<PAGE> 1
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998,
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-8032
SAN JUAN BASIN ROYALTY TRUST
(Exact name of registrant as specified in the
San Juan Basin Royalty Trust Indenture)
<TABLE>
<S> <C>
TEXAS 75-6279898
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
BANK ONE, TEXAS, N.A. 76113
CORPORATE TRUST DEPARTMENT (Zip Code)
P.O. BOX 2604
FORT WORTH, TEXAS
(Address of principal executive officers)
</TABLE>
(817) 884-4630
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
------------------- ------------------------
<S> <C>
Units of Beneficial Interest New York Stock Exchange
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
NONE
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
At March 24, 1999, there were 46,608,796 Units of Beneficial Interest of
the Trust outstanding with an aggregate market value on that date of
$308,783,274.
DOCUMENTS INCORPORATED BY REFERENCE
"Units of Beneficial Interest" at page 1; "Description of the Properties"
at pages 5 and 6; "Trustee's Discussion and Analysis" at pages 7 and 8; "Results
of the 4th Quarters of 1998 and 1997" at page 9; and "Statements of Assets,
Liabilities and Trust Corpus," "Statements of Distributable Income," "Statements
of Change in Trust Corpus," "Notes to Financial Statements," and "Independent
Auditor's Report" at page 10 et seq., in registrant's Annual Report to Unit
holders for fiscal year ended December 31, 1998 are incorporated herein by
reference for Item 2 (Properties), Item 3 (Legal Proceedings), Item 5 (Market
for Units of the Trust and Related Security Holder Matters), Item 7
(Management's Discussion and Analysis of Financial Condition and Results of
Operation) and Item 8 (Financial Statements and Supplementary Data) of Part II
of this Report.
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<PAGE> 2
PART I
ITEM 1. BUSINESS
The San Juan Basin Royalty Trust (the "Trust") is an express trust created
under the laws of the state of Texas by the "San Juan Basin Royalty Trust
Indenture" (the "Trust Indenture") entered into on November 3, 1980, between
Southland Royalty Company ("Southland Royalty") and The Fort Worth National
Bank, a banking association organized under the laws of the United States, as
Trustee. The Trustee is now Bank One, Texas, N.A. The principal office of the
Trust (sometimes referred to herein as the "Registrant") is located at 500
Throckmorton Street, Fort Worth, Texas 76102, Attention: Corporate Trust
Department (telephone number 817/884-4630).
On October 23, 1980, the stockholders of Southland Royalty approved and
authorized that company's conveyance of a net overriding royalty interest
(equivalent to a net profits interest) to the Trust for the benefit of the
stockholders of Southland Royalty of record at the close of business on the date
of the conveyance consisting of a 75% net overriding royalty interest carved out
of that company's oil and gas leasehold and royalty interests in the San Juan
Basin of northwestern New Mexico. The conveyance of this interest (the
"Royalty") was made on November 3, 1980, effective as to production from and
after November 1, 1980 at 7:00 A.M.
The Royalty was carved out of and now burdens those properties and
interests as more particularly described under "Item 2. Properties" herein.
The Royalty constitutes the principal asset of the Trust and the beneficial
interests in the Royalty are divided into that number of Units of Beneficial
Interest (the "Units") of the Trust equal to the number of shares of the common
stock of Southland Royalty outstanding as of the close of business on November
3, 1980. Each stockholder of Southland Royalty of record at the close of
business on November 3, 1980, received one Unit for each share of the common
stock of Southland Royalty then held.
The function of the Trustee is to collect the income attributable to the
Royalty, to pay all expenses and charges of the Trust, and then distribute the
remaining available income to the Unit holders. The Trust is not empowered to
carry on any business activity and has no employees, all administrative
functions being performed by the Trustee.
In 1985, Southland Royalty became a wholly-owned subsidiary of Burlington
Northern Inc. ("BNI"). In 1988, BNI transferred its natural resource operations
to Burlington Resources Inc. ("BRI") as a result of which Southland Royalty
became a wholly-owned indirect subsidiary of BRI. As a result of these
transactions, El Paso Natural Gas Company ("El Paso"), Meridian Oil, Inc.
("MOI") and Meridian Oil Trading Inc. ("MOTI") also became indirect subsidiaries
of BRI. Effective January 1, 1996, Southland Royalty, a wholly-owned subsidiary
of MOI, was merged with and into MOI, by which action the separate corporate
existence of Southland Royalty ceased and MOI survived and succeeded to the
ownership of all of the assets, has the rights, powers and privileges and
assumed all of the liabilities and obligations of Southland Royalty. Subsequent
to the merger, MOI changed its name to Burlington Resources Oil & Gas Company
("BROG").
The term "net proceeds" as used in the November 3, 1980 conveyance means
the excess of "gross proceeds" received by BROG during a particular period over
"production costs" for such period. "Gross proceeds" means the amount received
by BROG (or any subsequent owner of the interests from which the Royalty was
carved) from the sale of the production attributable to the interests from which
the Royalty was carved (the "Underlying Properties"), subject to certain
adjustments. "Production costs" generally means costs incurred on an accrual
basis by BROG in operating its properties and interests out of which the Royalty
was carved, including both capital and non-capital costs. For example, these
costs include development drilling, production and processing costs, applicable
taxes, and operating charges. If production costs exceed gross proceeds in any
month, the excess is recovered out of future gross proceeds prior to the making
of further payment to the Trust, but the Trust is not otherwise liable for any
production costs or other costs or liabilities attributable to these properties
and interests or the minerals produced therefrom. If at any time the Trust
receives more than the amount due under the Royalty, it shall not be obligated
to return such overpayment,
1
<PAGE> 3
but the amounts payable to it for any subsequent period shall be reduced by such
amount, plus interest, at a rate specified in the conveyance.
