE (BBL) (MCF) (BBL) (MCF)
- ----- ----------- ---------- ----------- -------
<S> <C> <C> <C> <C>
Florida.............................. 89,032 13,953 0 0
Louisiana............................ 62,641 1,718,409 0 0
Mississippi.......................... 94,578 3,694,182 0 0
New Mexico........................... 279,474 2,365,620 0 0
Oklahoma............................. 551,111 9,437,031 0 0
Texas................................ 4,661,411 19,436,128 12,684 126,845
--------- ---------- ------ -------
Total...................... 5,738,247 36,665,323 12,684 126,845
</TABLE>
Revenue values in this report are expressed in terms of estimated future
net revenue and present worth of future net revenue. These values are based on
the continuation of prices in effect on December 31, 1999. Future gross revenue
is defined as that revenue to be realized from the production and sale of the
estimated net reserves. Future net revenue is calculated by deducting estimated
severance and ad valorem taxes from the future gross revenue. Present worth of
future net revenue is calculated by discounting the future net revenue at the
arbitrary rate of 10 percent per year compounded monthly over the expected
period of realization.
Revenue values in this report were estimated using the initial prices and
costs provided by Bank of America. Future prices were estimated using guidelines
established by the Securities and Exchange Commission (SEC) and the Financial
Accounting Standards Board (FASB). The initial and future prices used in this
report are based on receipts by the Trust in December 1999, and Bank of America
has represented that the prices used herein are those that the Trust could
reasonably expect to receive. The assumptions used for estimating future prices
and costs are as follows:
Oil, Condensate, Natural Gas Liquids, and Natural Gas Prices
Oil, condensate, natural gas liquids, and natural gas prices were furnished
by Bank of America. These prices are based on receipts by the Trust in December
1999 and are held constant for the lives of the properties.
A projection of the estimated future net revenue from the properties
appraised, as of January 1, 2000, based on the aforementioned assumptions
concerning prices and costs is summarized as follows:
<TABLE>
<CAPTION>
YEAR FUTURE NET
ENDING REVENUE
DECEMBER 31, ($)
- ------------ -----------
<S> <C>
2000............................................... 23,132,160
2001............................................... 19,534,884
2002............................................... 16,821,563
-----------
Subtotal........................................... 59,488,607
Remaining.......................................... 136,785,278
-----------
Total.................................... 196,273,885
</TABLE>
The present worth of future net revenue, as of January 1, 2000, is
estimated to be $105,512,400.
Estimates of oil, condensate, NGL, and gas reserves and future net revenue
should be regarded only as estimates that may change as further production
history and additional information become available. Not only are such reserves
and revenue estimates based on that information which is currently available,
but such
14
<PAGE> 17
estimates are also subject to the uncertainties inherent in the application of
judgmental factors in interpreting such information.
In our opinion, the information relating to estimated proved reserves,
estimated future net revenue from proved reserves, and present worth of
estimated future net revenue from proved reserves of oil, condensate, natural
gas liquids, and gas contained in this report has been prepared in accordance
with Paragraphs 10-13, 15 and 30(a)-(b) of Statement of Financial Accounting
Standards No. 69 (November 1982) of the FASB and Rules 4-10(a) (1)-(13) of
Regulation S-X and Rule 302(b) of Regulation S-K of the SEC; provided, however,
(i) certain estimated data have not been provided with respect to changes in
reserves information, (ii) future income tax expenses have not been taken into
account in estimating the future net revenue and present worth values set forth
herein, and (iii) at the request of Bank of America and because of the limited
availability of data, proved reserves, future net revenue therefrom, and the
present worth thereof for certain royalty interests accounting for approximately
46 percent of the Trust's total proved reserves have been estimated in the
aggregate by state or field rather than on a property-by-property basis using
net production and revenue data and our general knowledge of producing
characteristics in the geographic areas in which such interests are located.
To the extent the above-enumerated rules, regulations, and statements
require determinations of an accounting or legal nature or information beyond
the scope of our report, we are necessarily unable to express an opinion as to
whether the above-described information is in accordance therewith or sufficient
therefor.
Submitted,
DeGOLYER and MacNAUGHTON
15
<PAGE> 18
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production and timing of
development. The preceding reserve data in the letter regarding the study
represent estimates only and should not be construed to be exact. The estimated
present worth of future net revenue amounts shown by the study should not be
construed as the current fair market value of the estimated oil and gas reserves
since a market value determination would include many additional factors.
Reserve estimates may be adjusted from time to time as more accurate
information on the volume or recoverability of existing reserves becomes
available. Actual reserve quantities do not change, however, except through
production. The Trust continues to own only the Royalty Properties that were
initially transferred to the Trust at the time of its creation and is prohibited
by the Trust Agreement from acquiring additional oil and gas interests.
The future net revenue shown by the study has not been reduced for
administrative costs and expenses of the Trust in future years. The costs and
expenses of the Trust may increase in future years, depending on the amount of
income from the Royalty Properties, increases in the Trustee's and escrow
agents' fees and expenses, accounting, engineering, legal and other professional
fees, and other factors. It is expected that the costs and expenses of the Trust
in 2000 will be approximately $1,500,000.
The present worth of future net revenue of the Trust's proved developed
reserves increased from $71,413,818 at January 1, 1999 to $105,512,400. This
increase resulted primarily from an increase in the oil and gas prices used in
the calculation of such amount, from $10.82 per barrel of oil and $1.8508 per
Mcf of gas at January 1, 1999 to $21.24 per barrel of oil and $2.4961 per Mcf of
gas at January 1, 2000. Subsequent to year end, the price of oil continued to
increase. As of March 15, 2000, published oil prices were approximately $30.73
per barrel. The use of such price, as compared to $21.24 per barrel, which was
used to calculate the above information, would result in a larger standardized
measure of discounted future net cash flows.
