- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
<Table>
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
</Table>
COMMISSION FILE NO. 1-8032
SAN JUAN BASIN ROYALTY TRUST
(Exact name of registrant as specified in the Amended and Restated San Juan
Basin Royalty Trust Indenture)
<Table>
TEXAS 75-6279898
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
TEXASBANK, TRUST DEPARTMENT
2525 RIDGMAR BOULEVARD,
SUITE 100
FORT WORTH, TEXAS 76116
(Address of principal executive offices) (Zip Code)
</Table>
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 [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
Number of Units of beneficial interest outstanding at May 14,
2003: 46,608,796
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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. In
accordance with Securities and Exchange Commission Staff Accounting Bulletin No.
47, released September 16, 1982, the Trust continues to prepare its financial
statements in a manner that differs from accounting principals generally
accepted in the United States of America ("GAAP"); such presentation is
customary to other royalty trusts. 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/A for
the year ended December 31, 2002. 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 March 31, 2003, and the distributable income and changes in
trust corpus for the three-month periods ended March 31, 2003 and 2002 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>
MARCH 31, DECEMBER 31,
2003 2002
----------- ------------
(UNAUDITED)
ASSETS
Cash and short-term investments............................. $ 9,401,502 $ 4,274,790
Net overriding royalty interest in producing oil and gas
properties (net of accumulated amortization of
$100,623,167 and $99,577,622 at March 31, 2003 and
December 31, 2002, respectively).......................... 32,652,361 33,697,906
----------- -----------
$42,053,863 $37,972,696
=========== ===========
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit Holders........................ $ 9,286,644 $ 4,159,932
Cash reserves............................................... 114,858 114,858
Trust corpus -- 46,608,796 Units of beneficial interest
authorized and outstanding................................ 32,652,361 33,697,906
----------- -----------
$42,053,863 $37,972,696
=========== ===========
</Table>
CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED
MARCH 31,
------------------------
2003 2002
----------- ----------
Royalty income.............................................. $19,911,068 $3,925,355
Interest income............................................. 7,453 746
Decrease in cash reserves................................... -- 76,761
----------- ----------
19,918,521 4,002,862
General and administrative expenditures..................... 420,374 475,850
----------- ----------
Distributable income........................................ $19,498,147 $3,527,012
=========== ==========
Distributable income per Unit (46,608,796 Units)............ $ 0.418337 $ 0.075673
=========== ==========
</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 (UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED MARCH 31,
----------------------------
2003 2002
------------- ------------
Trust corpus, beginning of period........................... $ 33,697,906 $37,859,749
Amortization of net overriding royalty interest............. (1,045,545) (380,704)
Distributable income........................................ 19,498,147 3,527,012
Distributions declared...................................... (19,498,147) (3,527,012)
------------ -----------
Total corpus, end of period................................. $ 32,652,361 $37,479,045
============ ===========
</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
("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 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 instead of as an expense. 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 2002, this tax credit was
approximately $1.09 per MMBtu. The Trust also receives production from wells
producing from a tight sands formation, which likewise 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. However, these
wells must have been drilled after November 5, 1990, or must have been 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. Unlike the
credit for coal seam gas, the credit for tight formation gas is not adjusted for
inflation, so the credit remains fixed at .517241 per MMBtu. For qualifying
production of the Trust, each Unit Holder must determine, from the tax
information the Unit Holder receives from the
4
SAN JUAN BASIN ROYALTY TRUST
NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
Trust, its pro rata share of such production 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 the Unit Holder's own income
tax liability, but such credit may not reduce the Unit Holder's regular tax
liability (after the foreign tax credit and certain other nonrefundable credits)
below its tentative 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.
Congress is considering extending the Section 29 credit beyond its December
31, 2002 expiration date, and the creation of a similar tax credit for new
production. Unless new legislation is passed, extending the Section 29 on
existing eligible production or allowing for a credit on eligible new
production, there will be no further Section 29 credit on the Trust's production
sold in the year 2003 or later years.
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 will seek certification of all qualified wells and that two additional
wells were certified in 2002.