Certain of the Underlying Properties are operated by BROG with the
obligation to conduct its operations in accordance with reasonable and prudent
business judgment and good oil and gas field practices. As operator, BROG has
the right to abandon any well when in its opinion such well ceases to produce or
is not capable of producing oil and gas in paying quantities. BROG also is
responsible, to the extent it has the legal right to do so for marketing the
production from such properties, either under existing sales contracts or under
future arrangements at the best prices and on the best terms it shall deem
reasonably obtainable in the circumstances. As a result of the settlement of the
Litigation (as hereinafter defined), agreement was reached, among other things,
regarding the marketing of such production. See Note 5 of Notes to Financial
Statements incorporated herein by reference. BROG also has the obligation to
maintain books and records sufficient to determine the amounts payable to the
Trustee. BROG, however, can sell its interest in the Underlying Properties.
Proceeds from production in the first month are generally recovered by BROG
in the second month, the net proceeds attributable to the Royalty are paid by
BROG to the Trustee in the third month and distribution by the Trustee to the
Unit holders is made in the fourth month. The identity of Unit holders entitled
to a distribution will generally be determined as of the last business day of
each calendar month (the "monthly record date"). The amount of each monthly
distribution will generally be determined and announced ten days before the
monthly record date. Unit holders of record as of the monthly record date will
be entitled to receive the calculated monthly distribution amount for each month
on or before ten business days after the monthly record date. The aggregate
monthly distribution amount is the excess of (i) net revenues from the Trust
properties, plus any decrease in cash reserves previously established for
contingent liabilities and any other cash receipts of the Trust over (ii) the
expenses and payments of liabilities of the Trust plus any net increase in cash
reserves for contingent liabilities.
Cash being held by the Trustee as a reserve for liabilities or
contingencies (which reserves may be established by the Trustee in its
discretion) or pending distribution is placed, in the Trustee's discretion, in
obligations issued by (or unconditionally guaranteed by) the United States or
any agency thereof, repurchase agreements secured by obligations issued by the
United States or any agency thereof, or certificates of deposit of banks having
a capital, surplus and undivided profits in excess of $50,000,000, subject, in
each case, to certain other qualifying conditions.
The Underlying Properties are primarily gas producing properties. Normally
there is a greater demand for gas in the winter months than during the rest of
the year. Otherwise, the income to the Trust attributable to the Royalty is not
subject to seasonal factors nor in any manner related to or dependent upon
patents, licenses, franchises or concessions. The Trust conducts no research
activities.
ITEM 2. PROPERTIES
The 75% net overriding royalty conveyed to the Trust was carved out of
Southland Royalty's (now BROG's) working interest and royalty interests in the
San Juan Basin in northwestern New Mexico. References below to "gross" wells and
acres are to the interests of all persons owning interests therein, while
references to "net" are to the interests of BROG (from which the Royalty was
carved) in such wells and acres.
Unless otherwise indicated, the following information in Item 2 is based
upon data and information furnished to the Trustee by BROG.
PRODUCING ACREAGE, WELLS AND DRILLING
The Underlying Properties consist of working interests and royalty
interests in 151,900 gross (119,000 net) producing acres in San Juan, Rio Arriba
and Sandoval Counties of northwestern New Mexico. Based upon information
received from the Trust's independent petroleum engineers, the Trust properties
contain 2,951 gross (812 net) economic wells, including dual completions.
Production from conventional gas wells is
2
<PAGE> 4
primarily from the Pictured Cliffs, Mesaverde and Dakota formations. During
1988, Southland Royalty began development of coal seam reserves in the Fruitland
Coal formation. For additional information concerning coal seam gas, the
"Description of the Properties" section of the Trust's Annual Report to security
holders for the year ended December 31, 1998, is herein incorporated by
reference.
The Royalty conveyed to the Trust is limited to the base of the Dakota
formation, which is currently the deepest significant producing formation under
acreage affected by the Royalty. Rights to production, if any, from deeper
formations are retained by BROG.
During 1998, BROG incurred approximately $12.8 million of capital
expenditures for the drilling and completion of 36 gross (11.89 net)
conventional wells, recompletion of 25 gross (13.8 net) conventional wells, two
gross (.08 net) coal seam well recompletions, and 37 gross (2.28 net) coal seam
recavitations. There were 17 (1.46 net) new conventional wells, one gross (.05
net) coal seam recompletion, and three (.12 net) coal seam recavitations in
progress as of December 31, 1998.
During 1997, BROG incurred approximately $7.2 million of capital
expenditures for the drilling and completion of 64 gross (3.53 net) conventional
wells, recompletion of 14 gross (5.4 net) conventional wells, drilling and
completion of 1 gross (.84 net) coal seam well, and 21 gross (2.32 net) coal
seam recavitations. There were 5 (1.22 net) new conventional wells, 3 (1.08 net)
conventional recompletions, 11 gross (.42 net) coal seam recompletions, 5 (.20
net) coal seam recavitations, and 1 (.04 net) coal seam well in progress as of
December 31, 1997.
BROG announced that the New Mexico Oil Conservation Division has approved
plans for 80-acre infill drilling of the Mesaverde formation in the San Juan
Basin. 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 this massive reservoir.
A pilot program began in 1997 and was expanded in 1998 to include two additional
areas.
