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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, 2002
[ ] 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)
<Table>
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)
</Table>
Registrant's telephone number, including area code: (214) 209-2400
Securities registered pursuant to Section 12(b) of the Act:
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<Caption>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -------------------
Units of Beneficial Interest New York Stock Exchange
</Table>
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of 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]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Securities and Exchange Act of
1934). Yes [X] No [ ]
The aggregate market value of units of beneficial interest of the
registrant (based on the closing sale price on the New York Stock Exchange as of
the last business day of its most recently completed second fiscal quarter) held
by non-affiliates of the registrant was approximately $331 million.
At March 19, 2003, there were 14,579,345 units of beneficial interest
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
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TABLE OF CONTENTS
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PAGE
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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................................... 5
Liability of Unit Holders................................. 5
Possible Divestiture of Units............................. 5
Federal Taxation............................................ 6
State Tax Considerations.................................... 8
Regulation and Prices....................................... 9
Regulation................................................ 9
Prices.................................................... 10
Item 2. Properties.................................................. 11
Title....................................................... 11
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......................................... 16
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........................................................ 21
Item 8. Financial Statements and Supplementary Data................. 22
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 34
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 34
Item 11. Executive Compensation...................................... 34
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 34
Item 13. Certain Relationships and Related Transactions.............. 34
Item 14. Controls and Procedures..................................... 34
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 35
</Table>
i
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.
The Trust created an Internet website in early 2003, and as a result,
during 2002, did not offer website access to its annual reports on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to
such reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Exchange Act; however, such reports will now be made available at
http://www.sbr-sabineroyalty.com as soon as reasonably practicable after such
information is electronically filed with or furnished to the SEC.
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 has historically been held by a separate trust formed
under the laws of Louisiana, the sole beneficiary of which was the Trust. Sabine
Louisiana Royalty Trust was a passive entity, with the trustee thereof, Hibernia
National Bank in New Orleans, having only such powers as were 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. On December 31, 2001, Bank of America, N.A. assumed the
duties as Trustee of the Sabine Louisiana Royalty Trust, since Louisiana law now
permits an out-of-state bank to act in this capacity. 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 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".
1
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.
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 2002 were $1,638,044 of which, pursuant to the terms of the Trust
Agreement, $284,172 was paid to Bank of America, as Trustee, and $852,520 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
2
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 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". Legislation is
pending in the 2003 Texas legislature that would repeal the "rule against
perpetuities". Future Trust reports will provide information regarding the
status of this legislation and the effect, if any, on the Trust.
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.
3
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 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 19, 2003, 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
4
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".
Mellon Investor Services LLC 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 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
5
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.
FEDERAL TAXATION
THE TAX CONSEQUENCES TO A UNIT HOLDER OF THE OWNERSHIP AND SALE OF UNITS
WILL DEPEND IN PART ON THE UNIT HOLDER'S TAX CIRCUMSTANCES. EACH UNIT HOLDER
SHOULD THEREFORE CONSULT THE UNIT HOLDER'S TAX ADVISOR ABOUT THE FEDERAL, STATE
AND LOCAL TAX CONSEQUENCES TO THE UNIT HOLDER OF THE OWNERSHIP OF UNITS.
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. A Unit holder generally would not have claimed percentage
depletion deductions for 1990 or any subsequent year because cost depletion
generally 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") (discussed above), 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 5 of the 6 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
6
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 arrangements are 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 arrangements
are 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 arrangements. Due to the absence of direct authority and the factual
nature of the characterization of the relationship among the escrow agents,
Pacific (USA) and the Trust, no opinion has been expressed by legal counsel with
respect to the tax consequences of the escrow arrangements. In the absence of
the escrow arrangements, the Unit holders would be deemed to receive or accrue
income from production from the Royalty Properties (and 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 arrangements are 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 arrangements as effective
for tax purposes and furnishes tax information to Unit holders on that basis.
The Service might take the position that the escrow arrangements should be
ignored for federal 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 expenses 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 arrangements are 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.
7
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," to the extent a Unit holder acquires and holds Units as an
investment and did not acquire them in the ordinary course of a trade or
business. Therefore, interest and royalty income attributable to ownership of
Units 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 2
percent of the individual's adjusted gross income. Although there are exceptions
to the 2 percent limitation, authority suggests that no exceptions apply to
expenses passed through from a grantor trust, like the Trust.
The foregoing summary is not exhaustive and does not purport to be
complete. 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 TAX CONSIDERATIONS
THE FOLLOWING IS INTENDED AS A BRIEF SUMMARY OF CERTAIN INFORMATION
REGARDING STATE INCOME TAXES AND OTHER STATE TAX MATTERS AFFECTING THE TRUST AND
THE UNIT HOLDERS. UNIT HOLDERS SHOULD CONSULT THE UNIT HOLDER'S TAX ADVISOR
REGARDING STATE INCOME TAX FILING AND COMPLIANCE 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 unlikely that the ownership
of Units would be sufficient to subject a corporate Unit holder to the franchise
tax who is not otherwise doing business in Texas and who does not have control
over the Trust or the trustee of the trust. 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.