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 Trust is 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 will 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
5
SAN JUAN BASIN ROYALTY TRUST
NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
excess production costs. Of the total, $1,702,630 is attributable to the Trust
and was deducted in determining first quarter 2002 royalty income.
6. SUBSEQUENT EVENTS
As part of a settlement between BROG and the Mineral Management Service of
the United States Department of the Interior, $901,776 was deducted from the
April 2003 royalty payment. This represents the Trust's 75% interest of the
total settlement.
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 MARCH 31, 2003 AND 2002
The Trust received royalty income of $19,911,068 and interest income of
$7,453 during the first quarter of 2003. There was no change in cash reserves.
After deducting administrative expenses of $420,374, distributable income for
the quarter was $19,498,147 ($.418337 per Unit). In the first quarter of 2002,
royalty income was $3,925,355, interest income was $746, cash reserves decreased
$76,761, administrative expenses were $475,850 and distributable income was
$3,527,012 ($.075673 per Unit). The tax credit relating to production from coal
seam and tight sand wells sold before January 1, 2003, totaled approximately .03
per Unit for the first quarter of 2003 and $.01 per Unit for the first quarter
of 2002. For further information concerning this tax credit, Unit Holders should
refer to the Trust's Annual Report for 2002. Based on 46,608,796 Units
outstanding, the per Unit distributions during the first quarter of 2003 were as
follows:
<Table>
January..................................................... $.100682
February.................................................... .118408
March....................................................... .199247
--------
Quarter Total............................................... $.418337
========
</Table>
The royalty income distributed in the first quarter of 2003 was higher than
that distributed in the first quarter of 2002, primarily due to an increase in
the average gas price from $2.20 per Mcf for the first quarter of 2002 to $3.51
per Mcf for the first quarter of 2003 and decreased capital expenditures.
Interest earnings for the quarter ended March 31, 2003, as compared to the
quarter ended March 31, 2002, were higher, primarily due to an increase in funds
available for investment. Administrative expenses were lower primarily as a
result of differences in timing in the receipt and payment of these expenses but
also because administrative expenses in the first quarter of 2002 included
expenses incurred in an arbitration proceeding involving BROG and the Trust
undertaken to resolve certain gas marketing issues.
The capital costs attributable to the properties from which the Trust's 75%
net overriding royalty ("Royalty") was carved (the "Underlying Properties") for
the first quarter of 2003 were reported by BROG as approximately $6.6 million.
BROG's capital expenditure budget for the Underlying Properties for 2003 is
estimated at $14.2 million, however, BROG reports that based on its actual
capital requirements, its mix of projects, and swings in the price of natural
gas, the actual capital expenditures for 2003 could range from $10 million to
$22 million. Capital expenditures were approximately $11.3 million for the first
quarter of 2002. In 2002, approximately $21.5 million in capital expenditures
were deducted in calculating the Royalty. In February 2003, BROG informed the
Trust that for 2003 it anticipates 351 projects, including the drilling of 38
new wells to be operated by BROG and 26 new wells to be operated by third
parties. Of the new BROG operated wells, 14 are projected to be conventional
wells completed in the Pictured Cliffs, Mesaverde and/or
7
Dakota formations, and the remaining 24 are projected as coal seam wells
completed in the Fruitland Coal formation. A total of 21 of the new wells
operated by third parties are projected to be conventional wells and the
remaining five are to be coal seam wells. BROG projects approximately $10.6
million to be spent on the new wells, and $3.6 million to be expended in working
over existing wells and in the maintenance and improvement of production
facilities.
BROG indicates its budget for 2003 reflects continued, significant
developments in which the Trust's net overriding royalty interest is relatively
high, as well as a sustained focus in conventional formations, including infill
drilling to the Mesaverde and Dakota formations, development of the Fruitland
Coal formation and multiple formation completions.
BROG previously informed the Trust that increases in its capital program,
particularly in 2000 through 2002, 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 2002 averaged
approximately 127 MMcf per day, as compared to average production of
approximately 121 MMcf per day for calendar 2001 and 116 MMcf per day for
calendar 2000. BROG has reported that natural gas production for the first
quarter of 2003 averaged approximately 126 MMcf per day.