OIL AND GAS PRODUCTION
The Trust recognizes production during the month in which the related
distribution is received. Production of oil and gas and related average sales
prices attributable to the Royalty for the three years ended December 31, 1998
were as follows:
<TABLE>
<CAPTION>
1998 1997 1996
--------------------- --------------------- ---------------------
OIL GAS OIL GAS OIL GAS
(BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF)
------- ----------- ------- ----------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Production.............. 37,067 18,904,906 50,860 24,236,419 36,792 17,927,785
Average Price........... $ 13.55 $ 1.75 $ 19.35 $ 2.21 $ 19.64 $ 1.30
</TABLE>
PRICING INFORMATION
Gas produced in the San Juan Basin is sold in both interstate and
intrastate commerce. Reference is made to "Regulation" for information as to
federal regulation of prices of oil and natural gas. Gas production from the
properties from which the Royalty was carved totaled 41,507,353 Mcf during 1998.
On September 4, 1996, the Trustee announced the settlement of the
litigation (the "Litigation") filed by the Trustee against BROG and Southland
Royalty Company. The Litigation, which was filed in the state district court of
Santa Fe County, New Mexico, Cause No. SF 94-1982(c), was dismissed on September
12, 1996.
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<PAGE> 5
Agreement was reached, among other things, regarding marketing arrangements
for the sale of those gas, oil and natural gas liquids products which are
subject to the Royalty (the "Trust" gas, oil and/or natural gas liquids) as
follows:
(i) BROG's pre-existing contract with a third-party purchaser covering
baseload gas volumes in the firm amount of 45,000 MMBtus/day was to remain
effective for a period of one year from July 1, 1996. The remaining volumes
of Trust gas were marketed by an independent marketer, El Paso Energy
Marketing Company ("El Paso"), a subsidiary of El Paso Energy Corporation,
beginning October 1, 1996. BROG agreed that subsequent contracts for the
sale of Trust gas would require the written approval of an independent gas
marketing consultant acceptable to the Trust;
(ii) BROG will continue to market the Trust oil and natural gas
liquids but will make payments to the Trust based on actual proceeds from
such sales. BROG will no longer use posted prices as the basis for
calculating proceeds to the Trust nor make a deduction for marketing fees
associated with sales of oil or natural gas liquids products; and
(iii) The independent marketer of the Trust gas is entitled to access
to BROG's current gas transportation, gathering, processing and treating
agreements with third parties through the remainder or their primary terms.
Additionally, El Paso could utilize BROG's eastern transportation agreement
for delivery from the San Juan Basin on the El Paso Natural Gas Company
pipeline to pipelines in West Texas of up to 13,333 MMBtu's/day of gas
produced from Trust properties for a period of one year commencing October
1, 1996.
The gas purchase contracts described in subparagraph (i), above, were
continued, by agreement of the parties until December 31, 1997. Effective
January 1, 1998, all volumes of Trust gas became subject to the terms of a
Natural Gas Sales and Purchase Contract between BROG and El Paso. That contract
is for a term of two years through and including December 31, 1999 and provides
for the sale of Trust gas at prices which will fluctuate in accordance with
published indices for gas sold in the San Juan Basin of New Mexico. BROG entered
into the contract with El Paso after soliciting and receiving competitive bids
in late 1997 from six major gas marketing firms to market and/or purchase the
Trust gas. While it is impossible to predict the exact economic value of gas
contracts, the Trust has been advised by its independent gas marketing
consultant that the contract with El Paso should provide for the average highest
sales price for natural gas in the San Juan Basin over the two-year term of the
contract. The gas marketing consultant currently advising the Trust is in
communication with BROG concerning BROG's plans for the marketing of gas subject
to the Royalty following the expiration of the contract with El Paso at the end
of 1999.
See Note 5 of Notes to Financial Statements of the Trust's Annual Report to
securityholders for the year ended December 31, 1998 for further discussion of
this settlement and its impact on the Trust.
OIL AND GAS RESERVES
The following are definitions adopted by the Securities and Exchange
Commission ("SEC") and the Financial Accounting Standards Board which are
applicable to terms used within this Item:
"Proved reserves" are those estimated quantities of crude oil, natural
gas and natural gas liquids, which, upon analysis of geological and
engineering data, appear with reasonable certainty to be recoverable in the
future from known oil and gas reservoirs under existing economic and
operating conditions.
"Proved developed reserves" are those proved reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.
"Proved undeveloped reserves" are those proved reserves which are
expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required.
"Estimated future net revenues" are computed by applying current
prices of oil and gas (with consideration of price changes only to the
extent provided by contractual arrangements and allowed by federal
regulation) to estimated future production of proved oil and gas reserves
as of the date of the
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<PAGE> 6
latest balance sheet presented, less estimated future expenditures (based
on current costs) to be incurred in developing and producing the proved
reserves, and assuming continuation of existing economic conditions.
"Estimated future net revenues" are sometimes referred to herein as
"estimated future net cash flows."
"Present value of estimated future net revenues" is computed using the
estimated future net revenues and a discount rate of 10%.