Louisiana. 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. Additionally, both Louisiana resident and non-resident
Unit holders may be subject to the Louisiana personal, corporate and/or
franchise tax as certain income and expenses from the Trust are from sources
within 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.
Florida, Mississippi, New Mexico and Oklahoma. Florida does not have a
personal income tax. Florida imposes an income tax on resident and nonresident
corporations (except for S corporations not subject to the built-in gains tax or
passive investment income tax), which will be applicable to royalty income
allocable to a corporate Unit holder from properties located within Florida.
Mississippi, New Mexico and Oklahoma each impose an income tax applicable to
both resident and nonresident individuals and corporations (subject to certain
exceptions for S corporations), which will be applicable to royalty income
allocable to a Unit holder from properties located within these states. 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
8
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 all of the aforementioned 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 state law, regulation and orders of
regulatory bodies pursuant thereto. These laws may govern a wide variety of
matters, including allowable rates of production, transportation, marketing,
pricing, prevention of waste, and pollution and protection of the environment.
These laws, regulations and orders have in the past and may again 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 and the distribution of its
products 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
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"), which principally
is responsible for regulating interstate transportation and the sale of natural
gas, 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 has been implemented
largely through restructuring proceedings and is subject to continuing
refinement. The effects of this policy are now presumably fully reflected in the
natural gas markets. The current policy of FERC continues 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 and to provide for the
unbundling of pipeline services so that such services may also be furnished by
nonpipeline suppliers on a competitive basis.
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.
9
PRICES
Oil
The Trust's average per barrel oil price decreased from $23.88 in 2001 to
$21.82 in 2002. The Trustee believes that the sluggish economy continued the
weak demand for fuel by such industries as the travel and transportation
industries and led to the decrease in the price of oil. This decrease was
somewhat offset in the last half of the year by slightly increasing oil prices
due primarily to international instability. The price of domestic oil in major
part is set by OPEC. Consequently, crude oil market prices are not predictable
or completely subject to normal free market forces.
Natural Gas
Natural gas prices, which once were determined largely by governmental
regulations, are now being governed by the marketplace. Substantial competition
in the natural gas marketplace continues. In addition, competition with
alternative fuels persists. The average price received by the Trust in 2002 on
natural gas volumes sold of $2.70 per Mcf represented a decrease from the $4.53
per Mcf received in 2001, due largely to a relatively mild winter during the
first quarter of 2002 and the continuing sluggish economy. This price decrease
was somewhat offset in the last half of the year by increasing gas prices due
primarily to international instability.
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.
10
Under these laws, removal or remediation of previously disposed wastes or
property contamination could be required.
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, 2002.
<Table>
<Caption>
MINERAL AND ROYALTY
---------------------------
STATE GROSS ACRES NET ACRES
- ----- ----------- ---------
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 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, 2003 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
DEGOLYER AND MACNAUGHTON
4925 GREENVILLE AVENUE, SUITE 400
ONE ENERGY SQUARE
DALLAS, TEXAS 75206
March 14, 2003
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, 2003, 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. Additionally, this information includes data supplied by
Petroleum Information/Dwights LLC; Copyright 2002 Petroleum Information/Dwights
LLC. 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 47 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, 2002. 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
12
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 estimating prices
provided only by 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, 2003. In the preparation of this study, data available from wells
drilled on the appraised properties through December 31, 2002, were used in
estimating gross ultimate recovery. When applicable, gross production estimated
to January 1, 2003, was deducted from gross ultimate recovery to arrive at the
estimates of gross reserves as of January 1, 2003. In some fields, this required
that the production rates be estimated for up to 6 months since production data
were available only through June 2002.
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
Net proved reserves, as of January 1, 2003, 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
(BBL) (MCF) (BBL) (MCF)
STATE ---------------- ----------- ---------------- ------
Florida........................ 103,067 18,375 0 0
Louisiana...................... 102,611 866,627 0 0
Mississippi.................... 98,987 2,885,552 16,252 25,241
New Mexico..................... 407,369 3,057,227 0 0
Oklahoma....................... 581,475 11,172,359 0 30,662
Texas.......................... 3,773,250 18,238,618 2,278 37,252
--------- ----------- ------ ------
Total........................ 5,066,769 36,238,758 18,530 93,155
</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, 2002. Future gross revenue
is defined as that revenue to he 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 adjusted to prices on January 1, 2003, based on receipts by the Trust
in December 2002. 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 based on
receipts by the Trust in December 2002 were furnished by Bank of America. These
prices are adjusted to posted prices as of January 1, 2003, 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, 2003, based on the aforementioned assumptions
concerning prices and costs is summarized as follows:
<Table>
<Caption>
YEAR FUTURE NET
ENDING REVENUE
DECEMBER 31 ($)
- ----------- ------------
2003........................................................ 27,762,873
2004........................................................ 24,597,571
2005........................................................ 21,795,084
------------
Subtotal.................................................... 74,155,528
Remaining................................................... 196,356,998
------------
Total....................................................... 270,512,526
</Table>
The present worth of future net revenue, as of January 1, 2003, is
estimated to be $138,455,065.
