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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002
COMMISSION FILE NO. 1-8032
SAN JUAN BASIN ROYALTY TRUST
<Table>
TEXAS 75-6279898
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
</Table>
TEXASBANK, TRUST DEPARTMENT
2525 RIDGMAR BOULEVARD
FORT WORTH, TEXAS 76116
(Address of principal executive offices)
(Zip Code)
TELEPHONE NUMBER: (866) 809-4553
(Registrant's telephone number, including area code)
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 [ ]
Number of Units of beneficial interest outstanding at November 14, 2002:
46,608,796
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SAN JUAN BASIN ROYALTY TRUST
PART I
FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
The condensed financial statements included herein have been prepared by
the independent accountants for the San Juan Basin Royalty Trust (the "Trust"),
at the request of TexasBank, the Trustee of the Trust, without audit, pursuant
to the rules and regulations of the Securities and Exchange Commission. Certain
information and footnote disclosures normally included in annual financial
statements have been condensed or omitted pursuant to Rule 10-01 of Regulation
S-X promulgated under the Securities and Exchange Act of 1934, although the
Trustee believes that the disclosures are adequate to make the information
presented not misleading. These condensed financial statements should be read in
conjunction with the financial statements and the notes thereto included in the
Trust's annual report on Form 10-K for the year ended December 31, 2001. In the
opinion of the Trustee, all adjustments, consisting only of normal recurring
adjustments, necessary to present fairly the assets, liabilities and trust
corpus of the San Juan Basin Royalty Trust at September 30, 2002, and the
distributable income and changes in trust corpus for the three-month periods and
nine-month periods ended September 30, 2002 and 2001 have been included. The
distributable income for such interim periods is not necessarily indicative of
the distributable income for the full year.
1
SAN JUAN BASIN ROYALTY TRUST
CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<Table>
<Caption>
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- ------------
(UNAUDITED)
ASSETS
Cash and short-term investments............................. $ 4,967,812 $ 191,620
Net overriding royalty interest in producing oil and gas
properties (net of accumulated amortization of $98,383,984
and $95,415,779 at September 30, 2002 and December 31,
2001, respectively)....................................... 34,891,544 37,859,749
----------- -----------
$39,859,356 $38,051,369
=========== ===========
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit Holders........................ $ 4,852,954 $ --
Cash Reserves............................................... 114,858 191,620
Trust corpus -- 46,608,796 Units of beneficial interest
authorized and outstanding................................ 34,891,544 37,859,749
----------- -----------
$39,859,356 $38,051,369
=========== ===========
</Table>
CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- -------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(UNAUDITED)
Royalty income........................... $12,549,272 $13,971,820 $26,034,196 $78,047,734
Interest income.......................... 6,560 13,600 9,410 145,292
Decrease in cash reserves................ -- -- 76,762 --
----------- ----------- ----------- -----------
12,555,832 13,985,420 26,120,368 78,193,026
Expenditures -- general and
administrative......................... 259,497 270,489 1,282,218 964,837
----------- ----------- ----------- -----------
Distributable income..................... $12,296,335 $13,714,931 $24,838,150 $77,228,189
=========== =========== =========== ===========
Distributable income per Unit (46,608,796
Units)................................. $ .263820 $ .294257 $ .532907 $ 1.656945
=========== =========== =========== ===========
</Table>
The accompanying notes to condensed financial statements are an integral part of
these statements.
2
SAN JUAN BASIN ROYALTY TRUST
CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
(UNAUDITED)
Trust corpus, beginning of period.... $ 36,354,315 $ 38,730,055 $ 37,859,749 $ 40,686,854
Amortization of net overriding
royalty interest................... (1,462,771) (670,989) (2,968,205) (2,627,787)
Distributable income................. 12,296,335 13,714,931 24,838,150 77,228,189
Distributions declared............... (12,296,335) (13,714,931) (24,838,150) (77,228,189)
------------ ------------ ------------ ------------
Total corpus, end of period.......... $ 34,891,544 $ 38,059,066 $ 34,891,544 $ 38,059,067
============ ============ ============ ============
</Table>
The accompanying notes to condensed financial statements are an integral part of
these statements.
3
SAN JUAN BASIN ROYALTY TRUST
NOTES TO CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF ACCOUNTING
The San Juan Basin Royalty Trust was established as of November 1, 1980.
The financial statements of the Trust are prepared on the following basis:
- Royalty income recorded for a month is the amount computed and paid by
the working interest owner, Burlington Resources Oil & Gas Company LP
f/k/a Burlington Resources Oil & Gas Company ("BROG"), to the Trustee for
the Trust. Royalty income consists of the amounts received by the owner
of the interest burdened by the net overriding royalty interest
("Royalty") from the sale of production less accrued production costs,
development and drilling costs, applicable taxes, operating charges, and
other costs and deductions, multiplied by 75%.
- Trust expenses recorded are based on liabilities paid and cash reserves
established from Royalty income for liabilities and contingencies.
- Distributions to Unit Holders are recorded when declared by the Trustee.
- The conveyance which transferred the overriding royalty interest to the
Trust provides that any excess of production costs over gross proceeds
must be recovered from future net profits.
The financial statements of the Trust differ from financial statements
prepared in accordance with accounting principles generally accepted in the
United States of America ("GAAP") because revenues are not accrued in the month
of production; certain cash reserves may be established for contingencies which
would not be accrued in financial statements prepared in accordance with GAAP;
and amortization of the Royalty calculated on a unit-of-production basis is
charged directly to trust corpus. The basis of accounting used by the Trust is
widely used by royalty trusts for financial reporting purposes.
2. FEDERAL INCOME TAXES
For federal income tax purposes, the Trust constitutes a fixed investment
trust which is taxed as a grantor trust. A grantor trust is not subject to tax
at the trust level. The Unit Holders are considered to own the Trust's income
and principal as though no trust were in existence. The income of the Trust is
deemed to have been received or accrued by each Unit Holder at the time such
income is received or accrued by the Trust rather than when distributed by the
Trust.
The Royalty constitutes an "economic interest" in oil and gas properties
for federal income tax purposes. Unit Holders must report their share of the
revenues of the Trust as ordinary income from oil and gas royalties and are
entitled to claim depletion with respect to such income. The Royalty is treated
as a single property for depletion purposes.
The Trust has on file technical advice memoranda confirming the tax
treatment described above.
