- --------------------------------------------------------------------------------
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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 JUNE 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>
BANK ONE, N.A., TRUST DEPARTMENT
P. O. BOX 2604
FORT WORTH, TEXAS 76113
(Address of principal executive offices)
(Zip Code)
TELEPHONE NUMBER 817/884-4630
(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 August 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 Bank One, N.A., 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 June 30,
2002, and the distributable income and changes in trust corpus for the
three-month periods and six-month periods ended June 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>
JUNE 30, DECEMBER 31,
2002 2001
----------- ------------
(UNAUDITED)
ASSETS
Cash and short-term investments............................. $ 4,066,375 $ 191,620
Net overriding royalty interest in producing oil and gas
properties (net of accumulated amortization of $95,796,483
and $95,415,779 at June 30, 2002 and December 31, 2001,
respectively)............................................. 36,354,315 37,859,749
----------- -----------
$40,420,690 $38,051,369
=========== ===========
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders........................ $ 3,951,517 $ 0
Cash reserves............................................... 114,858 191,620
Trust corpus -- 46,608,796 Units of beneficial interest
authorized and outstanding................................ 36,354,315 37,859,749
----------- -----------
$40,420,690 $38,051,369
=========== ===========
</Table>
CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ -------------------------
2002 2001 2002 2001
---------- ----------- ----------- -----------
Royalty income............................ $9,559,569 $26,585,943 $13,484,924 $64,075,915
Interest income........................... 2,104 72,624 2,851 131,692
Decrease in cash reserves................. -- -- 76,761 --
---------- ----------- ----------- -----------
9,561,673 26,658,567 13,564,536 64,207,607
General and administrative expenditures... 546,871 407,824 1,022,721 694,349
---------- ----------- ----------- -----------
Distributable income...................... $9,014,802 $26,250,743 $12,541,815 $63,513,258
========== =========== =========== ===========
Distributable income per Unit (46,608,796
Units).................................. $ .193414 $ .563215 $ .269087 $ 1.362688
========== =========== =========== ===========
</Table>
The accompanying notes to condensed financial statements are an integral part of
these statements.
2
CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- ---------------------------
2002 2001 2002 2001
----------- ------------ ------------ ------------
Trust corpus, beginning of period..... $37,479,045 $ 39,519,162 $ 37,859,749 $ 40,686,854
Amortization of net overriding royalty
interest............................ (1,124,730) (789,107) (1,505,434) (1,956,799)
Distributable income.................. 9,014,802 26,250,743 12,541,815 63,513,258
Distributions declared................ (9,014,802) (26,250,743) (12,541,815) (63,513,258)
----------- ------------ ------------ ------------
Total corpus, end of period........... $36,354,315 $ 38,730,055 $ 36,354,315 $ 38,730,055
=========== ============ ============ ============
</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
approximately $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. This credit 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, based upon the
number of Units
4
SAN JUAN BASIN ROYALTY TRUST
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
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 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 excess production costs. Of the total,
$1,702,630 is attributable to the Trust and has been deducted in determining
royalty income for the six months ended June 30, 2002.
5
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 JUNE 30, 2002 AND 2001
The Trust received royalty income of $9,559,569 and interest income of
$2,104 during the second quarter of 2002. After deducting administrative
expenses of $546,871, distributable income for the quarter was $9,014,802
($.193414 per Unit). In the second quarter of 2001, royalty income was
$26,585,943, interest income was $72,624, administrative expenses were $407,824
and distributable income was $26,250,743 ($.563215 per Unit). The tax credit
relating to production from coal seam and tight sand wells totaled approximately
$.03 per Unit for the second quarter of 2002 and $.04 per Unit for the second
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 second quarter of 2002
were as follows:
<Table>
April....................................................... $.009885
May......................................................... .098748
June........................................................ .084781
--------
Quarter Total............................................... $.193414
========
</Table>
The royalty income distributed in the second quarter of 2002 was lower than
that distributed in the second quarter of 2001, primarily due to a decrease in
the average gas price from $4.92 per Mcf for the second quarter of 2001 to $2.18
per Mcf for the second quarter of 2002. Interest earnings for the quarter ended
June 30, 2002, as compared to the quarter ended June 30, 2001, were lower,
primarily due to lower interest rates and a decrease in funds available for
investment. Administrative expenses were higher primarily as a result of
differences in timing in the receipt and payment of these expenses.
The capital costs attributable to the properties from which the Trust's 75%
net overriding royalty (the "Royalty") was carved (the "Underlying Properties")
for the second quarter of 2002 were reported by BROG as approximately $3.4
million. BROG's capital expenditure budget for the Underlying Properties for
2002 is an estimated $12.4 million. Capital expenditures were approximately $7.0
million for the second 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 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.
6
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 achieved favorable results
in this effort that resulted in natural gas production for calendar 2001
averaging 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 second
quarter of 2002 averaged approximately 125 MMcf per day.
BROG indicates its budget for 2002 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.
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. 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.