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
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
47 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
---------------------
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 2003 will be approximately $1,850,000.
The present worth of future net revenue of the Trust's proved developed
reserves increased from $86,115,013 at January 1, 2002 to $138,455,065 at
January 1, 2003. This increase resulted primarily from an increase in the oil
and gas prices used in the calculation of such amount, from $17.43 per barrel of
oil and $2.32 per Mcf of gas at January 1, 2002 to $29.20 per barrel of oil and
$4.13 per Mcf of gas at January 1, 2003.
15
Subsequent to year end, the price of both oil and gas continued to
fluctuate, giving rise to a correlating adjustment of the respective
standardized measure of discounted future net cash flows. As of March 3, 2003,
published oil prices were approximately $35.88 per barrel, which compared to
$29.20 per barrel, used to calculate the above information, would result in a
larger standardized measure of discounted future net cash flows for oil. As of
March 3, 2003, published gas prices were approximately $8.81 per Mcf. The use of
such price, as compared to $4.13 per Mcf, which was used to calculate the above
information, would result in a larger standardized measure of discounted future
net cash flows for gas.
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, none of which is within the Trustee's control,
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, instability in oil-producing regions 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.
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
------- ------- -------------
2002
First Quarter..................................... $24.450 $21.100 $0.50792
Second Quarter.................................... 26.140 20.350 0.45452
Third Quarter..................................... 25.050 15.000 0.54615
Fourth Quarter.................................... 25.400 21.500 0.37024
2001
First Quarter..................................... $22.750 $17.650 $0.64406
Second Quarter.................................... 26.980 19.800 0.94135
Third Quarter..................................... 25.550 19.400 0.77238
Fourth Quarter.................................... 22.660 18.850 0.50284
</Table>
At March 5, 2003, there were 14,579,345 Units outstanding and approximately
2,615 Unit holders of record.
The Trust does not maintain any equity compensation plans.
16
ITEM 6. SELECTED FINANCIAL DATA.
<Table>
<Caption>
YEARS ENDED DECEMBER 31 2002 2001 2000 1999 1998
- ----------------------- ----------- ----------- ----------- ----------- -----------
Royalty Income............. $28,134,458 $44,222,701 $34,407,684 $23,042,432 $24,075,260
Distributable Income....... 26,539,751 42,805,378 33,122,044 21,725,813 22,941,409
Distributable Income per
Unit..................... 1.82 2.94 2.27 1.49 1.57
Total Assets at Year End... 5,391,280 5,855,378 5,239,610 5,474,918 4,766,116
Distributions per Unit..... 1.88 2.86 2.27 1.41 1.65
</Table>
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
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. Accordingly the Trust is dependent on its operations to generate excess
cash flows utilized in making distributions. These operating cash flows are
largely dependent on such factors as oil and gas prices and production volumes
which are influenced by many factors beyond the control of the Trust.
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 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 is primarily from purchasers of the Trust's
oil and gas production and consists of gross sales of production less applicable
severance taxes. In January, 2000, the Trust received a cash settlement of
approximately $413,000 relating to the price adjustments for prior years on a
limited number of producing oil and gas wells. In March, 2002, the Trust
received a cash settlement of approximately $828,000 relating to the
Multidistrict Litigation Docket no. 1206 ("MDL 1206"), a class action lawsuit,
filed against numerous companies (the "Defendants") that produce, sell and/or
purchase domestic crude oil. These claims were based upon methods used by the
Defendants to calculate payments to royalty owners. The complaint alleged that,
as a result of the price-fixing conspiracy among the Defendants, their payments
to class members have been placed upon per barrel values that were less than
competitive market values. The MDL 1206 complaint stated that the alleged
price-fixing conspiracy violated federal antitrust law. It also alleged certain
state law violations, including claims for breach of contract. This settlement
was included in the April 2002 distribution along with monies received in the
normal course of business.
RESULTS OF OPERATIONS
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
17
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 2001 and 2002.
Net royalty income during 2002 decreased approximately $16,088,000, or 36.4
percent, compared to 2001 net royalty income, which had increased approximately
$9,815,000, or 28.5 percent, from 2000 net royalty income.