The volatile nature of the world energy markets makes it difficult to
estimate future prices of oil and gas. The prices obtained for oil and gas
depend upon numerous factors, including the domestic and foreign supply of oil
and gas and the price of foreign imports, market demand, the price and
availability of alternative fuels, the availability of pipeline capacity and the
effect of governmental regulations.
ITEM 3. LEGAL PROCEEDINGS.
There are no material pending legal proceedings to which the Registrant is
a party or of which any of its property is the subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
16
<PAGE> 19
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Units are listed and traded on the New York Stock Exchange under the
symbol "SBR." The following table sets forth the high and low sales prices for
the Units and the aggregate amount of cash distributions paid by the Trust
during the periods indicated.
<TABLE>
<CAPTION>
SALES PRICE
-------------------- DISTRIBUTIONS
HIGH LOW PER UNIT
------- ------- -------------
<S> <C> <C> <C>
1999
First Quarter..................................... $14.500 $12.063 $.28353
Second Quarter.................................... 15.375 13.063 .34070
Third Quarter..................................... 14.938 13.875 .41681
Fourth Quarter.................................... 15.125 13.125 .36592
1998
First Quarter..................................... $15.188 $13.000 $.52526
Second Quarter.................................... 16.563 14.000 .43088
Third Quarter..................................... 16.500 14.375 .38152
Fourth Quarter.................................... 15.750 11.750 .31600
</TABLE>
At March 15, 2000, there were 14,579,345 Units outstanding and
approximately 3,170 Unit holders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
YEARS ENDED
DECEMBER 31 1999 1998 1997 1996 1995
- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Royalty Income....... $23,042,432 $24,075,260 $25,688,064 $22,173,492 $16,088,936
Distributable
Income............. 21,725,812 22,941,409 24,499,892 20,972,323 14,829,839
Distributable Income
per Unit........... 1.49 1.57 1.68 1.44 1.02
Total Assets at Year
End................ 5,474,918 4,766,116 6,936,828 6,868,761 6,598,427
Distributions per
Unit............... 1.41 1.65 1.64 1.37 1.03
</TABLE>
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
Sabine Royalty Trust (the "Trust") makes monthly distributions to its Unit
holders of the excess of the preceding month's revenues received over expenses
incurred. Upon receipt, royalty income is invested in short-term investments
until its subsequent distribution. In accordance with the Trust Agreement, the
Trust's only long-term assets consist of royalty interests in producing oil and
gas properties. Although the Trust is permitted to borrow funds if necessary to
continue its operations, borrowings are not anticipated in the foreseeable
future.
Distributable income consists of royalty income plus interest income plus
any decrease in cash reserves established by the Trustee less general and
administrative expenses of the Trust less any increase in cash reserves
established by the Trustee. The Trust's royalty income represents payments
received during a particular time period for oil and gas production from the
Trust's properties. Because of various factors which influence the timing of the
Trust's receipt of payments, royalty income for any particular time period will
usually include payments for oil and gas produced in prior periods. The price
and volume figures that follow represent the volumes and prices for which the
Trust received payment during 1999.
17
<PAGE> 20
Net royalty income during 1999 decreased approximately $1,033,000, or 4.3
percent, compared to 1998 net royalty income, which had decreased approximately
$1,613,000, or 6.3 percent, from 1997 net royalty income.
Revenues generated by sales of oil and gas decreased in 1999 from 1998 as a
result of lower gas prices and lower oil and gas volumes offset somewhat by an
increase in oil prices. Gas volumes decreased from 9,119,288 thousand cubic feet
("Mcf") in 1998 to 8,709,114 Mcf in 1999, after increasing from 7,154,510 in
1997. The average price per Mcf of gas received by the Trust decreased from
$1.96 in 1998 to $1.88, after decreasing from $2.45 in 1997. The Trustee
believes that normal market forces and a relatively mild winter during the
fourth quarter of 1999 resulted in the lower gas prices.
Oil volumes sold decreased to 581,236 barrels in 1999 from 629,011 barrels
in 1998, having increased from 614,976 barrels in 1997. The effect of this
volume decrease was negated by a significant increase in the average price per
barrel received by the Trust to $15.50 in 1999 from $12.72 in 1998 which had
decreased from $18.77 in 1997. The effect of volatile world market conditions
contributed to the increase in prices throughout 1999.
Interest income decreased to $118,000 in 1999 from $163,000 in 1998. Lower
interest rates and less funds available contributed to this decrease. General
and administrative expenses increased to $1,435,000 in 1999 compared to
$1,297,000 in 1998 due to a claim settlement of $49,500 in the first quarter of
1999 and increases of escrow agent's fees and trustee fees of approximately
$69,200 and $23,000, respectively. General and administrative costs declined in
1998 to $1,297,000 compared to $1,350,000 in 1997 in most part due to
non-recurring costs associated with the retention and storage of historical
trust documents incurred in 1997.