The Trust began receiving royalty income from coal seam gas wells beginning
in 1989. Under Section 29 of the Internal Revenue Code, coal seam gas production
from wells drilled prior to January 1, 1993 (including certain wells recompleted
in coal seam formations thereafter), generally qualifies for the federal income
tax credit for producing non-conventional fuels if such production and the sale
thereof occurs before January 1, 2003. For 2001 this tax credit was $1.08 per
MMBtu. The Trust also receives production from wells producing from a tight
sands formation. These wells must have been drilled prior to January 1, 1993 and
after November 5, 1990, or after December 31, 1979, if the related formation was
committed or dedicated to interstate commerce (as defined in Section 2(18) of
the Natural Gas Policy Act as in effect November 5, 1990) as of April 20, 1977.
The credit relating to tights sands production is not adjusted for inflation, so
the credit remains fixed at .517241 per MMBtu. To benefit from the credit, each
Unit Holder must determine from the tax information they receive from the Trust,
their pro rata share of qualifying production of the Trust,
4
SAN JUAN BASIN ROYALTY TRUST
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
based upon the number of Units owned during each month of the year, and the
amount of available credit per MMBtu for the year, and then apply the tax credit
against their own income tax liability, but such credit may not reduce their
regular tax liability (after the foreign tax credit and certain other
nonrefundable credits) below their alternative minimum tax. Section 29 also
provides that any amount of Section 29 credit disallowed for the tax year solely
because of this limitation will increase their credit for prior year minimum tax
liability, which may be carried forward indefinitely as a credit against the
taxpayer's regular tax liability, subject, however, to the limitations described
in the preceding sentence. There is no provision for the carryback or
carryforward of the Section 29 credit in any other circumstances.
The Trustee is provided summary Section 29 tax credit information related
to Trust properties by BROG, which information is then passed along to the Unit
Holders. In 1999, the U.S. Court of Appeals for the 10th Circuit upheld the
position of the Internal Revenue Service and the Tax Court that nonconventional
fuel such as coal seam gas does not qualify for the Section 29 credit unless the
producer has received an appropriate well category determination from the
Federal Energy Regulatory Commission ("FERC"). The FERC's certification
authority expired effective January 1, 1993. However, on July 14, 2000, the FERC
issued a final ruling amending its regulations to reinstate certain regulations
involving well category determinations for all wells and tight formation areas
that could qualify for the Section 29 tax credit. BROG has informed the Trustee
that it has identified approximately 250 wells as non-certified. Of those, BROG
has determined that six do not qualify for the Section 29 tax credit. BROG has
applied to the FERC for certification of the approximately 100 qualified wells
operated by it, and is in communication with the operators of the remaining
qualified wells to encourage the filing by those operators of applications for
certification.
The classification of the Trust's income for purposes of the passive loss
rules may be important to a Unit Holder. As a result of the Tax Reform Act of
1986, royalty income will generally be treated as portfolio income and will not
reduce passive losses.
3. CONTINGENCIES
See Part II -- Item 1, "Legal Proceedings" concerning the status of
litigation matters.
4. SETTLEMENT OF CLAIMS RELATING TO GAS IMBALANCE
In June 2000, the Trust and BROG entered into a partial settlement of
claims relating to a gas imbalance with respect to production from mineral
properties currently operated by BROG. Under the terms of the partial settlement
BROG paid the Trust $3,490,000 to settle the imbalance insofar as it relates to
some of the wells located on the subject properties. The remainder of the
imbalance is to be addressed through volume adjustments whereby the Trust's net
overriding royalty interest will be applied to 50% of the overproduced parties'
interest, on a monthly basis, until the imbalance is corrected. The Trustee and
its consultants remain in communication with BROG in order to determine the
estimated value of the volume adjustments and the time during which the
remainder of the imbalance will be corrected. Such volume adjustments continue
to be monitored by the Trust's consultants.
5. COMMITMENTS AND CONTINGENCIES
At December 31, 2001, BROG had incurred excess production costs of
$2,259,628 on the underlying properties due primarily to high capital costs. The
Trust conveyance provides for the deduction of excess production costs in
determining royalty income until such costs are fully recovered and allows for
interest to be charged on excess production costs at the prime rate. Interest in
the amount of $10,545 was added to such excess production costs. Of the total,
$1,702,630 is attributable to the Trust and has been deducted in determining
royalty income for the nine months ended September 30, 2002. As a result of
settlements agreed to among BROG and other third parties concerning properties
burdened by the Royalty, the net profits applicable to the Trust were reduced by
approximately $3,624,117. This amount was deducted from the
5
SAN JUAN BASIN ROYALTY TRUST
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
Royalty due the Trust in one million dollar increments in each of May, June and
July of 2002, with the balance deducted in August of 2002.
6. AMENDMENTS TO THE TRUST'S INDENTURE
At a special meeting of Unit Holders on September 30, 2002, the Unit
Holders appointed TexasBank as the successor Trustee of the Trust. The Unit
Holders also approved amendments to the Trust's Royalty Trust Indenture (the
"Indenture") which clarified the language of the Indenture, clarified and
expanded the indemnification provisions of the Indenture, and amended the
provisions of the Indenture applicable to the fees payable to the Trustee, the
investment options available to the Trustee and the manner in which the Trustee
can dispose of assets of the Trust.
6
ITEM 2. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
FORWARD-LOOKING INFORMATION
Certain information included in this report contains, and other materials
filed or to be filed by the Trust with the Securities and Exchange Commission
(as well as information included in oral statements or other written statements
made or to be made by the Trust) may contain or include, forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934, and Section 27A of the Securities Act of 1933. Such forward-looking
statements may be or may concern, among other things, capital expenditures,
drilling activity, development activities, production efforts and volumes,
hydrocarbon prices and the results thereof, and regulatory matters. Such
forward-looking statements generally are accompanied by words such as "may,"
"will," "estimate," "expect," "predict," "anticipate," "goal," "should,"
"assume," "believe," "plan," "intend," or other words that convey the
uncertainty of future events or outcomes. Such statements reflect BROG's current
view with respect to future events; are based on our assessment of, and are
subject to, a variety of factors deemed relevant by the Trustee and BROG and
involve risks and uncertainties. Should one or more of these risks or
uncertainties occur, actual results may vary materially and adversely from those
anticipated.