The independent petroleum engineers' reports as to the proved oil and gas
reserves as of December 31, 1996, 1997 and 1998 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1995 to
December 31, 1998 (in thousands):
<TABLE>
<CAPTION>
CRUDE NATURAL
OIL GAS
(BBLS) (MCF)
------ -------
<S> <C> <C>
Reserves as of December 31, 1995............................ 418 166,450
Revisions of previous estimates............................. 272 95,106
Extensions, discoveries and other additions................. 4 2,367
Production.................................................. (37) (17,928)
---- -------
Reserves as of December 31, 1996............................ 657 245,995
---- -------
Revisions of previous estimates............................. (81) (25,734)
Extensions, discoveries and other additions................. 34 7,314
Production.................................................. (51) (24,236)
---- -------
Reserves as of December 31, 1997............................ 559 203,339
---- -------
Revisions of previous estimates............................. (195) (26,204)
Extensions, discoveries and other additions................. 6 5,201
Production.................................................. (37) (18,905)
---- -------
Reserves as of December 31, 1998............................ 333 163,431
==== =======
</TABLE>
Estimated quantities of proved developed reserves of crude oil and natural gas
as of December 31, 1998, 1997 and 1996 were as follows (in thousands):
<TABLE>
<CAPTION>
CRUDE NATURAL
OIL GAS
(BBLS) (MCF)
------ -------
<S> <C> <C>
1998........................................................ 328 159,454
1997........................................................ 547 199,753
1996........................................................ 637 239,962
</TABLE>
Generally, the calculation of oil and gas reserves takes into account a
comparison of the value of the oil or gas to the cost of producing those
minerals, in an attempt to cause minerals in the ground to be included in
reserve estimates only to the extent that the anticipated costs of production
will be exceeded by the anticipated sales revenue. Accordingly, an increase in
sales price and/or a decrease in production cost can itself result in an
increase in estimated reserves and declining prices and/or increasing costs can
result in reserves reported at less than the physical volumes actually thought
to exist. The Financial Accounting Standards Board requires supplemental
disclosures for oil and gas producers based on a standardized measure of
discounted future net cash flows relating to proved oil and gas reserve
quantities. Under this disclosure, future cash inflows are estimated by applying
year-end prices of oil and gas relating to the enterprise's proved reserves to
the year-end quantities of those reserves. Future price changes are only
considered to the extent provided by contractual arrangements in existence at
year-end. The standardized measure of discounted future net cash flows is
achieved by using a discount rate of 10% a year to reflect the timing of future
net cash flows relating to proved oil and gas reserves.
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<PAGE> 7
Estimates of proved oil and gas reserves are by their nature imprecise.
Estimates of future net revenue attributable to proved reserves are sensitive to
the unpredictable prices of oil and gas and other variables. Accordingly, under
the allocation method used to derive the Trust's quantity of proved reserves,
changes in prices will result in changes in quantities of proved oil and gas
reserves and estimated future net revenues.
The 1998, 1997 and 1996 changes in the standardized measure of discounted
future net cash flows related to future royalty income from proved reserves
discounted at 10% are as follows (in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
-------- --------- --------
<S> <C> <C> <C>
Balance, January 1.................................. $213,504 $ 439,037 $106,937
Revisions of prior-year estimates, change in prices
and other......................................... (63,731) (227,855) 338,208
Extensions, discoveries and other additions......... 3,667 7,915 4,612
Accretion of discount............................... 21,350 43,904 10,694
Royalty income...................................... (30,318) (49,497) (21,414)
-------- --------- --------
Balance, December 31................................ $144,472 $ 213,504 $439,037
======== ========= ========
</TABLE>
Reserve quantities and revenues shown in the tables above for the Royalty
were estimated from projections of reserves and revenues attributable to the
combined BROG and Trust interests. Reserve quantities attributable to the
Royalty were derived from estimates by allocating to the Royalty a portion of
the total net reserve quantities of the interests, based upon gross revenue less
production taxes. Because the reserve quantities attributable to the Royalty are
estimated using an allocation of the reserves, any changes in prices or costs
will result in changes in the estimated reserve quantities allocated to the
Royalty. Therefore, the reserve quantities estimated will vary if different
future price and cost assumptions occur. The future net cash flows were
determined without regard to future federal income tax credits available to
production from coal seam wells.
December average prices of $1.82 per Mcf of conventional gas, $1.30 per Mcf
of coal seam gas and $8.60 per Bbl of oil were used at December 31, 1998, in
determining future net revenue. The downward revision is primarily due to
significantly lower oil and gas prices in December 1998 as compared to December
1997.
December average prices of $2.21 per Mcf of conventional gas, $1.55 per Mcf
of coal seam gas and $15.97 per Bbl of oil were used at December 31, 1997, in
determining future net revenue. The downward revision is primarily due to
significantly lower gas prices in December 1997 as compared to December 1996.
December average prices of $4.04 per Mcf of conventional gas, $2.84 per Mcf
of coal seam gas and $23.18 per Bbl of oil were used at December 31, 1996, in
determining future net revenue. The upward revision is primarily due to
significantly higher gas prices in December 1996.
The following presents estimated future net revenues and present value of
estimated future net revenues attributable to the Royalty for each of the years
ended December 31, 1998, 1997 and 1996 (in thousands except amounts per Unit):
<TABLE>
<CAPTION>
1998 1997 1996
-------------------- -------------------- --------------------
ESTIMATED ESTIMATED ESTIMATED
FUTURE PRESENT FUTURE PRESENT FUTURE PRESENT
NET VALUE AT NET VALUE AT NET VALUE AT
REVENUE 10% REVENUE 10% REVENUE 10%
--------- -------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Total Proved................ $241,205 $144,472 $372,830 $213,504 $822,131 $439,037
Proved Developed............ $234,973 $142,095 $365,509 $211,580 $799,664 $430,365
Total Proved Per Unit....... $ 5.18 $ 3.10 $ 8.00 $ 4.58 $ 17.64 $ 9.42
</TABLE>
Proved reserve quantities are estimates based on information available at
the time of preparation and such estimates are subject to change as additional
information becomes available. The reserves actually recovered
6
<PAGE> 8
and the timing of production of those reserves may be substantially different
from the above estimates. Moreover, the present values shown above should not be
considered as the market values of such oil and gas reserves or the costs that
would be incurred to acquire equivalent reserves. A market value determination
would include many additional factors.