YEAR 2000 ISSUE
Many existing computer programs were designed to use only two digits to
identify a year in the date field. These programs were designed and developed
without considering the impact of the change in the century. If not corrected,
many computer applications could have failed or created erroneous results by or
at the Year 2000. The Year 2000 issue affected virtually all companies and
organizations. If a company or organization did not successfully address its
Year 2000 issues, it may have faced material adverse consequences. The Trustee
identified the General Ledger/Accounts Payable System as its primary system that
was vulnerable to the Year 2000 issue. The Trust selected a system that had been
warranted to be Year 2000 compliant and completed the installation of the new
system at the beginning of 1998. The cost of the system was approximately
$6,000. The Trustee incurred very little other costs to identify, assess,
remediate and test the Trust's systems for Year 2000 compliance.
The Trustee identified and assessed other information technology ("IT")
systems used in connection with the Trust as well as other systems, for Year
2000 compliance. Non-IT systems were generally more difficult to assess because
they often contain embedded technology that may have been subject to Year 2000
problems. The total cost of the Trustee's Year 2000 efforts was approximately
$10,000 (including the $6,000 referred to above), all of which was incurred and
paid by the third quarter of 1999. Of this amount, the Trustee paid $4,000 for
identification and assessment of affected systems.
The Trustee additionally identified those vendors it believed to have an
impact on its day-to-day operations if their operations were interrupted as a
result of Year 2000 problems. The Trustee developed a questionnaire regarding
the vendor's Year 2000 status. These vendors, consisting primarily of energy
companies, were contacted to determine their Year 2000 status and substantially
all responded to have addressed and resolved the issue within their companies.
All of the above precautions were put into place by the end of the third
quarter in 1999. The Trust suffered no consequences as a result of the Year 2000
issue.
18
<PAGE> 21
FORWARD-LOOKING STATEMENTS
This Annual Report includes "forward-looking statements" within the meaning
of Section 21E of the Securities Exchange Act of 1934, which are intended to be
covered by the safe harbor created thereby. All statements other than statements
of historical fact included in this Annual Report are forward-looking
statements. Such statements include, without limitation, certain reserve
information and other statements contained in Item 2, "Properties", and certain
statements regarding the Trust's financial position, industry conditions and
other matters contained in this Item 7. Although the Trustee believes that the
expectations reflected in such forward-looking statements are reasonable, such
expectations are subject to numerous risks and uncertainties and the Trustee can
give no assurance that they will prove correct. There are many factors, none of
which is within the Trustee's control, that may cause such expectations not to
be realized, including, among other things, factors identified in this Annual
Report affecting oil and gas prices and the recoverability of reserves, general
economic conditions, actions and policies of petroleum-producing nations and
other changes in the domestic and international energy markets.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Trust is a passive entity and other than the Trust's ability to
periodically borrow money as necessary to pay expenses, liabilities and
obligations of the Trust that cannot be paid out of cash held by the Trust, the
Trust is prohibited from engaging in borrowing transactions. The amount of any
such borrowings is unlikely to be material to the Trust. The Trust periodically
holds short term investments acquired with funds held by the Trust pending
distribution to Unitholders and funds held in reserve for the payment of Trust
expenses and liabilities. Because of the short-term nature of these borrowings
and investments and certain limitations upon the types of such investments which
may be held by the Trust, the Trustee believes that the Trust is not subject to
any material interest rate risk. The Trust does not engage in transactions in
foreign currencies which could expose the Trust or Unitholders to any foreign
currency related market risk. The Trust invests in no derivative financial
instruments and has no foreign operations or long-term debt instruments.
19
<PAGE> 22
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEPENDENT AUDITORS' REPORT
UNIT HOLDERS OF SABINE ROYALTY TRUST AND BANK OF AMERICA, N.A., TRUSTEE:
We have audited the statements of assets, liabilities and trust corpus of
Sabine Royalty Trust (the "Trust") as of December 31, 1999 and 1998, and the
related statements of distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 1999. These financial
statements are the responsibility of the Trustee. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with 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 described in Note 2 to the financial statements, these statements were
prepared on a modified cash basis of accounting, which is a comprehensive basis
of accounting other than generally accepted accounting principles.
In our opinion, such financial statements present fairly, in all material
respects, the assets, liabilities and trust corpus of the Trust at December 31,
1999 and 1998, and the distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 1999, on the basis of
accounting described in Note 2.
/s/ DELOITTE & TOUCHE LLP
Dallas, Texas
March 14, 2000
20
<PAGE> 23
FINANCIAL STATEMENTS
SABINE ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1999 1998
---------- ----------
<S> <C> <C>
ASSETS
Cash and short-term investments............................. $3,225,597 $2,132,011
Royalty interests in oil and gas properties less accumulated
amortization of $20,145,864 (1999) and $19,761,080
(1998).................................................... 2,249,321 2,634,105
---------- ----------
Total....................................................... $5,474,918 $4,766,116
========== ==========
LIABILITIES AND TRUST CORPUS
Trust expenses payable...................................... $ 227,531 $ 140,756
Other payables (Note 4)..................................... 93,189 299,215
Trust corpus (14,579,345 units of beneficial interest
authorized and outstanding)............................... 5,154,198 4,326,145
---------- ----------
Total....................................................... $5,474,918 $4,766,116
========== ==========
</TABLE>
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Royalty income................................... $23,042,432 $24,075,260 $25,688,064
Interest income.................................. 118,209 162,884 162,059
----------- ----------- -----------
Total............................................ 23,160,641 24,238,144 25,850,123
General and administrative expenses (Note 6)..... 1,434,829 1,296,735 1,350,231
----------- ----------- -----------
Distributable income............................. $21,725,812 $22,941,409 $24,449,892
=========== =========== ===========
Distributable income per unit (Basic and Assuming
Dilution) (14,579,345 units) (Note 1).......... $ 1.49 $ 1.57 $ 1.68
=========== =========== ===========
Distributions per unit (Note 3).................. $ 1.41 $ 1.65 $ 1.64
=========== =========== ===========
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
Trust corpus, beginning of year................ $ 4,326,145 $ 5,940,107 $ 5,885,543
Amortization of royalty interests.............. (384,784) (445,165) (467,768)
Distributable income........................... 21,725,812 22,941,409 24,499,892
Distributions to unit holders (Note 3)......... (20,512,975) (24,110,206) (23,977,560)
------------ ------------ ------------
Trust corpus, end of year...................... $ 5,154,198 $ 4,326,145 $ 5,940,107
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
21
<PAGE> 24
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
1. TRUST ORGANIZATION AND PROVISIONS
Sabine Royalty Trust (the "Trust") was established by the Sabine
Corporation Royalty Trust Agreement (the "Trust Agreement"), made and entered
into effective as of December 31, 1982, to receive a distribution from Sabine
Corporation ("Sabine") of royalty and mineral interests, including landowner's
royalties, overriding royalty interests, minerals (other than executive rights,
bonuses and delay rentals), production payments and any other similar,
nonparticipatory interest, in certain producing and proved undeveloped oil and
gas properties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma
and Texas (the "Royalties").