THREE MONTHS ENDED SEPTEMBER 30, 2002 AND 2001
The Trust received royalty income of $12,549,272 and interest income of
$6,560 during the third quarter of 2002. After deducting administrative expenses
of $259,497, distributable income for the quarter was $12,296,335 ($.263820 per
Unit). In the third quarter of 2001, royalty income was $13,971,820, interest
income was $13,600, administrative expenses were $270,489 and distributable
income was $13,714,931 ($.294257 per Unit). The tax credit relating to
production from coal seam and tight sand wells totaled approximately $.04 per
Unit for the third quarter of 2002 and $.03 per Unit for the third quarter of
2001. For further information concerning this tax credit, Unit Holders should
refer to the Trust's Annual Report for 2001. Based on 46,608,796 Units
outstanding, the per Unit distributions during the third quarter of 2002 were as
follows:
<Table>
July........................................................ $.082140
August...................................................... .077559
September................................................... .104121
--------
Quarter Total............................................... $.263820
</Table>
The royalty income distributed in the third quarter of 2002 was lower than
that distributed in the third quarter of 2001. Royalty income in the third
quarter of 2002 was negatively impacted by a decrease in the average gas price
from $3.06 per Mcf for the third quarter of 2001 to $2.28 per Mcf for the third
quarter of 2002 and by the loss of the Val Verde Credit (as defined and
described below), offset in part by the effect of audit exceptions identified by
the Trust's joint interest auditors and granted and paid by BROG in the third
quarter. Interest earnings for the quarter ended September 30, 2002, as compared
to the quarter ended September 30, 2001, were lower, primarily due to lower
interest rates and a decrease in funds available for investment. Administrative
expenses were lower, primarily as a result of differences in timing of the
receipt and payment of these expenses.
The capital costs attributable to the properties from which the Trust's 75%
net overriding royalty ("Royalty") was carved (the "Underlying Properties") for
the third quarter of 2002 were reported by BROG as approximately $2.1 million.
BROG's capital expenditure budget for the Underlying Properties for 2002 is an
estimated $12.4 million of which approximately $8 million had been expended
through the end of the August 2002 production month. Capital expenditures were
approximately $8.1 million for the third quarter of 2001. In 2001, approximately
$33.0 million in capital expenditures were deducted in calculating the Royalty.
In February 2002, BROG informed the Trust that for 2002 it anticipates drilling
43 new wells to be operated by BROG and 26 new wells to be operated by third
parties. Of the new BROG operated wells, 36 are projected to be conventional
wells completed in the Pictured Cliffs, Mesaverde and/or Dakota formations, and
the remaining seven are projected as coal seam wells completed in the Fruitland
Coal formation. BROG projects
7
approximately $9.6 million to be spent on the new wells, and $2.8 million to be
expended in working over existing wells and in the maintenance and improvement
of production facilities.
BROG previously informed the Trust that increases in its capital program,
particularly in 2000 and 2001, were designed to offset the natural decline in
production from the Underlying Properties. BROG has reported favorable results
in this effort in that natural gas production for calendar 2001 averaged
approximately 121 MMcf per day, as compared to average production of
approximately 116 MMcf per day and 113 MMcf per day for calendar 2000 and 1999,
respectively. BROG has reported that natural gas production for the third
quarter of 2002 averaged approximately 130 MMcf per day.
BROG indicates its budget for 2002 reflects continued, significant
development of properties in which the Trust's net overriding royalty interest
is relatively high, as well as a sustained focus on conventional formations,
including infill drilling to the Mesaverde and Dakota formations, development of
the Fruitland Coal formation and multiple formation completions.
Eighty-acre spacing has been permitted in the Mesaverde formation since
1997. The Mesaverde formation was originally developed in the 1950's on 320-acre
spacing, with infill drilling initiated in the early 1970's on 160-acre spacing.
In 1994, BROG undertook an extensive study of the Mesaverde formation. Results
indicated that downspaced drilling (infill drilling) on 80-acre spacing could
significantly increase recoverable gas reserves in the reservoir. A pilot
program began in 1997 and was expanded in 1998 to include two additional areas.
In February 2002, BROG informed the Trust that the New Mexico Oil Conservation
Division (the "OCD") had approved plans for 80-acre infill drilling of the
Dakota formation in the San Juan Basin. In October 2002, the OCD approved a
reduction from 320 to 160-acre spacing for those portions of the Fruitland Coal
formation where wells typically produce less than two MMcf per day. The OCD has
asked BROG and other interested parties to study over the next year whether the
change in spacing requirements should be expanded to cover other portions of
that reservoir.
BROG has informed the Trust that lease operating expenses and property
taxes were $3,974,830 and ($187,356) respectively, for the third quarter of
2002, as compared to $3,666,991 and $284,063, respectively, for the third
quarter of 2001. On inquiry, as regards the negative property tax allocation,
BROG responded that its July royalty calculation included adjustments for
property taxes previously allocated to the Trust in error.
As part of the September 4, 1996, settlement of the litigation filed by the
Trustee on June 4, 1992, against BROG and Southland Royalty Company, the Trust
was entitled to certain adjustments (the "Val Verde Credit") that represented
cost reductions favorable to the Trust in the charges for coal seam gas gathered
and treated on BROG's Val Verde system. The settlement provided that the Val
Verde Credit was applicable until the later of July 1, 2002 or until BROG no
longer owned the Val Verde facility. By correspondence dated July 15, 2002, BROG
notified the Trustee of the sale of the Val Verde facility to TEPPCO Partners,
L.P. effective July 1, 2002. Accordingly, effective July 1, 2002, the
calculation of net proceeds for gas gathered and treated at the Val Verde
facility will no longer include the Val Verde Credit. The total amount of the
Val Verde Credit for the twelve months ended June 30, 2002, was estimated by the
Trust's joint interest auditors as approximately $1,880,000. The loss of the Val
Verde Credit will result in increased costs allocated to the Trust for coal seam
gas gathered and treated on the Val Verde system and accordingly, will decrease
the royalty income received by the Trust.
BROG has informed the Trustee that during the third quarter of 2002, 24
gross (5.78 net) conventional new wells, one gross (0.05 net) payadd, and 11
gross (4.25 net) recompletions were completed on the Underlying Properties.
Thirty-seven gross (11.06 net) conventional new wells, one gross (.82 net)
restimulation, and four gross (.45 net) recompletions were in progress at
September 30, 2002. "Gross" acres or wells for purposes of this discussion,
means the entire ownership interest of all parties in such properties, and
BROG's interest therein is referred to as the "net" acres or wells. A payadd is
the completion of an additional productive interval in an existing completed
zone in a well.