REGULATION
Many aspects of the production, pricing and marketing of crude oil and
natural gas are regulated by federal and state agencies. Legislation affecting
the oil and gas industry is under constant review for amendment or expansion,
frequently increasing the regulatory burden on affected members of the industry.
Exploration and production operations are subject to various types of
regulation at the federal, state and local levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements in
order to drill or operate wells, and regulating the location of wells, the
method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled and the plugging and abandonment of
wells. Natural gas and oil operations are also subject to various conservation
laws and regulations that regulate the size of drilling and spacing units or
proration units and the density of wells which may be drilled and unitization or
pooling of oil and gas properties. In addition, state conservation laws
establish maximum allowable production from natural gas and oil wells, generally
prohibit the venting or flaring of natural gas and impose certain requirements
regarding the ratability of production. The effect of these regulations is to
limit the amounts of natural gas and oil that BROG can produce and to limit the
number of wells or the locations at which BROG can drill.
Federal Natural Gas Regulation
The Federal Energy Regulatory Commission (the "FERC") is primarily
responsible for federal regulation of natural gas. The interstate transportation
and sale for resale of natural gas is subject to federal governmental
regulation, including regulation of transportation and storage tariffs and
various other matters, by the FERC. The Natural Gas Wellhead Decontrol Act of
1989 ("Decontrol Act") terminated federal price controls on wellhead sales of
domestic natural gas on January 1, 1993. Consequently, sales of natural gas may
be made at market prices, subject to applicable contract provisions. The FERC's
jurisdiction over natural gas transportation and storage was unaffected by the
Decontrol Act.
Sales of natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation remain
subject to extensive federal and state regulation. Several major regulatory
changes have been implemented by Congress and the FERC from 1985 to the present
that affect the economics of natural gas production, transportation, and sales.
In addition, the FERC continues to promulgate revisions to various aspects of
the rules and regulations affecting those segments of the natural gas industry,
most notably interstate natural gas transmission companies, that remain subject
to the FERC's jurisdiction. These initiatives may also affect the intrastate
transportation of gas under certain circumstances. The stated purpose of many of
these regulatory changes is to promote competition among the various sectors of
the natural gas industry and these initiatives generally reflect more
light-handed regulation of the natural gas industry.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Trust cannot predict when or if any such
proposals might become effective, or their effect, if any, on the Trust. The
natural gas industry historically has been very heavily regulated; therefore,
there is no assurance that the less stringent regulatory approach pursued over
the last decade by the FERC and Congress will continue.
Sales of crude oil, condensate and gas liquids are not currently regulated
and are made at market prices. Effective as of January 1, 1995, the FERC
implemented regulations establishing an indexing system for transportation rates
for oil that could increase the cost of transporting oil to the purchaser or
reduce wellhead prices for crude oil.
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<PAGE> 9
Coal Seam Tax Credit
The Trust began receiving royalty income from coal seam gas wells 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 seams 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 1998, this tax credit is expected,
subject to the determination of the Treasury Department no later than April 1,
1999, to be in the range of approximately $1.05 (the approximate 1997 rate) to
$1.09 per MMBtu. For qualifying production of the Trust, each Unit holder must
determine his pro rata share of such production based upon the number of Units
owned during each month of the year and apply the tax credit against his own
income tax liability, but such credit may not reduce his regular liability
(after the foreign tax credit and certain other nonrefundable credits) below his
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 his 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 Section 29 tax credit information related to Trust
Properties by BROG. In 1997, the Tax Court upheld the IRS position that
nonconventional fuel such as coal seam gas does not qualify for the Section 29
credit unless the producer received a formal certification from the FERC. The
FERC's certification authority expired effective January 1, 1993. Many producers
believe that wells meeting the certification requirements are eligible for the
Section 29 credit regardless of the FERC certification. However, this position
is not in accordance with the IRS position or the decision of the Tax Court. The
court decision is on appeal and it is not possible to predict the likely
outcome. In the event the appeal is not successful, the ability of the Unit
holders to utilize allocated Section 29 credits in full could be questioned.
Other Regulation
The oil and natural gas industry is also subject to compliance with various
other federal, state and local regulations and laws, including, but not limited
to, environmental protection, occupational safety, resource conservation and
equal employment opportunity.
ITEM 3. LEGAL PROCEEDINGS
On September 4, 1996, the Trustee announced the settlement of the
Litigation filed by the Trustee against BROG and Southland Royalty Company. The
Litigation, which was filed in the state district court of Santa Fe County, New
Mexico, Cause No. SF 94-1982(c), was dismissed on September 12, 1996.
The claims asserted on behalf of the Trust in the Litigation included
breach of contract, breach of the covenant of good faith and fair dealing,
breach of express good faith duty, constructive fraud, unjust enrichment, prima
facie tort, intentional interference with contract and conspiracy. The relief
sought included compensatory and punitive damages, an accounting and an
injunction relating to marketing the production from the Underlying Properties.
BROG has denied and continues to deny the allegations made against it in the
Litigation, but the parties have agreed to settle the Litigation as outlined
herein.
BROG agreed (i) to pay $19,750,000 in cash plus interest earnings thereon
from September 5, 1996, in settlement of underpayment of royalty claims of the
Trust; and (ii) commencing in 1997, to credit the Trust with $250,000 per year
for five years as an offset against lease operating expenses chargeable to the
Trust. BROG also agreed to make certain adjustments that represent cost
reductions favorable to the Trust in the ongoing charges for coal seam gas
gathering and treating on BROG's Val Verde system. Additionally, the Trustee and
BROG established a formal protocol intended to provide the Trustee and its
representatives improved access to BROG's books and records applicable to the
Underlying Properties.