Certificates evidencing units of beneficial interest (the "Units") in the
Trust were mailed on December 31, 1982 to Sabine's shareholders of record on
December 23, 1982, on the basis of one Unit for each share of Sabine's
outstanding common stock. In May 1988, Sabine was acquired by Pacific
Enterprises, a California corporation. Through a series of mergers, Sabine was
merged into Pacific Enterprises Oil Company (USA) ("Pacific (USA)"), a
California corporation and a wholly owned subsidiary of Pacific Enterprises,
effective January 1, 1990. This acquisition and the subsequent mergers had no
effect on the Units. Pacific (USA), as successor to Sabine, has assumed by
operation of law all of Sabine's rights and obligations with respect to the
Trust. The Units are listed and traded on the New York Stock Exchange.
In connection with the transfer of the Royalties to the Trust upon its
formation, Sabine had reserved to itself all executive rights, including rights
to execute leases and to receive bonuses and delay rentals. In January 1993,
Pacific (USA) completed the sale of substantially all its producing oil and gas
assets to a third party. The sale did not include executive rights relating to
the Royalties, and Pacific (USA)'s ownership of such rights was not affected by
the sale.
Bank of America, N.A. (the "Trustee"), acts as trustee of the Trust. The
terms of the Trust Agreement provide, among other things, that:
- The Trust shall not engage in any business or commercial activity of any
kind or acquire assets other than those initially transferred to the
Trust.
- The Trustee may not sell all or any part of its assets unless approved by
the holders of a majority of the outstanding Units in which case the sale
must be for cash and the proceeds, after satisfying all existing
liabilities, promptly distributed to Unit holders.
- The Trustee may establish a cash reserve for the payment of any liability
that is contingent or uncertain in amount or that otherwise is not
currently due and payable.
- The Trustee will use reasonable efforts to cause the Trust and the Unit
holders to recognize income and expenses on monthly record dates.
- The Trustee is authorized to borrow funds to pay liabilities of the Trust
provided that such borrowings are repaid in full before any further
distributions are made to Unit holders.
- The Trustee will make monthly cash distributions to Unit holders of
record on the monthly record date (see Note 3).
Because of the passive nature of the Trust and the restrictions and
limitations on the powers and activities of the Trustee contained in the Trust
Agreement, the Trustee does not consider any of the officers and employees of
the Trustee to be "officers" or "executive officers" of the Trust as such terms
are defined under applicable rules and regulations adopted under the Securities
Exchange Act of 1934.
The proceeds of production from the Royalties are receivable from hundreds
of separate payors. In order to facilitate creation of the Trust and to avoid
the administrative expense and inconvenience of daily reporting to Unit holders,
the conveyances by Sabine of the Royalties located in five of the six states
22
<PAGE> 25
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
provided for the execution of an escrow agreement by Sabine and the initial
trustee of the Trust, in its capacities as trustee of the Trust and as escrow
agent. The conveyances by Sabine of the Royalties located in Louisiana provided
for the execution of a substantially identical escrow agreement by Sabine and a
Louisiana bank in the capacities of escrow agent and of trustee under the name
of Sabine Louisiana Royalty Trust. Sabine Louisiana Royalty Trust, the sole
beneficiary of which is the Trust, was established in order to avoid uncertainty
under Louisiana law as to the legality of the Trustee's holding record title to
the Royalties located in Louisiana.
Pursuant to the terms of the escrow agreements and the conveyances of the
properties by Sabine, the proceeds of production from the Royalties for each
calendar month, and interest thereon, are collected by the escrow agents and are
paid to and received by the Trust only on the next monthly record date. The
escrow agents have agreed to endeavor to assure that they incur and pay expenses
and fees for each calendar month only on the next monthly record date. The Trust
Agreement also provides that the Trustee is to endeavor to assure that income of
the Trust will be accrued and received and expenses of the Trust will be
incurred and paid only on each monthly record date. Assuming that the escrow
agreement is recognized for Federal income tax purposes and that the Trustee and
the escrow agents are able to control the timing of income and expenses, as
stated above, cash and accrual basis Unit holders should be treated as realizing
income only on each monthly record date. The Trustee is treating the escrow
agreement as effective for tax purposes. However, for financial reporting
purposes, royalty and interest income are recorded in the calendar month in
which the amounts are received by either the escrow agents or the Trust.