There was one gross (.41 net) coal seam miscellaneous project, two gross
(.91 net) new coal seam wells, two gross (1.12 net) coal seam recompletions, and
three gross (.01 net) coal seam restimulations completed
8
during the third quarter of 2002. Three gross (1.26 net) new coal seam wells,
one gross (.04 net) coal seam recavitation, and five gross (3.41 net) coal seam
recompletions were in progress at September 30, 2002.
In the third quarter of 2001, nine gross (1.53 net) miscellaneous capital
projects, 24 gross (8.32 net) conventional new wells, 17 gross (4.01 net)
payadds, five gross (3.65 net) recompletions and three gross (2.34 net)
restimulations were completed on the Underlying Properties. Seven gross (.74
net) miscellaneous capital projects, 113 gross (38.37 net) conventional new
wells, 12 gross (7.89 net) payadds, 47 gross (25.64 net) recompletions and eight
gross (.68 net) restimulations were in progress at September 30, 2001. There was
one gross (.35 net) coal seam recompletion completed during the third quarter of
2001. Four (.94 net) coal seam miscellaneous capital projects, six gross (.21
net) new coal seam wells, and 16 gross (.60 net) coal seam recompletions were in
progress at September 30, 2001.
Royalty income for the quarter ended September 30, 2002 is associated with
actual gas and oil production during May 2002 through July 2002 from the
Underlying Properties. Gas and oil sales from the Underlying Properties for the
quarters ended September 30, 2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
----------- -----------
Gas:
Total sales (Mcf)........................................ 11,997,442 11,092,019
Mcf per day.............................................. 130,406 120,565
Average price (per Mcf).................................. $ 2.28 $ 3.02
Oil:
Total sales (Bbls)....................................... 22,337 21,756
Bbls per day............................................. 243 236
Average price (per Bbl).................................. $ 21.95 $ 23.72
</Table>
Gas and oil sales attributable to the Royalty for the quarters ended
September 30, 2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
--------- ---------
Gas sales (Mcf)............................................. 6,831,526 4,995,406
Oil sales (Bbls)............................................ 12,772 9,975
</Table>
Sales volumes attributable to the Royalty are determined by dividing the
net profits received by the Trust and attributable to oil and gas, respectively,
by the prices received for sales volumes from the Underlying Properties, taking
into consideration production taxes attributable to the Underlying Properties.
Since the oil and gas sales attributable to the Royalty are based on an
allocation formula that is dependent on such factors as price and cost,
including capital expenditures, the aggregate production volumes from the
Underlying Properties may not provide a meaningful comparison to volumes
attributable to the Royalty.
During the third quarter of 2002, gas prices were lower than the prices
reported during the third quarter of 2001. The price per barrel of oil during
the third quarter of 2002 was $1.77 per barrel lower than that received for the
third quarter of 2001 due to decreases in oil prices in world markets generally,
including the posted prices applicable to oil sales attributable to the Royalty.
BROG has entered into two contracts for the sale of all volumes of gas
which are subject to the Royalty (the "Trust gas"). These contracts provide for
(i) the sale of Trust gas in two packages to Duke Energy and Marketing, L.L.C.
and PNM Gas Services, respectively, (ii) the delivery of Trust gas at various
delivery points over a period commencing April 1, 2002, and ending March 31,
2004, and (iii) the sale of Trust gas at prices which fluctuate in accordance
with published indices for gas sold in the San Juan Basin of New Mexico. Unit
Holders are referred to Note 6 of the Notes to Financial Statements in the
Trust's 2001 Annual Report for further information concerning the marketing of
gas produced from the Underlying Properties.
9
NINE MONTHS ENDED SEPTEMBER 30, 2002 AND 2001
For the nine months ended September 30, 2002, distributable income was
$24,838,150 ($.532907 per Unit) which was less than the $77,228,189 ($1.656945
per Unit) of income distributed during the same period in 2001. The decrease in
distributable income resulted primarily from lower gas and oil prices during the
first nine months of 2002. Interest income for the nine months ended September
30, 2002 was $9,410 compared to $145,292 during the first nine months of 2001.
This decrease is due to the timing of receipt of interest income, lower interest
rates and less cash to be invested in the first nine months of 2002. General and
administrative expenses were $1,282,218 in the first nine months of 2002
compared to $964,837 during the same 2001 period primarily due to differences in
timing of the receipt and payment of these expenses, but also as a result of
expenses incurred in an arbitration proceeding involving BROG and the Trust,
undertaken to resolve certain gas marketing issues, and expenses associated with
the special meeting of Unit Holders of the Trust held September 30, 2002.
Capital expenditures incurred by BROG, attributable to the Underlying
Properties, for the first nine months of 2002 amounted to approximately $16.8
million. Capital expenditures were approximately $21.5 million for the first
nine months of 2001. Capital expenditures included in the calculation of the
Royalty through the first nine months of 2002 are in excess of BROG's estimated
$12.4 million budget for 2002. This is primarily because the actual expenditures
include amounts attributable to prior years' budgets. Capital expenses within a
given year's capital budget frequently carry over and are not actually incurred
until subsequent years when the projects to which they relate are completed.
Lease operating expenses and property taxes totaled $11,733,774 for the first
nine months of 2002 compared to $11,207,821 for the first nine months of 2001.
The increase in lease operating expenses relates in part to the loss of the Val
Verde Credit beginning July 1, 2002.
BROG advised the Trustee that during the nine months ended September 30,
2002, 81 gross (25.97 net) conventional wells were completed on the Underlying
Properties, and 36 gross (14.44 net) conventional wells were recompleted. Two
gross (1.74 net) miscellaneous capital projects, and one gross (0.05 net) payadd
were completed during the first nine months of 2002. During the nine months
ended September 30, 2002, 14 gross (5.01 net) coal seam wells and four gross
(1.31 net) miscellaneous coal seam capital projects were completed. Eleven gross
(3.23 net) coal seam recompletions, four gross (.94 net) coal seam
recavitations, and three gross (.01 net) coal seam restimulations were completed
during the first nine months of 2002.
During the nine months ended September 30, 2001, 61 gross (23.68 net)
conventional wells were completed on the Underlying Properties, and 16 gross
(8.49 net) conventional wells were recompleted. Nine gross (1.53 net)
miscellaneous capital projects, five gross (3.20 net) restimulations, and 64
gross (6.77 net) conventional payadds were completed. Four gross (0.27 net) coal
seam wells were completed during the first nine months of 2001. During the nine
months ended September 30, 2001, two gross (.76 net) coal seam recompletions,
and one gross (.88 net) coal seam payadd were completed. Six gross (.04 net)
coal seam wells were recavitated during the first nine months of 2001.