Agreement was also reached regarding marketing arrangements for the sale of
Trust gas, oil and natural gas liquids products going forward as more
particularly described in "Pricing Information" under Item 2. Properties herein.
8
<PAGE> 10
The $19,750,000 (or $.423739 per unit of beneficial interest) was paid to
the Trust on September 30, 1996 and distributed on October 15, 1996, to
unitholders of record as of September 30, 1996, (the "Record Date"). The
distribution was taxable to unit holders as of such Record Date. This
distribution was in addition to the regular monthly distribution on October 15,
1996.
A lawsuit has been commenced against BROG by certain royalty and overriding
royalty owners on behalf of those persons similarly situated. The suit involves
properties that are burdened by the Trust's royalty interest. This case is one
of six virtually identical class actions filed against New Mexico gas producers.
All such cases have been consolidated in the First Judicial District of Santa Fe
County, New Mexico in a case filed September 1, 1995 and styled San Juan 1990-A,
L.P., et al. v. El Paso Production Company and Meridian Oil Inc. The plaintiffs
allege that they and members of the proposed class have been underpaid for
royalties and overriding royalties. The plaintiffs have sought to certify the
actions as class actions and seek monetary damages. The court has denied class
certification. Because of the pending nature of the litigation, exposure to the
Trust from this suit cannot be quantified. However, if the plaintiffs who have
interests in properties that are burdened by the Trust are successful, royalty
income received by the Trust could decrease.
In addition, the Trust is aware of an administrative claim initiated by the
Mineral Management Service of the United States Department of the Interior (the
"MMS") against BROG by demand letter dated March 17, 1997 regarding a gas
contract settlement dated March 1, 1990, between BROG and certain other parties
thereto. The claim alleges that additional royalties are due on production from
federal and Indian leases in the State of New Mexico on properties that are
burdened by the Royalty. BROG filed its statement of reasons in June 1997
thereby contesting whether the royalties are payable as claimed. If the MMS
claim is successful, royalty income received by the Trust could decrease.
For additional information concerning legal proceedings, Note 5 of the
Notes to Financial Statements at pages 14 and 15 of the Trust's Annual Report to
security holders for the year ended December 31, 1998 are herein incorporated by
reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of Unit holders, through the
solicitation of proxies or otherwise, during the fourth quarter ended December
31, 1998.
9
<PAGE> 11
PART II
ITEM 5. MARKET FOR UNITS OF THE TRUST AND RELATED SECURITY HOLDER MATTERS
The information under "Units of Beneficial Interest" at page 1 of the
Trust's Annual Report to security holders for the year ended December 31, 1998,
is herein incorporated by reference.
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------
1998 1997 1996 1995 1994
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Royalty income(1)........... $30,317,860 $49,497,479 $41,236,424 $15,156,292 $23,280,188
Distributable income........ 29,598,402 48,648,930 37,803,167 13,790,101 22,632,493
Distributable income per
Unit...................... 0.635039 1.043770 0.811072 0.295867 0.485584
Distributions per Unit...... 0.635039 1.043770 0.811072 0.295867 0.485584
Total assets, December 31... 53,753,582 61,231,280 65,935,976 70,554,982 75,531,405
</TABLE>
- ---------------
(1) The royalty income distributions for 1996 include material payments received
in settlement of litigation as more particularly described under "Item 2.
Properties" herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
The "Trustee's Discussion and Analysis" and "Results of the 4th Quarters of
1998 and 1997" at pages 7 through 9 of the Trust's Annual Report to
securityholders for the year ended December 31, 1998, are herein incorporated by
reference.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Trust has not entered into derivative financial instruments, derivative
commodity instruments or other similar instruments during 1998. As discussed in
Item 2. Properties -- Pricing Information, the Trust does not market the Trust
gas, oil and/or natural gas liquids. BROG is responsible for such marketing.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Financial Statements of the Trust and the notes thereto at page 10 et
seq., of the Trust's Annual Report to security holders for the year ended
December 31, 1998, are herein incorporated by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
10
<PAGE> 12
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Trust has no directors or executive officers. The Trustee is a
corporate trustee which may be removed, with or without cause, at a meeting of
the Unit holders, by the affirmative vote of the holders of a majority of all
the Units then outstanding.
ITEM 11. EXECUTIVE COMPENSATION
During the year ended December 31, 1998, the Trustee received total
remuneration as follows:
<TABLE>
<CAPTION>
NAME OF INDIVIDUAL OR NUMBER OF CAPACITIES IN WHICH CASH
PERSONS IN GROUP SERVED COMPENSATION
------------------------------- ------------------- ------------
<S> <C> <C>
Bank One, Texas, N.A................................... Trustee $69,494(1)
</TABLE>
- ---------------
(1) Under the Trust Indenture, the Trustee is entitled to an administrative fee
for its administrative services, preparation of quarterly and annual
statements with attention to tax and legal matters 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. The administrative fee is subject to reduction by a credit for
funds provision.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security Ownership of Certain Beneficial Owners. The following table
sets forth, as of December 31, 1998, information with respect to each person
known to own beneficially more than 5% of the outstanding Units of the Trust:
<TABLE>
<CAPTION>
AMOUNT AND
NATURE OF BENEFICIAL
NAME AND ADDRESS OWNERSHIP PERCENT OF CLASS
---------------- -------------------- ----------------
<S> <C> <C>
Fund American Enterprises Holdings, Inc.(1).......... 5,994,876 Units 14.4%
80 South Main Street
Hanover, New Hampshire 03755
Societe General Asset Management Corp.(2)............ 5,180,000 Units 11.1%
1221 Avenue of the Americas
New York, New York 10020
Capital Guardian Trust Company(3).................... 4,218,800 Units 9.1%
11100 Santa Monica Boulevard
Los Angeles, California 90025
</TABLE>
- ---------------
(1) This information was provided to the Trust on Amendment Number 8 to Schedule
13D, dated December 2, 1997, as filed with the Securities and Exchange
Commission (the "SEC") by Fund American Enterprises Holdings, Inc. ("FAEH"),
which indicated that these Units were owned by Fund American Enterprises,
Inc. The Amendment Number 8 to Schedule 13D may be reviewed for more
detailed information concerning the matters summarized herein.