Revenues generated by sales of oil and gas decreased in 2002 from 2001 as a
result of lower gas and oil prices. This decrease in price was exacerbated by
decreases in both natural gas and oil volumes. Gas volumes decreased from
7,701,397 thousand cubic feet ("Mcf") in 2001 to 6,691,473 Mcf in 2002 after
decreasing from 7,788,314 Mcf in 2000. The average price per Mcf of gas received
by the Trust decreased from $4.53 per Mcf in 2001 to $2.70 per Mcf in 2002,
after increasing from $2.85 per Mcf in 2000. The Trustee believes that normal
market forces, the relatively mild winter during the first quarter of 2002, and
the continuing sluggish economy resulted in the lower gas prices.
Oil volumes sold decreased to 537,534 barrels in 2002 from 573,354 barrels
in 2001, having decreased from 610,472 barrels in 2000. The effect of this
volume decrease was furthered by a decrease in the average price per barrel
received by the Trust to $21.82 in 2002 from $23.88 in 2001 and $23.86 in 2000.
The Trustee believes that the sluggish economy continued the weak demand for
fuel by such industries as the travel industry and led to the decrease in the
price of oil. This decrease was somewhat offset in the last half of the year by
slightly increasing oil prices due primarily to international instability.
Interest income decreased to $43,000 in 2002 from $205,000 in 2001, which
decreased from $240,000 in 2000. Changes in interest income are the result of
changes in interest rates and funds available for investment. General and
administrative expenses increased to $1,638,000 in 2002 compared to $1,622,000
in 2001 due to increases in the escrow agent fees and trustee fees services of
approximately $40,000 and $12,000, respectively. These increases were somewhat
offset by a decrease in the timing of payment of professional fees of
approximately $33,000. General and administrative expenses increased to
$1,622,000 in 2001 compared to $1,526,000 in 2000 due to increases in the
transfer agent fees and the timing of payment of professional fees of
approximately $19,000 and $21,000, respectively, as well as an increase of
approximately $11,000 in the New York Stock Exchange listing fee.
CONTRACTUAL OBLIGATIONS
<Table>
<Caption>
LESS THAN MORE THAN
CONTRACTUAL OBLIGATIONS TOTAL 1 YEAR 1-3 YEARS 3-5 YEARS 5 YEARS
- ----------------------- ----- --------- --------- --------- ---------
Long-Term Debt Obligations................... 0 0 0 0 0
Capital Lease Obligations.................... 0 0 0 0 0
Operating Lease Obligations.................. 0 0 0 0 0
Purchase Obligations......................... 0 0 0 0 0
Other Long-Term Liabilities Reflected on the
Trusts Balance Sheet....................... 0 0 0 0 0
---- ---- ---- ---- ----
Total........................................ 0 0 0 0 0
==== ==== ==== ==== ====
</Table>
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The Trust's financial statements reflect the selection and application of
accounting policies that require the Trust to make significant estimates and
assumptions. The following are some of the more critical judgement areas in the
application of accounting policies that currently affect the Trust's financial
condition and results of operations.
18
1. 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 accounting principles generally accepted in the United States of
America:
- 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.
- 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.
The financial statements of the Trust differ from financial statements
prepared in conformity with accounting principles generally accepted in the
United States of America 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.
- 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 accounting principles generally accepted in the United States of
America.
2. REVENUE RECOGNITION
Revenues from Royalty Interests are recognized in the period in which
amounts are received by the Trust. Royalty income received by the Trust in a
given calendar year will generally reflect the proceeds, on an entitlements
basis, from natural gas produced for the twelve-month period ended September
30th in that calendar year.
3. RESERVE DISCLOSURE
Independent petroleum engineers estimate the net proved reserves
attributable to the Royalty Interest. In accordance with Statement of Financial
Standards No. 69, "Disclosures About Oil and Gas Producing Activities",
estimates of future net revenues from proved reserves have been prepared using
year-end contractual gas prices and related costs. Numerous uncertainties are
inherent in estimating volumes and the value of proved reserves and in
projecting future production rates and the timing of development of non-
producing reserves. Such reserve estimates are subject to change as additional
information becomes available. The reserves actually recovered and the timing of
production may be substantially different from the reserve estimates.
4. CONTINGENCIES
Contingencies related to the Royalty Properties that are unfavorably
resolved would generally be reflected by the Trust as reductions to future
royalty income payments to the Trust with corresponding reductions to cash
distributions to Unit holders. The Trustee is aware of no such items as of
December 31, 2002.
19
NEW ACCOUNTING PRONOUNCEMENTS
SFAS No. 143, "Accounting for Asset Retirement Obligations" was issued in
June 2001, and will be adopted by the Trust on January 1, 2003. This Statement
addresses financial accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement
costs. The effect of adopting SFAS No. 143 will not have a material impact on
the Trust's financial statements.