Royalty income for the nine months ended September 30, 2002 is associated
with actual gas and oil production during November 2001 through July 2002 from
the Underlying Properties. Gas and oil sales from the Underlying Properties for
the nine months ended September 30, 2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
----------- -----------
Gas:
Total sales (Mcf)........................................ 34,598,163 32,711,954
Mcf per day.............................................. 126,733 119,824
Average price (per Mcf).................................. $ 2.31 $ 4.58
Oil:
Total Sales (Bbls)....................................... 72,035 71,395
Bbls per day............................................. 264 262
Average price (per Bbl).................................. $ 20.16 $ 25.13
</Table>
10
Gas and oil sales attributable to the Royalty for the nine months ended
September 30, 2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
---------- ----------
Gas sales (Mcf)............................................. 14,009,456 17,788,133
Oil sales (Bbls)............................................ 31,031 39,264
</Table>
During the first nine months of 2002, gas and oil prices were lower than
during the first nine months of 2001. Sales volumes attributable to the Royalty
are determined by dividing the net profits received by the Trust and
attributable to oil and gas, respectively, by the prices received for sales
volumes from the Underlying Properties, taking into consideration production
taxes attributable to the Underlying Properties. Since the oil and gas sales
attributable to the Royalty are based on an allocation formula that is dependant
on such factors as price and cost, including capital expenditures, the aggregate
sales amounts from the Underlying Properties may not provide a meaningful
comparison to sales attributable to the Royalty.
CALCULATION OF ROYALTY INCOME
Royalty income received by the Trust for the three months and nine months
ended September 30, 2002 and 2001, respectively, was computed as shown in the
following table:
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- --------------------------
2002 2001 2002 2001
----------- ----------- ----------- ------------
Gross proceeds of sales from the
Underlying Properties:
Gas proceeds.................... $27,127,920 $33,509,718 $76,613,158 $149,896,232
Oil proceeds.................... 490,483 516,124 1,400,519 1,794,169
Other........................... (2,443,923) -- (5,110,589) --
----------- ----------- ----------- ------------
Total........................... 25,174,490 34,025,842 72,903,088 151,690,401
----------- ----------- ----------- ------------
Less production costs:
Severance tax -- Gas............ 2,486,138 3,327,808 7,236,679 14,739,317
Severance tax -- Oil............ 40,929 43,939 114,457 162,751
Severance tax -- Other.......... -- -- -- --
Lease operating expense and
property tax.................. 3,787,473 3,951,053 11,733,774 11,207,821
Other........................... 3,037 5,000 18,037 45,000
Capital expenditures............ 2,124,551 8,068,949 16,817,707 21,471,867
----------- ----------- ----------- ------------
Total........................... 8,442,128 15,396,749 35,920,654 47,626,756
----------- ----------- ----------- ------------
Less excess production and
interest from prior year...... -- -- 2,270,173 --
----------- ----------- ----------- ------------
Net profits..................... 16,732,362 18,629,093 34,712,261 104,063,645
Net overriding royalty
interest...................... 75% 75% 75% 75%
----------- ----------- ----------- ------------
Royalty income.................. $12,549,272 $13,971,820 $26,034,196 $ 78,047,734
=========== =========== =========== ============
</Table>
EFFECTS OF SECURITIES REGULATION
As a publicly-traded trust listed on the New York Stock Exchange (the
"NYSE"), the Trust is and will continue to be subject to extensive regulation
under, among others, the Securities Act of 1933, the Exchange Act of 1934, the
rules and regulations of the NYSE and the Sarbanes-Oxley Act of 2002. Issuers
failing to comply with such authorities risk serious consequences, including
criminal as well as civil and administrative penalties. In most instances, these
laws, rules and regulations do not specifically address their applicability to
11
publicly-traded trusts, such as the Trust. In particular, the Sarbanes-Oxley Act
of 2002 provides for the adoption by the Securities and Exchange Commission (the
"Commission") of certain rules and regulations that may be impossible for the
Trust to literally satisfy because of its nature as a pass-through trust. For
example, the Commission is required to adopt rules and regulations pursuant to
the Sarbanes-Oxley Act of 2002 that would require a publicly-traded company's
board of directors, audit committee or executive directors (or similar body) to
act with respect to certain corporate governance matters. The Trust does not
have, nor does the indenture governing the Trust provide for, a board of
directors, an audit committee or any executive officers. Accordingly, the Trust
could not literally comply with such rules and regulations. It is the Trustee's
intention to follow the Commission's rulemaking closely, attempt to comply with
such rules and regulations and, where appropriate, request relief from these
rules and regulations. However, if the Trust is unable to comply with such rules
and regulations or to obtain appropriate relief, the Trust may be required to
expend as yet unknown but potentially material costs to amend the indenture that
governs the Trust to allow for compliance with such rules and regulations.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Trust has not entered into derivative financial instruments, derivative
commodity instruments or other similar instruments during the quarter ended
September 30, 2002. The Trust does not market the Trust gas, oil and/or natural
gas liquids. BROG is responsible for this marketing.
ITEM 4. CONTROLS AND PROCEDURES
The Trust maintains a system of disclosure controls and procedures that is
designed to provide reasonable assurance that information required to be
disclosed in the Trust's filings under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported, within the time periods specified
in the Commission's rules and forms. Due to the pass-through nature of the
Trust, BROG provides much of the information disclosed in this Form 10-Q and the
other periodic reports filed by the Trust with the Commission.
The Trustee receives periodic updates from BROG regarding activities
related to the Trust. Accordingly, the Trust's ability to timely report certain
information required to be disclosed in the Trust's periodic reports is
dependent on BROG's timely delivery of such information to the Trust. In order
to help ensure the accuracy and completeness of the information required to be
disclosed in the Trust's periodic reports, the Trust employs independent public
accountants, joint interest auditors, marketing consultants, attorneys and
petroleum engineers. These outside professionals assist the Trustee in reviewing
and compiling this information for inclusion in this Form 10-Q and the other
periodic reports provided by the Trust to the Commission.
The Trustee has evaluated the Trust's disclosure controls and procedures
within the 90 days prior to the filing of this Quarterly Report on Form 10-Q and
has determined that, subject to BROG's delivery of timely and accurate
information to the Trust, such disclosure controls and procedures are effective.
The Trustee has not reviewed the Trust's disclosure controls and procedures in
concert with management, a board of directors or an independent audit committee.