(2) This information was provided to the Trust on Amendment Number 3 to Schedule
13G, dated February 6, 1999, as filed with the SEC. The Amendment Number 3
to Schedule 13G may be reviewed for more detailed information concerning the
matters summarized herein.
(3) This information was provided to the SEC and to the Trust in Amendment to
Schedule 13G, dated February 12, 1999. Capital Guardian Trust Company
reports sole voting power over 3,543,800 Units and sole dispositive power
over 4,218,800 Units. The Amendment Number 4 to Schedule 13G filed with the
SEC may be reviewed for more detailed information concerning the matters
summarized herein.
11
<PAGE> 13
(b) Security Ownership of Management. In various fiduciary capacities, Bank
One, Texas, N.A. owned, as of December 31, 1998, an aggregate of 89,472 Units
with the sole right to vote 33,672 of these Units, the shared right to vote
1,000 of these Units, and no right to vote 54,800 of these Units. Bank One,
Texas, N.A. disclaims any beneficial interest in these Units. The number of
Units reflected in this paragraph includes Units held by all branches of Bank
One, Texas, N.A.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Trust has no directors or executive officers. See Item 11 for the
remuneration received by the Trustee during the year ended December 31, 1998 and
Item 12(b) for information concerning Units owned by Bank One, Texas, N.A. in
various fiduciary capacities.
12
<PAGE> 14
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
The following documents are filed as a part of this Report:
FINANCIAL STATEMENTS
Included in Part II of this Report by reference to the Annual Report of the
Trust for the year ended December 31, 1998:
Independent Auditors' Report
Statements of Assets, Liabilities and Trust Corpus
Statements of Distributable Income
Statements of Changes in Trust Corpus
Notes to Financial Statements
FINANCIAL STATEMENT SCHEDULES
Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required information is
given in the financial statements or notes thereto.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
(4)(a) -- San Juan Basin Royalty Trust Indenture, dated November 3,
1980, between Southland Royalty Company and The Fort
Worth National Bank (now Bank One, Texas, N.A.), as
Trustee, heretofore filed as Exhibit 4(a) to the Trust's
Annual Report on Form 10-K to the SEC for the fiscal year
ended December 31, 1980, is incorporated herein by
reference.*
(b) -- Net Overriding Royalty Conveyance from Southland Royalty
Company to the Forth Worth National Bank (now Bank One,
Texas, 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 SEC for the
fiscal year ended December 31, 1980, is incorporated
herein by reference.*
(13) -- Registrant's Annual Report to security holders for fiscal
year ended December 31, 1998.**
(23) -- Consent of Cawley, Gillespie & Associates, Inc.,
reservoir engineer.**
(27) -- Financial Data Schedule.**
</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, Texas, N.A.,
P.O. Box 2604, Fort Worth, Texas 76113.
** Filed herewith.
REPORTS ON FORM 8-K
During the last quarter of the Trust fiscal year ended December 31, 1998,
no reports on Form 8-K were filed with the Securities and Exchange Commission by
the Trust.
13
<PAGE> 15
SIGNATURE
Pursuant to the Requirements of Section 13 or 15(d) of the Securities and
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, TEXAS, N.A.
TRUSTEE OF THE SAN JUAN BASIN
ROYALTY TRUST
By: /s/ LEE ANN ANDERSON
----------------------------------
(Lee Ann Anderson)
Vice President
Date: March 31, 1999
(The Trust has no directors or executive officers)
14
<PAGE> 16
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<C> <S>
(4)(a) -- San Juan Basin Royalty Trust Indenture, dated November 3,
1980, between Southland Royalty Company and The Fort
Worth National Bank (now Bank One, Texas, N.A.), as
Trustee, heretofore filed as Exhibit 4(a) to the Trust's
Annual Report on Form 10-K to the SEC for the fiscal year
ended December 31, 1980, is incorporated herein by
reference.*
(b) -- Net Overriding Royalty Conveyance from Southland Royalty
Company to the Forth Worth National Bank (now Bank One,
Texas, 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 SEC for the
fiscal year ended December 31, 1980, is incorporated
herein by reference.*
(13) -- Registrant's Annual Report to security holders for fiscal
year ended December 31, 1998.**
(23) -- Consent of Cawley, Gillespie & Associates, Inc.,
reservoir engineer.**
(27) -- Financial Data Schedule.**
</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, Texas, N.A.,
P.O. Box 2604, Fort Worth, Texas 76113.
** Filed herewith.
<PAGE> 1
EXHIBIT 13
SAN JUAN BASIN ROYALTY TRUST
POST OFFICE BOX 2604 FORT WORTH, TEXAS 76113 817-884-4630 WWW.SJBRT.COM
<PAGE> 2
THE TRUST
The principal asset of the San Juan Basin Royalty Trust (the "Trust")
consists of a 75% net overriding royalty interest carved out of certain of
Southland Royalty Company's ("Southland Royalty") oil and gas leasehold and
royalty interests in the San Juan Basin of northwestern New Mexico.