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment
of FASB Statement No. 13, and Technical Corrections" was issued in April 2002
and is effective for fiscal years beginning after May 15, 2002. This Statement
includes the rescission of FASB Statement No. 4, "Reporting Gains and Losses
from Extinguishment of Debt", and an amendment to FASB Statement No. 13,
"Accounting for Leases", to eliminate an inconsistency between the required
accounting for sale-leaseback transactions and the required accounting for
certain lease modifications that have economic effects that are similar to sale-
leaseback transactions. The effect of adopting SFAS No. 145 will not have a
material impact on the Trust's financial statements.
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" was issued in June 2002 and will be effective for exit or disposal
activities subsequent to December 31, 2002. The Trust anticipates no material
impact on its financial statements from the adoption of this accounting
standard.
SFAS No. 148, "Accounting for Stock-Based Compensation -- Transition and
Disclosure, an amendment of FASB Statement No. 123," was issued in December 2002
and provides new transition methods if an entity adopts the fair value based
method of valuing stock-based compensation suggested in SFAS No. 123 "Accounting
for Stock-Based Compensation," as well as requiring additional disclosures in
interim and annual financial statements. The Trust has no options or other
stock-based instruments and accordingly, the impact of this new Standard is not
expected to be material to the financial statements of the Trust.
FASB interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others," requires disclosures beginning with financial statements ending after
December 15, 2002 and requires liability recognition beginning January 1, 2003.
The Trust had no such guarantees outstanding as of December 31, 2002.
FIN No. 46, "Consolidation of Variable Interest Entities" was issued in
January 2003. This interpretation of Accounting Research Bulletin No. 51,
"Consolidated Financial Statements," applies immediately to variable interest
entities created after January 31, 2003 and applies to the first period
beginning after June 15, 2003 to entities acquired before February 1, 2003. This
FIN does not affect the Trust as it has no unconsolidated subsidiaries accounted
for under the equity method of accounting.
OFF-BALANCE SHEET ARRANGEMENTS
As stipulated in the Trust Agreement, the Trust is intended to be passive
in nature and the Trustee does not have any control over or any responsibility
relating to the operation of the Royalty Properties. The Trustee has powers to
collect and distribute proceeds received by the Trust and pay Trust liabilities
and expenses and its actions have been limited to those activities. Therefore,
the Trust has not engaged in any off-balance sheet arrangements.
INFLATION
Prices obtained for oil and gas production depend upon numerous factors
that are beyond the control of the Trust, including the extent of domestic and
foreign production, imports of foreign oil, market demand, domestic and
worldwide economic and political conditions, storage capacity and government
20
regulations and tax laws. Prices for both oil and gas have fluctuated between
2000 to 2002. The following table presents the weighted average prices received
per year by the Trust:
<Table>
<Caption>
OIL GAS
PER BBL PER MCF
------- -------
2002........................................................ 21.82 2.70
2001........................................................ 23.88 4.53
2000........................................................ 23.86 2.85
</Table>
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, factors affecting the
price of oil and natural gas contained in Item 1, "Business", 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 (including, without limitation, 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, instability in oil-producing regions and the effect of
governmental regulations) 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.
21
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 accompanying statements of assets, liabilities and
trust corpus of Sabine Royalty Trust (the "Trust") as of December 31, 2002 and
2001, and the related statements of distributable income and changes in trust
corpus for each of the three years in the period ended December 31, 2002. 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 auditing standards generally
accepted in the United States of America. 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 accounting principles generally accepted in the United
States of America.
In our opinion, such financial statements present fairly, in all material
respects, the assets, liabilities and trust corpus of the Trust at December 31,
2002 and 2001, and the distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 2002, on the basis of
accounting described in Note 2.