The Trust does not have, nor does the indenture governing the Trust provide for
officers, a board of directors or an independent audit committee.
Subsequent to the Trustee's evaluation, there were no significant changes
in internal controls or other factors that could significantly affect internal
controls, including any corrective actions with regard to significant
deficiencies and material weaknesses.
12
PART II
OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
SETTLEMENTS
As part of the September 4, 1996, settlement of the litigation filed by the
Trustee on June 4, 1992, against BROG and Southland Royalty Company, the Trust
was entitled to certain adjustments (the "Val Verde Credit") that represented
cost reductions favorable to the Trust in the charges for coal seam gas gathered
and treated on BROG's Val Verde system. The settlement provided that the Val
Verde Credit was applicable until the later of July 1, 2002 or until BROG no
longer owned the Val Verde facility. By correspondence dated July 15, 2002, BROG
notified the Trustee of the sale of the Val Verde facility to TEPPCO Partners,
L.P. effective July 1, 2002. Accordingly, effective July 1, 2002, the
calculation of net proceeds for gas gathered and treated at the Val Verde
facility will no longer include the Val Verde Credit. The total amount of the
Val Verde Credit for the twelve months ended October 31, 2001, was estimated by
the Trust's joint interest auditors as approximately $2,070,000. The loss of the
Val Verde Credit will result in increased costs allocated to the Trust for coal
seam gas gathered and treated on the Val Verde system and accordingly, will
decrease the royalty income received by the Trust.
An administrative claim was initiated on March 17, 1997 by the Mineral
Management Service of the United States Department of the Interior (the "MMS")
against BROG regarding a gas contract settlement dated March 1, 1990, between
BROG and certain other parties thereto. The claim alleged that additional
royalties were due on production from federal and Indian leases in the State of
New Mexico on properties burdened by the Trust. On December 3, 2001, BROG
settled this claim by paying the Jicarilla Apache Nation the sum of $2,853,974
and the MMS the sum of $1,224,043. MMS also retained certain overpayments by
BROG in the amount of $1,127,623 as part of the settlement. Certain properties
included in this settlement are burdened by the Trust. BROG has offset the
entire $2,853,974 Jicarilla component of the settlement against amounts
otherwise distributed in payment of the Royalty, but has not yet informed the
Trust of its proposal as to what portion, if any, of the $1,224,043 paid to the
MMS might be allocable to the Royalty. BROG has indicated that it does not
appear that any of the $1,127,623 in overpayments retained by the MMS is
attributable to the Trust.
In another proceeding involving BROG and the Jicarilla Apache Nation, the
MMS entered an Order to Perform on June 10, 1998, stating that, in valuing
production for royalty purposes, BROG must perform, among other things, a "dual
accounting" calculation (i.e., compute royalties on the greater of the value of
gas prior to processing or the combined value of processed residue gas and plant
products plus the value of any condensate recovered downstream without
processing). In December 2000, BROG and the Jicarilla Apache Nation entered into
a settlement resolving the issues associated with the dual accounting
calculation. Under the settlement, BROG paid $3,260,366 to the Jicarilla Apache
Nation. BROG has allocated $1,978,182 of the settlement payment to the Royalty.
BROG has indicated it will provide information identifying the Underlying
Properties affected by these settlements, as well as the Trust's share of these
settlements. Beginning in May 2002, BROG deducted the lesser of $1 million or
50% of the monthly net profits distribution from net profits distributions to
the Trust until an aggregate of $3,624,117 was deducted. BROG deducted $1
million from each of the monthly net profits distributions to the Trust in May,
June and July of 2002, and the balance in August of 2002. The Trust's legal and
joint interest auditing consultants will review the information to be provided
and advise the Trust as to the appropriateness of such deductions.
In June 2000, the Trust and BROG entered into a partial settlement of
claims relating to a gas imbalance with respect to production from mineral
properties currently operated by BROG. Under the terms of the partial
settlement, BROG paid the Trust $3,490,000 to settle the imbalance insofar as it
relates to some of the wells located on the subject properties. The remainder of
the imbalance is to be addressed through volume adjustments whereby the Trust's
net overriding royalty interest will be applied to 50% of the overproduced
parties' interest, on a monthly basis, until the imbalance is corrected. The
Trustee and its consultants remain
13
in communication with BROG in order to determine the estimated value of the
volume adjustments and the time during which the remainder of the imbalance will
be corrected. BROG indicates that the volume adjustment commenced in August
2000. The Trust's consultants continue to monitor those adjustments.
ADMINISTRATIVE PROCEEDINGS
The following information was provided to the Trust by BROG. Please note
that the proceedings described below apply to the collective interest of BROG
and the Trust. BROG is not able to estimate the amount of any potential loss to
the Trust in each of the outstanding proceedings, or the portion of any such
potential loss that would be allocated to the Royalty.
1. MMS PROCEEDINGS
Blanco Pool. This appeal arises from a MMS Demand Letter dated October 20,
1995, and bears MMS Appeal Docket No. MMS-95-0740. The demand letter challenges
the "valuation benchmark" utilized by BROG for gas sold by BROG from the "Blanco
Pool" during the audit period of January 1, 1989 through December 31, 1991. BROG
paid royalties on sales to its marketing affiliate based on "gross proceeds"
received by BROG from its affiliate. The demand letter states that BROG paid
incorrectly under MMS regulations. The MMS methodology in calculating the
amounts demanded does not attempt to trace resale proceeds. Instead, MMS'
auditors use published index prices at pipeline interconnect points in the San
Juan Basin as a proxy for actual comparable sales, and net out certain actual
costs to move the gas to those index points. While BROG had deducted prevailing
field transportation rates in computing its monthly prices in the San Juan
Basin, the auditors limited the deduction to the actual rate paid to El Paso
Natural Gas under a "backhaul" agreement. The demand letter directs BROG to pay
additional royalties of $518,304, to recalculate royalties in accordance with
the MMS' interpretation of the regulations and to pay the difference between
total royalty due and royalty paid.
Affiliate Proceeds Demand -- Conventional Gas. This appeal arises from a
MMS demand letter dated June 9, 1997, and bears MMS Appeal Docket No.
MMS-97-0168. The demand letter is a blanket demand relating to all of BROG's
non-coalbed methane gas production nationwide for the audit period of January 1,
1989 through December 31, 1994. The demand letter is based primarily on the MMS
theory that royalties are to be based on BROG's marketing affiliate gross
proceeds rather than BROG's gross proceeds (e.g. the affiliate resale proceeds
issue). The demand letter directs BROG to recalculate its royalties on these
sales using a netback calculation of the proceeds of the affiliate, and pay the
difference between total royalties due under such calculation and the royalties
actually paid by BROG. This demand letter is in furtherance of the demand letter
described in the prior paragraph.