Distributable income as determined for financial reporting purposes for a
given quarter will not usually equal the sum of distributions made during that
quarter. Distributable income for a given quarter will approximate the sum of
the distributions made during the last two months of such quarter and the first
month of the next quarter.
2. ACCOUNTING POLICIES
BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on the following basis
and are not intended to present financial position and results of operations in
conformity with generally accepted accounting principles:
- Royalty income, net of severance and ad valorem taxes, and interest
income are recognized in the month in which amounts are received by the
Trust (see Note 1).
- Trust expenses, consisting principally of routine general and
administrative costs, include payments made during the accounting period.
Expenses are accrued to the extent of amounts that become payable on the
next monthly record date following the end of the accounting period.
Reserves for liabilities that are contingent or uncertain in amount may
also be established if considered necessary.
- Royalties that are producing properties are amortized using the
unit-of-production method. This amortization is shown as a reduction of
Trust corpus.
- Distributions to Unit holders are recognized when declared by the Trustee
(see Note 3).
The financial statements of the Trust differ from financial statements
prepared in conformity with generally accepted accounting principles because of
the following:
- Royalty income is recognized in the month received rather than in the
month of production.
- Expenses other than those expected to be paid on the following monthly
record date are not accrued.
23
<PAGE> 26
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
- Amortization of the Royalties is shown as a reduction to Trust corpus and
not as a charge to operating results.
- Reserves may be established for contingencies that would not be recorded
under generally accepted accounting principles.
USE OF ESTIMATES
The preparation of financial statements in conformity with the basis of
accounting described above requires management to make estimates and assumptions
that affect reported amounts of certain assets, liabilities, revenues and
expenses as of and for the reporting periods. Actual results may differ from
such estimates.
IMPAIRMENT
Trust management routinely reviews its royalty interests in oil and gas
properties for impairment whenever events or circumstances indicate that the
carrying amount of an asset may not be recoverable. If an impairment event
occurs and it is determined that the carrying value of the Trust's royalty
interests may not be recoverable, an impairment will be recognized as measured
by the amount by which the carrying amount of the royalty interests exceeds the
fair value of these assets, which would likely be measured by discounting
projected cash flows.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board ("FASB") issued, in June 1998,
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities," which establishes accounting and
reporting standards for derivative instruments. SFAS No. 133 is effective for
the Trust January 1, 2001. The Trustee does not believe the adoption of SFAS No.
133 will have a significant impact on the financial statements of the Trust.
DISTRIBUTABLE INCOME PER UNIT
Basic earnings per Unit is computed by dividing net income by the weighted
average Units outstanding. Earnings per Unit assuming dilution is computed by
dividing net income by the weighted average number of Units and equivalent Units
outstanding. The Trust had no equivalent Units outstanding for any period
presented. Basic and assuming dilution distributable income per Unit are the
same.
FEDERAL INCOME TAXES
The Internal Revenue Service has ruled that the Trust would be classified
as a grantor trust for Federal income tax purposes and therefore is not subject
to taxation at the trust level. The Unit holders are considered, for Federal
income tax purposes, to own the Trust's income and principal as though no trust
were in existence. Accordingly, no provision for Federal income tax expense has
been made in these financial statements. The income of the Trust will be deemed
to have been received or accrued by each Unit holder at the time such income is
received or accrued by the Trust.
3. DISTRIBUTIONS TO UNIT HOLDERS
The amount to be distributed to Unit holders ("Monthly Income Amount") is
determined on a monthly basis. The Monthly Income Amount is an amount equal to
the sum of cash received by the Trust during a monthly period (the period
commencing on the day after a monthly record date and continuing through and
including the next succeeding monthly record date) attributable to the
Royalties, any reduction in cash reserves and any other cash receipts of the
Trust, including interest, reduced by the sum of
24
<PAGE> 27
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
liabilities paid and any increase in cash reserves. Unit holders of record as of
the monthly record date (the 15th day of each calendar month except in limited
circumstances) are entitled to have distributed to them the calculated Monthly
Income Amount for such month on or before 10 business days after the monthly
record date. The Monthly Income Amount per Unit is declared by the Trust no
later than 10 days prior to the monthly record date.
The cash received by the Trust from purchasers of the Trust's oil and gas
production consists of gross sales of production less applicable severance
taxes.
4. OTHER PAYABLES
Other payables consist of the following:
<TABLE>
<CAPTION>
DECEMBER 31, 1999 1998
- ------------ ------- --------
<S> <C> <C>
Funds due to payors for royalties erroneously forwarded to
the Trust................................................. $ 9,262 $ 19
Royalty receipts in suspense pending verification of
ownership interest or title............................... $83,927 $299,196
------- --------
Total............................................. $93,189 $299,215
======= ========
</TABLE>
The Trustee believes that these amounts represent an ordinary operating
condition of the Trust and that they will be paid or released in the normal
course of business.
5. SUBSEQUENT EVENTS
Subsequent to December 31, 1999, the Trust declared the following
distributions:
<TABLE>
<CAPTION>
MONTHLY RECORD DATE PAYMENT DATE DISTRIBUTION PER UNIT
- ------------------- ------------ ---------------------
<S> <C> <C>
January 18, 2000 January 31, 2000 $.20049
February 15, 2000 February 29, 2000 $.18787
March 15, 2000 March 29, 2000 $.14055
</TABLE>
The Trust received a cash settlement of approximately $413,000 subsequent
to December 31, 1999. This settlement was for price adjustments related to prior
years relating to a limited number of producing oil and gas wells.