BROG has informed the Trust that lease operating expenses and property
taxes were $3,663,386 and $71,100 respectively, for the second quarter of 2002,
as compared to $3,810,641 and $83,751, respectively, for the second quarter of
2001.
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.
BROG has also informed the Trustee that 12 gross (5.16 net) conventional
wells, seven gross (1.93 net) conventional recompletions, three gross (2.29 net)
coal seam wells, and five gross (1.97 net) coal seam recompletions were
completed as of June 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.
During the second quarter of 2002, 65 gross (19.41 net) conventional wells,
four gross (0.22 net) conventional recompletions, six gross (2.98 net) coal seam
wells, and six gross (3.22 net) coal seam recompletions were in progress as of
June 30, 2002.
In the second quarter of 2001, 11 gross (5.69 net) conventional wells, five
gross (3.47 net) conventional recompletions, 35 gross (2.22 net) conventional
payadds, four gross (.03 net) coal seam recavitations and one gross (.88 net)
coal seam payadd were completed in the second quarter of 2001. A payadd is the
completion of an additional productive interval in an existing completed zone in
a well.
7
Royalty income for the quarter ended June 30, 2002 is associated with
actual gas and oil production during February 2002 through April 2002 from the
Underlying Properties. Gas and oil sales from the Underlying Properties for the
quarters ended June 30, 2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
----------- -----------
Gas:
Total sales (Mcf)........................................ 11,129,745 10,355,225
Mcf per day.............................................. 125,053 116,351
Average price (per Mcf).................................. $ 2.18 $ 4.92
Oil:
Total sales (Bbls)....................................... 28,204 24,830
Bbls per day............................................. 317 279
Average price (per Bbl).................................. $ 19.14 $ 24.60
</Table>
Gas and oil sales attributable to the Royalty for the quarters ended June
30, 2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
----------- -----------
Gas sales (Mcf)............................................ 5,252,787 5,874,782
Oil sales (Bbls)........................................... 13,935 14,203
</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 second quarter of 2002, average gas prices were less than half
the average prices reported during the second quarter of 2001. The average price
per barrel of oil during the second quarter of 2002 was $5.46 per barrel lower
than during the second 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.
Prior to April 1, 2002, all volumes of gas which were subject to the
Royalty (the "Trust gas") were sold under a contract dated November 10, 1999
between BROG and Duke Energy and Marketing L.L.C. This contract, as amended,
provided for the delivery of Trust gas at various delivery points over a period
commencing January 1, 2000, and ending March 31, 2002, and provided for the sale
of Trust gas at prices which fluctuated in accordance with published indices for
gas sold in the San Juan Basin of New Mexico. On March 13, 2002, BROG entered
into two contracts for the sale of Trust gas beginning April 1, 2002. 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.
SIX MONTHS ENDED JUNE 30, 2002 AND 2001
For the six months ended June 30, 2002, distributable income was
$12,541,815 ($.269807 per Unit) which was less than the $63,513,258 ($1.362688
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 half of 2002. Interest income for the six months ended June 30, 2002 was
$2,851 compared to $131,692 during the first six months of 2001. This decrease
is due to the timing of receipt of interest income, lower interest rates and
less cash to be invested. General and administrative expenses were $1,022,721
compared to $694,349 during the 2001 period primarily due to differences in
timing of the receipt and payment of these expenses, but
8
also as a result of expenses incurred in an arbitration proceeding involving
BROG and the Trust, undertaken to resolve certain gas marketing issues.
Capital expenditures incurred by BROG, attributable to the Underlying
Properties, for the first six months of 2002 amounted to approximately $14.7
million. Capital expenditures were approximately $13.4 million for the first six
months of 2001. Lease operating expenses and property taxes totaled $7,799,633
and $146,667, respectively, for the first six months of 2002 as compared to
$7,089,077 and $167,691, respectively, for the first six months of 2001.
BROG advised the Trustee that during the six months ended June 30, 2002, 55
gross (20.17 net) conventional wells were completed on the Underlying
Properties, and 25 gross (10.19 net) conventional wells were recompleted. Two
gross (1.74 net) miscellaneous capital projects, and 12 gross (4.1 net) coal
seam wells were completed during the fist six months of 2002. During the six
months ended June 30, 2001, 9 gross (2.11 net) coal seam recompletions and three
gross (0.90 net) miscellaneous coal seam capital projects were completed. One
gross (0.02 net) coal seam well was recavitated during the first six months of
2001.
Royalty income for the six months ended June 30, 2002 is associated with
actual gas and oil production during November 2001 through April 2002 from the
Underlying Properties. Gas and oil sales from the Underlying Properties for the
six months ended June 30, 2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
----------- -----------
Gas:
Total sales (Mcf)........................................ 22,600,721 21,619,935
Mcf per day.............................................. 124,866 119,447
Average price (per Mcf).................................. $ 2.19 $ 5.38
Oil:
Total Sales (Bbls)....................................... 49,658 49,639
Bbls per day............................................. 274 274
Average price (per Bbl).................................. $ 18.33 $ 25.75
</Table>
Gas and oil sales attributable to the Royalty for the six months ended June
30, 2002 and 2001 were as follows:
<Table>
<Caption>
2002 2001
--------- ----------
Gas sales (Mcf)............................................. 7,177,930 12,792,727
Oil sales (Bbls)............................................ 18,259 29,289
</Table>
During the first six months of 2002, gas and oil prices were lower than
during the first six months of 2001. 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.