Coalbed Methane. This appeal arises from a MMS demand letter dated October
28, 1996, and bears MMS Appeal Docket No. MMS-96-0437. The demand letter relates
to BROG's coalbed methane production from the Northeast Blanco Unit for the
audit period of May 1, 1990 through December 31, 1993, and from the San Juan
30-6 Unit for the audit period of January 1, 1989 through December 31, 1991.
Like the Blanco Pool demand letter, the demand letter does not attempt to trace
resale proceeds. The issues are whether MMS should bear its share of CO2
extraction costs and, if so, whether the costs should be based on market rates
or actual costs of the system, and whether MMS' share of transportation costs
(which MMS does not dispute it must bear) should be based on market rates or
actual costs of the system. BROG is directed to pay additional royalties of
$3,600,584 for underpayment of royalty for gas produced from the units mentioned
above, to recalculate royalties for gas produced from other federal leases in
accordance with MMS' interpretation of the regulations and to pay the difference
between total royalty due and royalty paid.
Due to the similarity of the claims in the Blanco Pool, Affiliate Proceeds
Demand and the Coal Bed Methane administrative appeals, to the claims in the
suits in the In re Natural Gas Royalties qui tam litigation described below, the
administrative appeals have been stayed by agreement with MMS pending the
resolution of the gas qui tam litigation, and settlement discussions between
BROG and the federal government in the gas qui tam litigation will, if
successful, include the settlement of each of the MMS Proceedings.
14
2. JICARILLA INDIAN TRIBE PROCEEDINGS
This appeal arises from an MMS Order to Perform dated June 10, 1998. The
Order to Perform states that, in valuing production for royalty purposes, BROG
must, among other things, perform a major portion analysis (i.e., calculate
value on the highest price paid or offered for a major portion of the gas
produced from the field where the leased lands are situated). BROG believes that
producers do not have access to prices received by other producers in a field,
so a major portion calculation must be done by MMS.
LITIGATION
1. GRYNBERG LITIGATION
In September 1998, BROG was advised by the United States Department of
Justice under an order of confidentiality that a lawsuit styled United States of
America ex rel Jack J. Grynberg v. Burlington Resources Oil & Gas, et al., Civil
Action No. 97-CV-189 and 190, United States District Court for the District of
Wyoming, had been filed under seal pursuant to the qui tam provisions of the
civil federal False Claims Act, and that seventy-seven similar cases had been
filed by the plaintiff against other companies. The complaint alleges that BROG
engaged in the mismeasurement of volumes and wrongful analysis of heating
content of natural gas and engaged in other activities, including the sale of
natural gas to affiliated companies, which resulted in the underpayment of
royalties to the United States. The government investigated the plaintiff's
claims, and in May 1999 issued notice that the United States would not intervene
in the case. The lawsuits have been unsealed by the court and the plaintiff has
served the complaint on BROG. This claim was subsequently consolidated into a
multi-district litigation proceeding as described in paragraph 2 below.
2. IN RE NATURAL GAS ROYALTIES QUI TAM LITIGATION
On March 28, 2000, the United States District Court for the Eastern
District of Texas, Lufkin Division, ordered that the first amended complaint in
the case of United States ex rel. M. Glenn Osterhoudt, III v. Amerada Hess, et
al., Civil Action No. 9:98CV101, in the United States District Court for the
Eastern District of Texas, Lufkin Division, and the second amended complaint in
the case of United States of America ex rel. Harrold E. (Gene) Wright v. Agip
Petroleum Burlington, et al., Civil Action No. C-5:96CV243 be unsealed and
served upon defendants, including BROG. In these lawsuits, the plaintiffs have
alleged violations of the civil False Claims Act. Plaintiffs contend that
defendants underpaid royalties on natural gas and natural gas liquids produced
on federal and Indian lands through the use of below-market prices, improper
deductions, improper measurement techniques and transactions with affiliated
companies. The United States has filed an intervention in these cases as to some
of the defendants, including BROG.
In July 2000, the United States District Court for the District of New
Mexico unsealed and BROG was served with the petition in United States of
America ex rel. Mark A. Perry v. BROG Resources, Inc., et al., Civil Action No.
9:00CV197, in the United States District Court for the District of New Mexico,
wherein plaintiff alleges violations of the civil False Claims Act. The
plaintiff claims that BROG understated the value of natural gas and natural gas
liquids produced on federal and Indian lands in connection with its computation
and reporting of royalty payments. The United States has elected to intervene in
this case, but a complaint has not been served upon BROG.
In October 2000, the federal Judicial Panel on Multidistrict Litigation
ordered that the Wright and Osterhoudt lawsuits be transferred to the United
State District Court for the District of Wyoming for inclusion with the Grynberg
lawsuit described in paragraph 1 above in multidistrict litigation proceedings.
A similar order was issued in December 2000 transferring the Perry lawsuit.
These cases have been consolidated for pre-trial proceedings in the matter
styled In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States
District Court for the District of Wyoming.
If successful, this litigation could result in a decrease in royalty income
received by the Trust. At this time, no estimate can be made as to the amount of
any potential loss in this litigation, or the portion of any such potential loss
that would be allocated to the Trust's interest. Any proposed allocation of loss
to the Trust will be reviewed by the Trust's consultants.
15
3. QUINQUE LITIGATION
In September 1999, BROG was served with a class action petition styled
Quinque Operating Burlington on behalf of Gas Producers v. Gas Pipelines, et
al., Case No. 99 C 30, in the District Court of Stevens County, Kansas, naming
certain of its current or former affiliates as defendants, along with hundreds
of other gas production and gas pipeline companies. The petition alleges that
the defendants engaged in the mismeasurement of volumes and wrongful analysis of
heating content of natural gas and engaged in other activities which resulted in
the underpayment of revenue owed to working interest owners, royalty interest
owners, overriding royalty interest owners and state taxing authorities. If
successful, this litigation could result in a decrease in royalty income
received by the Trust. At this time, no estimate can be made as to the amount of
any loss in this litigation, or the portion of any such potential loss that
would be allocated to the Trust. Any proposed allocation of loss to the Trust
will be reviewed by the Trust's consultants.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the special meeting of the Trust's Unit Holders held on September 30,
2002 (the "Special Meeting"), the Unit Holders appointed TexasBank to serve as
successor Trustee of the Trust, replacing Bank One, N.A. Of the 37,824,917 Units
present in person or by proxy at the Special Meeting, 35,174,563 Units voted in
favor of TexasBank, 2,384,335 Units voted against TexasBank and 266,019 Units
abstained.