In October 2002, the New Mexico Oil Conservation Division approved reduced,
160-acre spacing in selected portions of the Fruitland Coal formation. BROG has
informed the Trust that, principally as a result of this approval, its budget
for 2003 reflects a focus on the Fruitland Coal formation. In February 2002,
BROG informed the Trust that the New Mexico Oil Conservation Division had
approved plans for 80-acre infill drilling of the Dakota formation in the San
Juan Basin. The New Mexico Oil Conservation 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. Eighty-acre
spacing has been permitted in the Mesaverde formation since 1997.
BROG has informed the Trust that lease operating expenses and property
taxes were $3,921,567 and $136,250 respectively, for the first quarter of 2003,
as compared to $4,136,247 and $75,567, respectively, for the first quarter of
2002.
The war in Iraq has increased the volatility in prices for oil and gas. It
is unclear what effect the war in Iraq will have on the net proceeds received by
the Trust and, accordingly, distributable income.
BROG has informed the Trustee that during the first quarter of 2003, two
gross (0.88 net) coal seam miscellaneous projects, seven gross (0.87 net) coal
seam wells, three gross (0.94 net) miscellaneous capital projects, nine gross
(6.56 net) conventional wells, 19 gross (0.92 net) payadds, and five gross (3.21
net) restimulations were completed on the Underlying Properties.
Twenty-seven gross (9.53 net) coal seam wells, one gross (0.002 net)
recavitation, four gross (0.14 net) recompletions, 25 gross (13.02 net)
conventional wells, 27 gross (2.52 net) payadds, 14 gross (4.55 net)
recompletions and 26 gross (17.56 net) restimulations were in progress at March
31, 2003.
There were 43 gross (15.01 net) conventional wells, 18 gross (8.26 net)
conventional recompletions, two gross (1.74 net) miscellaneous capital projects,
nine gross (1.81 net) coal seam wells, three gross (0.90 net) miscellaneous coal
seam capital projects, one gross (0.02 net) coal seam recavitation, and four
gross (0.14 net) coal seam recompletions completed as of March 31, 2002.
Sixty-four gross (13.23 net) conventional wells, 25 gross (7.32 net)
conventional recompletions, five gross (0.51 net) miscellaneous capital
projects, 10 gross (0.50 net) restimulations and five gross (2.73 net) payadds
were in progress as of March 31, 2002. Seven gross (4.07 net) coal seam wells,
nine gross (5.18 net) coal seam recompletions, one gross (0.04 net)
miscellaneous coal seam capital project, and one gross (0.007 net) coal seam
restimulation were in progress as of March 31, 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 production interval in an existing completed zone in a well.
8
During the first quarter of 2002, 43 gross (15.01 net) conventional wells,
18 gross (8.26 net) conventional recompletions, two gross (1.74 net)
miscellaneous capital projects, nine gross (1.81 net) coal seam wells, three
gross (0.90 net) miscellaneous coal seam capital projects, one gross (0.02 net)
coal seam recavitation, and four gross (0.14 net) coal seam recompletions were
completed as of March 31, 2002. Sixty-four gross (13.23 net) conventional wells,
25 gross (7.32 net) conventional recompletions, five gross (0.51 net)
miscellaneous capital projects, 10 gross (0.50 net) restimulations and five
gross (2.73 net) payadds were in progress as of March 31, 2002. Seven gross
(4.07 net) coal seam wells, nine gross (5.18 net) coal seam recompletions, one
gross (0.04 net) miscellaneous coal seam capital project, and one gross (0.007
net) coal seam restimulation were in progress as of March 31, 2002.