6. TRUSTEE'S FEES AND EXPENSES
Fees and expenses for the years ended December 31, associated with the
Trustee's services for the Trust pursuant to the Trust Agreement, were as
follows:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Trustee's fee................................... $219,408 $196,546 $203,962
Escrow agent's fee.............................. 658,234 589,647 611,895
-------- -------- --------
Total fees and expenses......................... $877,642 $786,193 $815,857
======== ======== ========
</TABLE>
25
<PAGE> 28
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
7. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table sets forth the royalty income, distributable income and
distributable income per Unit of the Trust for each quarter in the years ended
December 31, 1999 and 1998 (in thousands, except per Unit amounts):
<TABLE>
<CAPTION>
CALENDAR ROYALTY DISTRIBUTABLE DISTRIBUTABLE
QUARTER INCOME INCOME INCOME PER UNIT
- -------- ------- ------------- ---------------
<S> <C> <C> <C>
1999
First.................................... $ 5,163 $ 4,812 $0.33
Second................................... 5,078 4,765 0.33
Third.................................... 6,253 5,982 0.41
Fourth................................... 6,548 6,167 0.42
------- ------- -----
$23,042 $21,726 $1.49
======= ======= =====
1998
First.................................... $ 7,766 $ 7,445 $0.51
Second................................... 5,688 5,386 0.37
Third.................................... 5,919 5,679 0.39
Fourth................................... 4,702 4,431 0.30
------- ------- -----
$24,075 $22,941 $1.57
======= ======= =====
</TABLE>
8. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
RESERVE QUANTITIES
Information regarding estimates of the proved oil and gas reserves
attributable to the Trust are based on reports prepared by DeGolyer and
MacNaughton, independent petroleum engineering consultants. Estimates were
prepared in accordance with Statement of Financial Accounting Standards No. 69
and the guidelines established by the Securities and Exchange Commission.
Oil and gas reserve quantities (all located in the United States) are
estimates based on information available at the time of their preparation. Such
estimates are subject to change as additional information becomes available.
Reserves actually recovered, and the timing of the production of those reserves,
may differ substantially from original estimates. The following schedule
presents changes in the Trust's total proved reserves (in thousands):
<TABLE>
<CAPTION>
OIL GAS
(BARRELS) (MCF)
--------- ------
<S> <C> <C>
January 1, 1997............................................. 5,975 33,700
Revisions of previous estimates........................... 820 7,592
Production................................................ (612) (6,927)
----- ------
December 31, 1997........................................... 6,183 34,365
Revisions of previous estimates........................... 656 13,427
Production................................................ (633) (8,738)
----- ------
December 31, 1998........................................... 6,206 39,054
Revisions of previous estimates........................... 176 6,698
Production................................................ (631) (8,960)
----- ------
December 31, 1999........................................... 5,751 36,792
===== ======
</TABLE>
26
<PAGE> 29
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Estimated quantities of proved developed reserves of oil and gas as of the
dates indicated were as follows (in thousands):
<TABLE>
<CAPTION>
OIL GAS
(BARRELS) (MCF)
--------- ------
<S> <C> <C>
Proved developed reserves:
January 1, 1997........................................... 5,885 33,572
December 31, 1997......................................... 6,171 34,288
December 31, 1998......................................... 6,206 39,054
December 31, 1999......................................... 5,738 36,665
</TABLE>
DISCLOSURE OF A STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The following is a summary of a standardized measure (in thousands) of
discounted future net cash flows related to the Trust's total proved oil and gas
reserve quantities. Information presented is based upon a valuation of proved
reserves by using discounted cash flows based upon current (at year end) oil and
gas prices ($21.24 per bbl and $2.50 per Mcf, respectively) and severance and ad
valorem taxes, if any, and economic conditions, discounted at the required rate
of 10 percent. As the Trust is not subject to taxation at the trust level, no
provision for income taxes has been made in the following disclosure. The impact
of changes in current prices on reserves could vary significantly from year to
year. Accordingly, the information presented below should not be viewed as an
estimate of the fair market value of the Trust's oil and gas properties nor
should it be viewed as indicative of any trends.
<TABLE>
<CAPTION>
DECEMBER 31, 1999 1998 1997
- ------------ -------- -------- --------
<S> <C> <C> <C>
Future net cash inflows......................... $196,274 $128,469 $187,364
Discount of future net cash flows at 10%........ (90,762) (57,055) (82,452)
-------- -------- --------
Standardized measure of discounted future net
cash flows.................................... $105,512 $ 71,414 $104,912
======== ======== ========
</TABLE>
The change in the standardized measure of discounted future net cash flows
for the years ended December 31, 1999, 1998 and 1997 is as follows (in
thousands):
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Standardized measure of discounted future net
cash flows, January 1......................... $ 71,414 $104,912 $ 94,627
Royalty income, net of severance and ad valorem
taxes......................................... (23,042) (24,075) (25,688)
Changes in prices, net of related costs......... 40,434 (35,640) 3,479
Revisions of previous estimates and other....... 9,565 15,726 23,031
Accretion of discount........................... 7,141 10,491 9,463
-------- -------- --------
Standardized measure of discounted future net
cash flows, December 31,...................... $105,512 $ 71,414 $104,912
======== ======== ========
</TABLE>
Subsequent to year end, the price of oil increased significantly. As of
March 15, 2000, published oil prices were approximately $30.73 per barrel. The
use of such price, as compared to $21.24 per barrel, which was used to calculate
the above information, would result in a larger standardized measure of
discounted future net cash flows.