/s/ DELOITTE & TOUCHE LLP
Dallas, Texas
March 17, 2003
22
SABINE ROYALTY TRUST
FINANCIAL STATEMENTS
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<Table>
<Caption>
DECEMBER 31,
--------------------------
2002 2001
---------- ----------
ASSETS
Cash and short-term investments............................. $3,898,379 $4,140,971
Royalty interests in oil and gas properties less accumulated
amortization of $20,902,284 (2002) and $20,680,778
(2001).................................................... 1,492,901 1,714,407
---------- ----------
Total....................................................... $5,391,280 $5,855,378
========== ==========
LIABILITIES AND TRUST CORPUS
Trust expenses payable...................................... $ 408,121 $ 127,074
Other payables (Note 4)..................................... 379,940 51,207
---------- ----------
Total liabilities........................................... 788,061 178,281
Trust corpus (14,579,345 units of beneficial interest
authorized and outstanding)............................... 4,603,219 5,677,097
---------- ----------
Total....................................................... $5,391,280 $5,855,378
========== ==========
</Table>
STATEMENTS OF DISTRIBUTABLE INCOME
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
---------------------------------------------
2002 2001 2000
----------- ----------- -----------
Royalty income................................... $28,134,458 $44,222,701 $34,407,684
Interest income.................................. 43,337 205,134 239,909
----------- ----------- -----------
Total............................................ 27,177,795 44,427,835 34,647,593
General and administrative expenses (Note 6)..... 1,638,044 1,622,457 1,525,549
----------- ----------- -----------
Distributable income............................. $26,539,751 $42,805,378 $33,122,044
=========== =========== ===========
Distributable income per unit (Basic and Assuming
Dilution) (14,579,345 units) (Note 1).......... $ 1.82 $ 2.94 $ 2.27
=========== =========== ===========
Distributions per unit (Note 3).................. $ 1.88 $ 2.86 $ 2.27
=========== =========== ===========
</Table>
STATEMENTS OF CHANGES IN TRUST CORPUS
<Table>
<Caption>
2002 2001 2000
------------ ------------ ------------
Trust corpus, beginning of year................ $ 5,677,097 $ 4,802,700 $ 5,154,199
Amortization of royalty interests.............. (221,506) (224,870) (310,044)
Distributable income........................... 26,539,751 42,805,378 33,122,044
Distributions to unit holders (Note 3)......... (27,392,123) (41,706,111) (33,163,499)
------------ ------------ ------------
Trust corpus, end of year...................... $ 4,603,219 $ 5,677,097 $ 4,802,700
============ ============ ============
</Table>
The accompanying notes are an integral part of these financial statements.
23
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
24
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
reporting to Unit holders, the conveyances by Sabine of the Royalties located in
five of the six states 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. On
December 31, 2001, Bank of America, N.A. assumed the duties as Trustee of the
Sabine Louisiana Royalty Trust, since Louisiana law now permits an out-of-state
bank to act in this capacity.
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
agreements are 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 accounting principles generally accepted in the United States of
America:
- 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).
25
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
The financial statements of the Trust differ from financial statements
prepared in conformity with accounting principles generally accepted in the
United States of America 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.
- 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 accounting principles generally accepted in the United States of
America.
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
SFAS No. 143, "Accounting for Asset Retirement Obligations" was issued in
June 2001, and will be adopted by the Trust on January 1, 2003. This Statement
addresses financial accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement
costs. The effect of adopting SFAS No. 143 will not have a material impact on
the Trust's financial statements.
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment
of FASB Statement No. 13, and Technical Corrections" was issued in April 2002
and is effective for fiscal years beginning after May 15, 2002. This Statement
includes the rescission of FASB Statement No. 4, "Reporting Gains and Losses
from Extinguishment of Debt", and an amendment to FASB Statement No. 13,
"Accounting for Leases", to eliminate an inconsistency between the required
accounting for sale-leaseback transactions and the required accounting for
certain lease modifications that have economic effects that are similar to sale-
leaseback transactions. The effect of adopting SFAS No. 145 will not have a
material impact on the Trust's financial statements.
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" was issued in June 2002 and will be effective for exit or disposal
activities subsequent to December 31, 2002. The Trust anticipates no material
impact on its financial statements from the adoption of this accounting
standard.
SFAS No. 148, "Accounting for Stock-Based Compensation -- Transition and
Disclosure, an amendment of FASB Statement No. 123," was issued in December 2002
and provides new transition methods if
26
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
an entity adopts the fair value based method of valuing stock-based compensation
suggested in SFAS No. 123 "Accounting for Stock-Based Compensation," as well as
requiring additional disclosures in interim and annual financial statements. The
Trust has no options or other stock-based instruments and accordingly, the
impact of this new Standard is not expected to be material to the financial
statements of the Trust.
FASB interpretation ("FIN") No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others," requires disclosures beginning with financial statements ending after
December 15, 2002 and requires liability recognition beginning January 1, 2003.
The Trust had no such guarantees outstanding as of December 31, 2002.
FIN No. 46, "Consolidation of Variable Interest Entities" was issued in
January 2003. This interpretation of Accounting Research Bulletin No. 51,
"Consolidated Financial Statements," applies immediately to variable interest
entities created after January 31, 2003 and applies to the first period
beginning after June 15, 2003 to entities acquired before February 1, 2003. This
FIN does not affect the Trust as it has no unconsolidated subsidiaries accounted
for under the equity method of accounting.
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 is 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, which is on the record date following the end
of each month, which is discussed above in Note 1.