Royalty income for the quarter ended March 31, 2003 is associated with
actual gas and oil production during November 2002 through January 2003 from the
Underlying Properties. Gas and oil sales from the Underlying Properties for the
quarters ended March 31, 2003 and 2002 were as follows:
<Table>
<Caption>
2003 2002
----------- -----------
Gas:
Total sales (Mcf)........................................ 11,637,548 11,470,975
Mcf per day.............................................. 126,495 124,685
Average price (per Mcf).................................. $ 3.51 $ 2.20
Oil:
Total sales (Bbls)....................................... 16,107 23,454
Bbls per day............................................. 175 255
Average price (per Bbl).................................. $ 24.44 $ 15.78
</Table>
Gas and oil sales attributable to the Royalty for the quarters ended March
31, 2003 and 2002 were as follows:
<Table>
Gas sales (Mcf)............................................. 6,151,128 1,925,143
Oil sales (Bbls)............................................ 8,339 4,324
</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 first quarter of 2003, average gas prices were $1.31 higher than
the average prices reported during the first quarter of 2002. The average price
per barrel of oil during the first quarter of 2003 was $8.66 per barrel higher
than that received for the first quarter of 2002 due to increases 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
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 two year period ending March 31, 2004, and from year-to-year
thereafter until terminated by either party on twelve months notice, and (iii)
for 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. Neither party to
either of the two contracts elected to give the twelve months notice required to
terminate the contracts effective March 31, 2004, and accordingly, the term of
both contracts has been extended through March 31, 2005. Unit Holders are
referred to Note 6 of the Notes to Financial Statements in the Trust's 2002
Annual Report for further information concerning the marketing of gas produced
from the Underlying Properties. Prior to April 1, 2002, the Trust gas was sold
under a contract dated November 10, 1999 between BROG and Duke Energy and
Marketing L.L.C.
9
Confidentiality agreements with purchasers of gas produced from the
Underlying Properties prohibit public disclosure of certain terms and conditions
of gas sales contracts with those entities, including specific pricing terms,
gas receipt points, etc. Such disclosure could compromise the ability to compete
effectively in the marketplace for the sale of gas produced from the Underlying
Properties.
CALCULATION OF ROYALTY INCOME
Royalty income received by the Trust for the three months ended March 31,
2003 and 2002, respectively, was computed as shown in the following table:
<Table>
<Caption>
2003 2002
----------- -----------
Gross proceeds of sales from the Underlying Properties:
Gas proceeds............................................... $40,863,040 $25,216,887
Oil proceeds............................................... 393,663 370,150
----------- -----------
Total...................................................... 41,256,703 25,587,037
----------- -----------
Less production costs:
Severance tax -- Gas....................................... 4,037,766 2,499,137
Severance tax -- Oil....................................... 34,209 35,954
Lease operating expense and property tax................... 4,057,817 4,211,814
Other...................................................... 15,000 10,000
Capital expenditures....................................... 6,563,820 11,326,153
----------- -----------
Total...................................................... 14,708,612 18,083,058
----------- -----------
Less excess production and interest from prior year........ -- 2,270,173
----------- -----------
Net profits................................................ 26,548,091 5,233,806
Net overriding royalty interest............................ 75% 75%
----------- -----------
Royalty income............................................. $19,911,068 $ 3,925,355
=========== ===========
</Table>
CONTRACTUAL OBLIGATIONS
Under the Trust's indenture, the Trustee is entitled to an administrative
fee for its administrative services and the preparation of quarterly and annual
statements of: (i) 1/20 of 1% of the first $100 million of the annual gross
revenue of the Trust, and 1/30 of 1% of the annual gross revenue of the Trust in
excess of $100 million and (ii) the Trustee's standard hourly rates for time in
excess of 300 hours annually. Beginning January 1, 2003, in no case will the
administrative fee due under items (i) and (ii) above be less than $36,000 per
year (as adjusted annually to reflect the increase (if any) in the Producers
Price Index as published by the U.S. Department of Labor, Bureau of Labor
Statistics).
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 Securities 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 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 "SEC") 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 SEC 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
10
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 SEC'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.
CRITICAL ACCOUNTING POLICIES
In accordance with the Commission's staff accounting bulletins and
consistent with other royalty trusts, 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
BROG to the Trustee for the Trust.
- 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 Royalty 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 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 instead of as an expense.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Trust invests in no derivative financial instruments, and has no
foreign operations or long-term debt instruments. 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 Unit Holders 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 Unit Holders to any foreign currency related market risk. The Trust
does not market the Trust gas, oil and/or natural gas liquids. BROG is
responsible for such 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. Disclosure controls and procedures include
controls and procedures designed to ensure that information required to be
disclosed by the Trust is accumulated and communicated by BROG to the Trustee
and its employees who participate in the preparation of the Trust's periodic
reports as appropriate to allow timely decisions regarding required disclosure.