At the Special Meeting, the Unit Holders also voted on various proposals to
amend the Trust's Royalty Trust Indenture (the "Indenture"). The Unit Holders
approved a proposal amending the Indenture to ensure accurate cross-references
to current legal authority, to delete references to contingent events that are
no longer applicable and to add a "force majeure" provision with the following
vote:
<Table>
<Caption>
VOTES FOR VOTES AGAINST ABSTENTIONS
- --------- ------------- -----------
34,993,385 2,458,248 373,284
</Table>
At the Special Meeting, the Unit Holders approved a proposal amending the
Indenture to clarify and expand certain provisions of the indemnification
provisions of the Indenture with the following vote:
<Table>
<Caption>
VOTES FOR VOTES AGAINST ABSTENTIONS
- --------- ------------- -----------
34,595,644 2,826,123 403,150
</Table>
At the Special Meeting, the Unit Holders approved a proposal amending the
Indenture to address the fees earned by the Trustee, the permitted investments
in which the Trustee may invest the Trust's assets, and the manner in which the
Trustee may dispose of assets of the Trust with the following vote:
<Table>
<Caption>
VOTES FOR VOTES AGAINST ABSTENTIONS BROKER NON-VOTES
- --------- ------------- ----------- ----------------
22,857,423 2,794,678 389,298 11,783,518
</Table>
At the Special Meeting, the Unit Holders voted on, but did not approve, an
amendment which would have expanded the types of proxies which are permissible
under the Indenture to include proxies granted by Unit Holders over the
telephone or electronically through the Internet (among other methods) with the
following vote. This proposal required the affirmative vote of at least 75% of
all the Units outstanding.
<Table>
<Caption>
VOTES FOR VOTES AGAINST ABSTENTIONS
- --------- ------------- -----------
34,871,743 2,581,052 372,122
</Table>
16
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits.
<Table>
(4)(a) Amended and Restated Royalty Trust Indenture, dated
September 30, 2002 (the original Royalty Trust Indenture
dated November 1, 1980, having been entered into between
Southland Royalty Company and The Fort Worth National Bank,
as Trustee), heretofore filed as Exhibit 99.2 to the Trust's
Current Report on Form 8-K, filed with the Securities and
Exchange Commission on October 1, 2002, is incorporated
herein by reference.
(4)(b) Net Overriding Royalty Conveyance from Southland Royalty
Company to The Fort Worth National Bank, as Trustee, dated
November 1, 1980 (without Schedules), heretofore filed as
Exhibit (4)(b) to the Trust's Annual Report on Form 10-K to
the Securities and Exchange Commission for the fiscal year
ended December 31, 1980, is incorporated herein by
reference.
(4)(c) Assignment of Net Overriding Royalty Interest (San Juan
Basin Royalty Trust), dated September 30, 2002, between Bank
One, N.A. and TexasBank (filed herewith).
</Table>
(b) Reports on Form 8-K.
The Trust filed a report on Form 8-K on August 15, 2002. In the report, the
Trust reported, under Item 9, that on August 14, 2002, it had submitted a
certification to the Securities and Exchange Commission, relating to the Trust's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, pursuant to
18 U.S.C. Section 1350, adopted pursuant to the Sarbanes-Oxley Act of 2002.
The Trust filed a report on Form 8-K on October 1, 2002. In the report, the
Trust reported, under Item 5, that on September 30, 2002, it had issued a press
release announcing that at the Special Meeting the Unit Holders had (a)
appointed TexasBank as the successor Trustee of the Trust and (b) approved three
separate groups of amendments to the San Juan Basin Royalty Trust Indenture.
17
SIGNATURES
Pursuant to the requirements 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.
TEXASBANK, AS TRUSTEE FOR THE
SAN JUAN BASIN ROYALTY TRUST
By /s/ LEE ANN ANDERSON
------------------------------------
Lee Ann Anderson
Vice President and Trust Officer
Date: November 14, 2002
(The Trust has no directors or executive officers.)
18
CERTIFICATION
I, Lee Ann Anderson, certify that:
1. I have reviewed this quarterly report on Form 10-Q of San Juan Basin
Royalty Trust, for which TexasBank acts as trustee;
2. Based on my knowledge, this quarterly 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 quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly 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 period presented in this quarterly
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 quarterly 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 quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly 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 quarterly 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.
In giving the certifications in paragraphs 4, 5 and 6 above, I have relied to
the extent I consider reasonable on information provided to me by Burlington
Resources Oil & Gas Company LP.
TEXASBANK, AS TRUSTEE FOR THE
SAN JUAN BASIN ROYALTY TRUST
By: /s/ LEE ANN ANDERSON
------------------------------------
Lee Ann Anderson
Vice President and Trust Officer
Date: November 14, 2002
19
INDEX TO EXHIBITS
<Table>
<Caption>
SEQUENTIALLY
EXHIBIT NUMBERED
NUMBER EXHIBIT PAGE
- ------- ------- ------------
(4)(a) Amended and Restated Royalty Trust Indenture, dated
September 30, 2002 (the original Royalty Trust Indenture
dated November 1, 1980 having been entered into between
Southland Royalty Company and The Fort Worth National Bank,
as Trustee), heretofore filed as Exhibit 99.2 to the Trust's
Current Report on Form 8-K filed with the Securities and
Exchange Commission on October 1, 2002, is incorporated
herein by reference.*
(4)(b) Net Overriding Royalty Conveyance from Southland Royalty
Company to The Fort Worth National Bank, as Trustee, dated
November 1, 1980 (without Schedules), heretofore filed as
Exhibit (4)(b) to the Trust's Annual Report on Form 10-K to
the Securities and Exchange Commission for the fiscal year
ended December 31, 1980, is incorporated herein by
reference.*
(4)(c) Assignment of Net Overriding Royalty Interest (San Juan
Basin Royalty Trust), dated September 30, 2002, between Bank
One, N.A. and TexasBank (filed herewith).*
</Table>
- ---------------
* A copy of this Exhibit is available to any Unit Holder, at the actual cost of
reproduction, upon written request to the Trustee, TexasBank, 2525 Ridgmar
Boulevard, Fort Worth, Texas 76116.