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 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 is primarily from purchasers of the Trust's
oil and gas production and consists of gross sales of production less applicable
severance taxes. In January, 2000, the Trust received a cash settlement of
approximately $413,000 relating to the price adjustments for prior years on a
limited number of producing oil and gas wells. In March, 2002, the Trust
received a cash settlement of approximately $828,000 relating to the
Multidistrict Litigation Docket no. 1206 ("MDL 1206"), a class
27
SABINE ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
action lawsuit, filed against numerous companies (the "Defendants") that
produce, sell and/or purchase domestic crude oil. These claims were based upon
methods used by the Defendants to calculate payments to royalty owners. The
complaint alleged that, as a result of the price-fixing conspiracy among the
Defendants, their payments to class members have been placed upon per-barrel
values that were less than competitive market values. The MDL 1206 complaint
stated that the alleged price-fixing conspiracy violated federal antitrust law.
It also alleged certain state-law violations, including claims for breach of
contract. This settlement was included in the April 2002 distribution along with
monies received in the normal course of business.
4. OTHER PAYABLES
Other payables consist of the following:
<Table>
<Caption>
DECEMBER 31, 2002 2001
- ------------ -------- -------
Funds due to payors for royalties erroneously forwarded to
the Trust................................................. $ 0 $ 9
Royalty receipts in suspense pending verification of
ownership interest or title............................... $379,940 $51,198
-------- -------
Total............................................. $379,940 $51,207
======== =======
</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, 2002, the Trust declared the following
distributions:
<Table>
<Caption>
MONTHLY RECORD DATE PAYMENT DATE DISTRIBUTION PER UNIT
- ------------------- ------------ ---------------------
January 15, 2003 January 29, 2003 $.17308
February 18,2003 February 28, 2003 $.16437
March 17, 2003 March 31, 2003 $.11755
</Table>
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>
2002 2001 2000
---------- ---------- ----------
Trustee's fee................................... $ 284,172 $ 260,986 $ 251,246
Escrow agent's fee.............................. 852,520 782,961 753,747
---------- ---------- ----------
Total fees and expenses......................... $1,136,692 $1,043,947 $1,004,993
========== ========== ==========
</Table>
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, 2002 and 2001 (in thousands, except per Unit amounts):
<Table>
<Caption>
CALENDAR ROYALTY DISTRIBUTABLE DISTRIBUTABLE
QUARTER INCOME INCOME INCOME PER UNIT
- -------- ------- ------------- ---------------
2002
First Quarter............................ $ 6,971 $ 6,562 $0.45
Second Quarter........................... 6,092 5,653 0.39
Third Quarter............................ 7,819 7,413 0.51
Fourth Quarter........................... 7,252 6,912 0.47
------- ------- -----
$28,134 $26,540 $1.82
======= ======= =====
2001
First Quarter............................ $13,624 $13,257 $0.91
Second Quarter........................... 11,452 11,095 0.76
Third Quarter............................ 9,991 9,617 0.66
Fourth Quarter........................... 9,156 8,836 0.61
------- ------- -----
$44,223 $42,805 $2.94
======= ======= =====
</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)
--------- ------
January 1, 2000............................................. 5,751 36,792
Revisions of previous statements.......................... 412 8,927
Production................................................ (611) (7,243)
----- ------
December 31, 2000........................................... 5,552 38,476
Revisions of previous statements.......................... 396 4,962
Production................................................ (518) (5,949)
----- ------
December 31, 2001........................................... 5,430 37,489
Revisions of previous statements.......................... 181 4,457
Production................................................ (526) (5,614)
----- ------
December 31, 2002........................................... 5,085 36,332
===== ======
</Table>
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)
--------- ------
Proved developed reserves:
January 1, 2000........................................... 5,738 36,665
December 31, 2000......................................... 5,546 38,334
December 31, 2001......................................... 5,425 37,376
December 31, 2002......................................... 5,067 36,239
</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 ($29.20 per bbl and $4.13 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, 2002 2001 2000
- ------------ --------- -------- ---------
Future net cash inflows........................ $ 270,513 $165,978 $ 450,494
Discount of future net cash flows at 10%....... (132,058) (79,863) (201,922)
--------- -------- ---------
Standardized measure of discounted future net
cash flows................................... $ 138,455 $ 86,115 $ 248,572
========= ======== =========
</Table>
The change in the standardized measure of discounted future net cash flows
for the years ended December 31, 2002, 2001 and 2000 is as follows (in
thousands):
<Table>
<Caption>
2002 2001 2000
-------- --------- --------
Standardized measure of discounted future net
cash flows, January 1......................... $ 86,115 $ 248,572 $105,512
Royalty income, net of severance and ad valorem
taxes......................................... (28,134) (44,223) (34,408)
Changes in prices, net of related costs......... 51,026 (123,464) 119,910
Revisions of previous estimates and other....... 20,836 (19,627) 47,007
Accretion of discount........................... 8,612 24,857 10,551
-------- --------- --------
Standardized measure of discounted future net
cash flows, December 31....................... $138,455 $ 86,115 $248,572
======== ========= ========
</Table>
Subsequent to year end, both the price of oil and gas continued to
fluctuate, giving rise to a correlating adjustment of the respective
standardized measure of discounted future net cash flows. As of March 3, 2003,
published oil prices were approximately $35.88 per barrel, which compared to
$29.20 per barrel, used to calculate the above information, would result in a
larger standardized measure of discounted future net cash flows for oil. As of
March 3, 2003, published gas prices were approximately $8.81 per Mcf. The use of
such price, as compared to $4.13 per Mcf, which was used to calculate the above
information, would result in a larger standardized measure of discounted future
net cash flows for gas.