27
<PAGE> 30
REPORT OF INDEPENDENT ACCOUNTANTS
To the Trustee on Behalf of Unit Holders of Sabine Royalty Trust:
We have audited the accompanying Statements of Fees and Expenses (as
defined in Exhibit C to the Sabine Royalty Trust Agreement) paid by Sabine
Royalty Trust to Bank of America, N.A., (the "Trustee") as trustee and escrow
agent, for the years ended December 31, 1999, 1998 and 1997. These statements
are the responsibility of the Trustee's management. Our responsibility is to
express an opinion on these statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audits to obtain reasonable assurance about whether the Statements of Fees
and Expenses are free of material misstatement. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the Statements
of Fees and Expenses. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall statement presentation. We believe that our audits provide a reasonable
basis for our opinion.
As described in Note 3 to the statements, these statements were prepared on
a modified cash basis of accounting, which is a comprehensive basis of
accounting other than generally accepted accounting principles.
In our opinion, the Statements of Fees and Expenses referred to above
present fairly, in all material respects, the fees and expenses paid by Sabine
Royalty Trust to Bank of America, N.A., as trustee and escrow agent, for the
years ended December 31, 1999, 1998 and 1997, on the basis of accounting
referred to above.
/s/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Charlotte, North Carolina
March 14, 2000
28
<PAGE> 31
STATEMENTS OF FEES AND EXPENSES
PAID BY SABINE ROYALTY TRUST TO
BANK OF AMERICA, N.A., AS
TRUSTEE AND ESCROW AGENT, FOR EACH OF THE THREE
YEARS IN THE PERIOD ENDED DECEMBER 31, 1999
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Trustee's fee......................................... $219,408 $196,546 $203,962
Escrow agent's fee.................................... 658,234 589,647 611,895
-------- -------- --------
Total fees and expenses paid to Bank of America,
N.A................................................. $877,642 $786,193 $815,857
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these statements.
NOTES
1. Sabine Royalty Trust (the "Trust") is an express trust formed under the
laws of Texas by the Sabine Corporation Royalty Trust Agreement (the "Trust
Agreement") made and entered into effective as of December 31, 1982, between
Sabine Corporation ("Sabine"), as trustor, and Bank of America, N.A. (the
"Bank"), as successor trustee (the "Trustee"). Contemporaneously with the
execution of the Trust Agreement, Sabine, the Trustee and the predecessor of the
Bank, as escrow agent (the "Escrow Agent"), entered into an escrow agreement
which establishes an escrow (the "Escrow"). Prior to distribution of units of
beneficial interest (the "Units") in the Trust to Sabine's shareholders, Sabine
transferred to the Trust royalty and mineral interests, including landowner's
royalties, overriding royalty interests, minerals (other than executive rights,
bonuses and delay rentals), production payments and other similar,
non-participatory interests, in certain producing and proved undeveloped oil and
gas properties in six states (the "Royalty Properties").
In May 1988, Sabine was acquired by Pacific Enterprise ("Pacific"), a
California corporation. Through a series of mergers, Sabine was merged into
Pacific Enterprises Oil Company (USA) ("Pacific (USA)"), a California
corporation and a wholly owned subsidiary of Pacific, effective January 1, 1990.
This acquisition and the subsequent mergers had no effect on the Units. Pacific
(USA), as successor to Sabine, has assumed by operation of law all of Sabine's
rights and obligations with respect to the Trust.
The compensation agreement under the Trust Agreement provides for a "cost
plus" fee payable to the Bank for all services rendered in its capacities as
Trustee and as Escrow Agent. Generally, the fees payable to the Bank are
calculated by dividing the expenses incurred by the Bank, as Trustee and as
Escrow Agent, solely for services provided by the Bank in the administration of
the Trust and the Escrow by seven-tenths (0.7). Professional and other
noncontributing (out-of-pocket) expenses incurred by the Bank, as Trustee or as
Escrow Agent, as the case may be, in the performance of its duties in the
foregoing capacities are charged to the Trust or the Escrow, as the case may be,
at cost. These expenses do not contribute to the fees payable to the Bank
described above. Annually, the Trustee must estimate Trust and Escrow expenses
contributing to the fee for the forthcoming year and publish this amount in the
Trust's first quarterly report to Unit holders. The Trustee can be penalized by
forfeiture of reimbursement for part of its expenses if such expenses exceed the
estimate. The Trustee also can earn a bonus by administering the Trust for total
costs that are lower than the estimate. The Bank did not earn a bonus for 1999,
1998 or 1997; therefore, none will be taken in 2000 and none was taken in 1999
or 1998.
2. Escrow Agent's fees and Trustee's fees consist of a profit margin plus
all fully allocated costs incurred by the Bank, as Trustee and as Escrow Agent,
in performing administrative services to the Trust as specified in the Trust
Agreement. Allocated costs do not include any professional and related expenses
to third parties.
All costs incurred by the Bank in its capacities as Trustee and as Escrow
Agent are accumulated in one account. Fees based thereon are allocated between
the Trustee function and the Escrow Agent function
29
<PAGE> 32
according to the actual administrative services rendered by the Bank in each
capacity. Any determinations by the Bank as to the allocation of the fee between
the Trustee and the Escrow Agent are conclusive and binding on the Unit holders
and Pacific (USA), but in no event does the Bank's allocation affect the
aggregate fee payable to the Bank.