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 SEC.
11
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 SEC.
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 Trust Indenture 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.
PART II
OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
SETTLEMENTS
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 Royalty. BROG previously offset
the entire $2,853,974 Jicarilla component of the settlement against amounts
otherwise distributed in payment of the Royalty, and deducted $901,776 from the
April 2003 distribution to the Trust as the Trust's 75% portion of the remaining
$1,224,043 component of the settlement, slightly reduced by agreement of the
parties. 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 Royalty.
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 Underlying Properties. The remainder
of the imbalance is to be addressed through volume adjustments whereby the
Trust's Royalty will be increased by the proceeds from 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. 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.
12
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 CO(2)
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 Coalbed Methane administrative appeals, to the claims in the
suits in the In re Natural Gas Royalties qui tam litigation described below,
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.
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.
13
LITIGATION
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 below.
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 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.
QUINQUE LITIGATION
In September 1999, BROG was served with a class action petition styled
Quinque Operating Company 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. On February 21, 2002, the
District Court granted leave for plaintiffs to file a third amended class action
petition substituting in new class representative plaintiffs thereby changing
14
the style of the case to Will Price, Stixon Petroleum, Inc. and Thomas F. Boles
on behalf of Gas Producers v. Gas Pipelines, et al., Case No. 99 C 30, in the
District Court of Stevens County, Kansas. 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 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 of the Trust's
Current Report on Form 8-K filed with the SEC 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 3, 1980 (without Schedules), heretofore filed as
Exhibit 4(b) to the Trust's Annual Report on Form 10-K filed
with the SEC for the fiscal year ended December 31, 1980, is
incorporated herein by reference.*
(4)(c) Assignment of Net Overriding Interest (San Juan Basin
Royalty Trust), dated September 30, 2002, between Bank One,
N.A. and TexasBank heretofore filed as Exhibit 4(c) to the
Trust's Quarterly Report on Form 10-Q with the SEC for the
quarter ended September 30, 2002, is incorporated herein by
reference.*
10(a) Indemnification Agreement, dated May 13, 2003, with
effectiveness as of July 30, 2002 by and between Lee Ann
Anderson and San Juan Basin Royalty Trust.**
</Table>
- ---------------
* A copy of this Exhibit is available to any Unit Holder (free of charge) upon
written request to the Trustee, TexasBank, 2525 Ridgmar Boulevard, Suite 100,
Fort Worth, Texas 76116.
** Filed herewith.
(b) Reports on Form 8-K.
The Trust filed a report on Form 8-K on February 25, 2003. In the report,
the Trust reported, under Item 5, that on February 10, 2003, it had issued a
press release announcing the capital project plan for 2003 as delivered to it by
BROG as well as revisions to the 2002 capital budget estimate.
15
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: May 15, 2003
(The Trust has no directors or executive officers.)
16
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: May 15, 2003
17
INDEX TO EXHIBITS
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
(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 of the Trust's
Current Report on Form 8-K filed with the SEC 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 3, 1980 (without Schedules), heretofore filed as
Exhibit 4(b) to the Trust's Annual Report on Form 10-K filed
with the SEC for the fiscal year ended December 31, 1980, is
incorporated herein by reference.*
(4)(c) Assignment of Net Overriding Interest (San Juan Basin
Royalty Trust), dated September 30, 2002, between Bank One,
N.A. and TexasBank heretofore filed as Exhibit 4(c) to the
Trust's Quarterly Report on Form 10-Q with the SEC for the
quarter ended September 30, 2002, is incorporated herein by
reference.*
10(a) Indemnification Agreement, dated May 13, 2003, with
effectiveness as of July 30, 2002 by and between Lee Ann
Anderson and San Juan Basin Royalty Trust.**
</Table>
- ---------------
* A copy of this Exhibit is available to any Unit Holder (free of charge) upon
written request to the Trustee, TexasBank, 2525 Ridgmar Boulevard, Suite 100,
Fort Worth, Texas 76116.
** Filed herewith.