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, 2002, 2001 and 2000. 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 of America. 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 , the Statements of Fees and Expenses were prepared
on a modified cash basis of accounting, which is a comprehensive basis of
accounting other than accounting principles generally accepted in the United
States of America.
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, 2002, 2001 and 2000, on the basis of accounting
described in Note 3.
/s/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Charlotte, North Carolina
March 17, 2003
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, 2002
<Table>
<Caption>
2002 2001 2000
----------- ---------- ----------
Trustee's fee...................................... $ 284,172 $ 260,986 $ 251,246
Escrow agent's fee................................. 852,520 782,961 753,747
---------- ---------- ----------
Total fees and expenses............................ $1,136,692 1,043,947 1,004,993
========== ========== ==========
</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 elected to forgo bonuses earned
of $38,308, $56,041 and $14,989 in 2002, 2001 and 2000 respectively.
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
paid to third parties.
32
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 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.
33
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.
Directors and Executive Officers. 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.
Compliance with Section 16(a) of the Exchange Act. The Trust has no
directors and officers and knows of no Unit holder that is a beneficial owner of
more than ten percent of the outstanding Units, and is therefore unaware of any
person that failed to report on a timely basis reports required by Section 16(a)
of the Exchange Act.
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, 2003
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 February 28,
2003 an aggregate of 245,621 Units in various fiduciary capacities, and it had
shared voting and investment power with respect to 52,391 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.
ITEM 14. CONTROLS AND PROCEDURES.
Within the 90 days prior to the date of this report, the trustee carried
out an evaluation of the effectiveness of the design and operation of the
Trust's disclosure controls and procedures pursuant to Exchange Act Rule 13a-14.
Based upon that evaluation, the Trustee concluded that the Trust's disclosure
controls and procedures are effective in timely alerting the trustee to material
information relating to the Trust required to be included in the Trust's
periodic filings with the Securities and Exchange Commission. No significant
changes in the Trust's internal controls or other factors that could affect
these controls have occurred subsequent to the date of such evaluation.
34
PART IV
ITEM 15. 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, 2002 and
2001
Statements of Distributable Income for Each of the Three Years in the
Period Ended December 31, 2002
Statements of Changes in Trust Corpus for Each of the Three Years in the
Period Ended December 31, 2002
Notes to Financial Statements
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>
(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.
(99) -- Report dated March 1, 2003 of the Trustee containing
interim tax information for each of the 12 months in the
year ending December 31, 2002.
(99.1) -- Certification by Bank of America, Trustee of Sabine
Royalty Trust, dated March 27, 2003 and submitted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(18 U.S.C. Section 1350).
</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.
(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.
35
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., Trustee
By: /s/ RON E. HOOPER
----------------------------------
Ron E. Hooper
Senior Vice-President
Date: March 27, 2003
(THE REGISTRANT HAS NO DIRECTORS OR EXECUTIVE OFFICERS.)
36
CERTIFICATIONS
I, Ron Hooper, certify that:
1. I have reviewed this annual report on Form 10-K of Sabine Royalty
Trust, for which Bank of America, N.A. acts as Trustee;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly present in all
material respects the financial condition, distributable income and changes
in trust corpus of the registrant as of, and for, the periods presented in
this annual report;
4. I am responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and
15d-14), or for causing such procedures to be established and maintained,
for the registrant and I have:
a) designed such disclosure controls and procedures, or caused such
controls and procedures to be designed, to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to me by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and
c) presented in this annual report my conclusions about the
effectiveness of the disclosure controls and procedures based on my
evaluation as of the Evaluation Date;
5. I have disclosed, based on my most recent evaluation, to the
registrant's auditors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves persons who
have a significant role in the registrant's internal controls; and
6. I have indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of my most
recent evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
By: /s/ RON HOOPER
------------------------------------
Ron Hooper
Senior Vice President and Trust
Administrator
Bank of America, N.A.
Date: March 27, 2003
37
INDEX TO EXHIBITS
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
(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.
(99) -- Report dated March 1, 2003 of the Trustee containing
interim tax information for each of the 12 months in the
year ending December 31, 2002.
(99.1) -- Certification by Bank of America, Trustee of Sabine
Royalty Trust, dated March 27, 2003 and submitted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(18 U.S.C. Section 1350).
</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.