3. The Statements of Fees and Expenses are prepared on a modified cash
basis, which is a comprehensive basis of accounting other than generally
accepted accounting principles. Trust expenses include payments made during the
accounting period. Expenses are accrued to the extent of amounts that become
payable on the next monthly record date following the end of the accounting
period. These statements differ from statements prepared in conformity with
generally accepted accounting principles because expenses other than those
expected to be paid on the following monthly record date are not accrued.
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.
The Registrant has no directors or executive officers. The Trustee is a
corporate trustee which may be removed, with or without cause, by the
affirmative vote at a meeting duly called and held of the holders of a majority
of the Units represented at the meeting.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) Security Ownership of Certain Beneficial Owners. As of March 15, 2000
there were no Unit holders known to the Trustee to be beneficial owners of more
that 5% of the outstanding Units.
(b) Security Ownership of Management. The Trust has no directors or
executive officers. Bank of America, N.A., the Trustee, held as of March 10,
2000 an aggregate of 182,061 Units in various fiduciary capacities, and it had
sole voting and investment power with respect to none of such Units.
(c) Changes in Control. The Trustee knows of no arrangements the operation
of which may at a subsequent date result in a change in control of the
Registrant.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Not applicable.
30
<PAGE> 33
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements (included in Item 8 of this report)
Independent Auditors' report
Statements of Assets, Liabilities and Trust Corpus at December 31, 1999 and
1998
Statements of Distributable Income for Each of the Three Years in the
Period Ended December 31, 1999
Statements of Changes in Trust Corpus for Each of the Three Years in the
Period Ended December 31, 1999
Notes to Financial Statements
Report dated March 1, 2000 of the Trustee containing interim tax
information for each of the 12 months in the year ending December 31, 1999.
2. Financial Statement Schedules
Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required information is
included in the financial statements and notes thereto.
3. Exhibits
<TABLE>
<C> <S>
(4)(a)* -- Sabine Corporation Royalty Trust Agreement effective as
of December 31, 1982, by and between Sabine Corporation
and InterFirst Bank Dallas, N.A., as trustee.
(b)* -- Sabine Corporation Louisiana Royalty Trust Agreement
effective as of December 31, 1982, by and between Sabine
Corporation and Hibernia National Bank in New Orleans, as
trustee, and joined in by InterFirst Bank Dallas, N.A.,
as trustee.
(23) -- Consent of DeGolyer and MacNaughton.
(27)** -- Financial Data Schedule.
</TABLE>
- ---------------
* Exhibits 4(a) and 4(b) are incorporated herein by reference to Exhibits 4(a)
and 4(b), respectively, of the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1993.
** Included with EDGAR version of Form 10-K only.
(b) Reports on Form 8-K. No reports on Form 8-K were filed by the
Registrant during the last quarter of the period covered by this report.
31
<PAGE> 34
SIGNATURES
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.
SABINE ROYALTY TRUST
BY: BANK OF AMERICA, N.A.
(as successor), Trustee
By: /s/ RON E. HOOPER
----------------------------------
Ron E. Hooper
Vice-President
Date: March 23, 2000
(THE REGISTRANT HAS NO DIRECTORS OR EXECUTIVE OFFICERS.)
32
<PAGE> 35
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
(4)(a)* -- Sabine Corporation Royalty Trust Agreement effective as
of December 31, 1982, by and between Sabine Corporation
and InterFirst Bank Dallas, N.A., as trustee.
(b)* -- Sabine Corporation Louisiana Royalty Trust Agreement
effective as of December 31, 1982, by and between Sabine
Corporation and Hibernia National Bank in New Orleans, as
trustee, and joined in by InterFirst Bank Dallas, N.A.,
as trustee.
(23) -- Consent of DeGolyer and MacNaughton.
(27)** -- Financial Data Schedule.
</TABLE>
- ---------------
* Exhibits 4(a) and 4(b) are incorporated herein by reference to Exhibits 4(a)
and 4(b), respectively, of the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1993.
** Included with EDGAR version of Form 10-K only.
<PAGE> 1
EXHIBIT 23
[DEGOLYER AND MACNAUGHTON LETTERHEAD]
March 21, 2000
Sabine Royalty Trust
Bank of America, N.A.
Bank of America Plaza - 17th Floor
901 Main Street
Dallas, Texas 75202
Gentlemen:
We hereby consent to the inclusion of our letter report dated March 3,
2000, concerning the reserves and revenue, as of January 1, 2000, of certain
royalty interests owned by Sabine Royalty Trust in the Annual Report on Form
10-K for the year ended December 31, 1999, of the Sabine Royalty Trust to be
filed with the Securities and Exchange Commission. We also consent to the
references to our firm under "Properties -- Reserves" in Item 2 and under
"Supplemental Oil and Gas Information (Unaudited)-- Reserve Quantities" in Item
8 of the Form 10-K.
Very truly yours,
/s/ DEGOLYER AND MACNAUGHTON
Degolyer and MacNaughton
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 3,225,597
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 3,225,597
<PP&E> 22,395,185
<DEPRECIATION> 20,145,864
<TOTAL-ASSETS> 5,474,918
<CURRENT-LIABILITIES> 320,720
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 5,154,198
<TOTAL-LIABILITY-AND-EQUITY> 5,474,918
<SALES> 23,042,432
<TOTAL-REVENUES> 23,160,641
<CGS> 0
<TOTAL-COSTS> 1,434,829
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 21,725,812
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 21,725,812
<EPS-BASIC> 1.49
<EPS-DILUTED> 1.49
</TABLE>