9
CALCULATION OF ROYALTY INCOME
Royalty income received by the Trust for the three months and six months
ended June 30, 2002 and 2001, respectively, was computed as shown in the
following table:
<Table>
<Caption>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------- --------------------------
2002 2001 2002 2001
----------- ----------- ----------- ------------
Gross proceeds of sales from the
Underlying Properties:
Gas proceeds.................... $24,268,350 $50,937,406 $49,485,237 116,386,514
Oil proceeds.................... 539,877 610,706 910,026 1,278,045
Other........................... (2,666,666) -- (2,666,666) --
----------- ----------- ----------- ------------
Total........................... 22,141,561 51,548,112 47,728,597 117,664,559
----------- ----------- ----------- ------------
Less production costs:
Severance tax -- Gas............ 2,251,404 5,031,925 4,750,541 11,411,509
Severance tax -- Oil............ 37,575 54,843 73,529 118,664
Severance tax -- Other.......... -- 148 -- 148
Lease operating expense and
property tax.................. 3,734,486 3,894,392 7,946,300 7,256,768
Other........................... 5,000 40,000 15,000 40,000
Capital expenditures............ 3,367,004 7,078,879 14,693,156 13,402,918
----------- ----------- ----------- ------------
Total........................... 9,395,469 16,100,187 27,478,526 32,230,007
----------- ----------- ----------- ------------
Less excess production and
interest from prior year...... -- -- 2,270,173 --
----------- ----------- ----------- ------------
Net profits..................... 12,746,092 35,447,925 17,979,898 85,434,552
Net overriding royalty
interest...................... 75% 75% 75% 75%
----------- ----------- ----------- ------------
Royalty income.................. $ 9,559,569 $26,585,944 $13,484,924 $ 64,075,914
=========== =========== =========== ============
</Table>
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 June
30, 2002. The Trust does not market the Trust gas, oil and/or natural gas
liquids. BROG is responsible for such marketing.
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
10
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 proposes to 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 will pay $3,260,366 to the Jicarilla
Apache Nation. BROG has proposed to allocate $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. BROG has proposed to deduct the lesser of $1 million or 50% of the
monthly net profits distribution from upcoming net profits distributions to the
Trust commencing May 2002 until an aggregate of $3,624,117 has been deducted.
BROG deducted $1 million from each of the monthly net profits distributions to
the Trust in May and June 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
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. 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
11
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, the 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 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.
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,
12
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.
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.
13
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits.
<Table>
(4)(a) San Juan Basin Royalty Trust Indenture dated November 3,
1980, between Southland Royalty Company (now Burlington
Resources Oil & Gas Company LP) and The Fort Worth National
Bank (now Bank One, N.A.), as Trustee, heretofore filed as
Exhibit (4)(a) 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)(b) Net Overriding Royalty Conveyance from Southland Royalty
Company (now Burlington Resources Oil & Gas Company LP) to
The Fort Worth National Bank (now Bank One, N.A.), as
Trustee, dated November 3, 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.
</Table>
(b) Reports on Form 8-K.
The Trust filed a report on Form 8-K on June 12, 2002. In the report, the
Trust reported, under Item 5, that on June 11, 2002, it had (a) submitted a
notice to the Unit holders of the Trust of the Trustee's resignation and (b)
issued a press release announcing that the Trustee had submitted notice of its
resignation to the Unit holders.
14
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.
BANK ONE, N.A., AS TRUSTEE FOR THE
SAN JUAN BASIN ROYALTY TRUST
By /s/ LEE ANN ANDERSON
------------------------------------
Lee Ann Anderson
Vice President
Date: August 14, 2002
(The Trust has no directors or executive officers.)
15
INDEX TO EXHIBITS
<Table>
<Caption>
SEQUENTIALLY
EXHIBIT NUMBERED
NUMBER DESCRIPTION PAGE
- ------- ----------- ------------
(4)(a) San Juan Basin Royalty Trust Indenture dated November 3,
1980, between Southland Royalty Company (now Burlington
Resources Oil & Gas Company LP) and The Fort Worth National
Bank (now Bank One, N.A.), as Trustee, heretofore filed as
Exhibit (4)(a) 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)(b) Net Overriding Royalty Conveyance from Southland Royalty
Company (now Burlington Resources Oil & Gas Company LP) to
The Fort Worth National Bank (now Bank One, N.A.), as
Trustee, dated November 3, 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.*
</Table>
- ---------------
* A copy of this Exhibit is available to any Unit holder, at the actual cost of
reproduction, upon written request to the Trustee, Bank One, N.A., P.O. 2604,
Fort Worth, Texas 76113.