UNITS OF BENEFICIAL INTEREST
The Units of Benecial Interest of the Trust ("Units") are traded on the New
York Stock Exchange under the symbol "SJT." From January 1, 1997, to December
31, 1998, quarterly high and low sales prices and the aggregate amount of
monthly distributions per Unit paid each quarter were as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Distributions
1998 High Low Paid
- ---- ---- --- ----
<S> <C> <C> <C>
First Quarter .............. $ 9.3750 $ 7.1875 $ .245489
Second Quarter ............. 8.8750 7.3125 .137462
Third Quarter .............. 7.7500 5.1875 .132248
Fourth Quarter ............. 6.8750 5.1250 .119840
------------
Total for 1998 ....... $ .635039
============
1997
First Quarter .............. $ 8.8750 $ 7.5000 $ .391930
Second Quarter ............. 8.3125 7.2500 .183766
Third Quarter .............. 10.1250 7.9375 .206076
Fourth Quarter ............. 10.5626 8.6875 .261998
------------
Total for 1997........ $ 1.043770
============
- --------------------------------------------------------------------------------
</TABLE>
At December 31, 1998, 46,608,796 Units outstanding were held by 2,436 Unit
holders of record. The following table presents information relating to the
distribution of ownership Units:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Number of
Type of Unit Holders Unit Holders Units Held
- -------------------- ------------ ----------
<S> <C> <C>
Individuals ................. 2,114 3,685,129
Fiduciaries ................. 271 908,232
Institutions ................ 27 1,857,713
Brokers, Dealers and Nominees 6 39,946,730
Corporations and Partnerships 4 90,792
Miscellaneous ............... 14 120,200
----- ----------
Total ................. 2,436 46,608,796
===== ==========
- --------------------------------------------------------------------------------
</TABLE>
<PAGE> 3
TO UNIT HOLDERS
We are pleased to present the 1998 Annual Report of the San Juan Basin Royalty
Trust. The report includes a copy of the Trust's Annual Report on Form 10-K to
the Securities and Exchange Commission for the year ended December 31, 1998,
without exhibits. The Form 10-K contains important information concerning the
Underlying Properties, including the oil and gas reserves attributable to the
net overriding royalty interest owned by the Trust. Production figures provided
in this letter and in the Trustee's Discussion and Analysis are based on
information provided by Burlington Resources Oil & Gas Company ("BROG"). The
Trust was established in November 1980 by Trust Indenture between Southland
Royalty and The Fort Worth National Bank. Pursuant to the Indenture, Southland
Royalty conveyed to the Trust a 75% net overriding royalty interest (equivalent
to a net profits interest) carved out of Southland Royalty's oil and gas
leasehold and royalty interests in the San Juan Basin of northwestern New
Mexico. This net overriding royalty interest (the "Royalty") is the principal
asset of the Trust. The Form 10-K contains important information concerning,
among other things, the oil and gas reserves attributable to the Royalty and the
properties from which the Royalty was carved. Under the Trust Indenture, Bank
One, Texas, N.A. (successor trustee) as Trustee, has the primary function of
collecting monthly net proceeds ("Royalty Income") attributable to the Royalty
and making the monthly distributions to the Unit holders after deducting
administrative expenses and any amounts necessary for cash reserves. Income
distributed to Unit holders for the year 1998 was $29,598,402 or $.635039 per
Unit. This distributable income consisted of Royalty Income of $30,317,860 plus
interest income of $68,648, less administrative expenses of $788,106. In
September 1988, the Trust was advised by Southland Royalty and its affiliate
Meridian Oil, Inc. ("MOI"), both of which were subsidiaries of Burlington
Resources, Inc., that they had initiated a drilling program in the San Juan
Basin of northwestern New Mexico involving development of Fruitland Coal gas
reserves on properties in which the Trust owns an interest. For more information
on the coal seam drilling program and the related Federal income tax credit
associated with gas produced from coal seam wells drilled before January 1,
1993, please see the "Description of the Properties" section of this Annual
Report. On January 2, 1996, Southland Royalty was merged with and became a
wholly-owned subsidiary of MOI. Subsequent to the merger, MOI changed its name
to Burlington Resources Oil & Gas Company. Information about the Trust's
estimated proved reserves of gas, including coal seam gas, and of oil as well as
the present value of net revenues discounted at 10% can be found in Item 2 of
the accompanying Form 10-K. Certain Royalty Income is generally considered
portfolio income under the passive loss rules enacted by the Tax Reform Act of
1986. Therefore, it appears that Unit holders should not consider the taxable
income from the Trust to be passive income in determining net passive income or
loss. Unit holders should consult their tax advisors for further information.
Unit holders of record will continue to receive an individualized tax
information letter for each of the quarters ending March 31, June 30 and
September 30, 1999, and for the year ending December 31, 1999. Unit holders
owning Units in nominee name may obtain monthly tax information from the Trustee
upon request. For readers' convenience, a glossary which contains definitions
will be found on page four. Please visit our web site at www.sjbrt.com to access
news releases, reports, SEC filings and tax information.
Bank One, Texas, N.A., Trustee
By: /s/ LEE ANN ANDERSON
Lee Ann Anderson
Vice President
2
<PAGE> 4
[PHOTO]
3
<PAGE> 5
GLOSSARY OF TERMS
AGGREGATE MONTHLY DISTRIBUTION: an amount paid to unitholders equal to the
royalty income received by the Trustee during a calendar month plus interest,
less the general and administrative expenses of the Trust, adjusted by any
changes in cash reserves.
BBL: Barrel, generally 42 U.S. gallons measured at 60 degrees F.
BCF: Billion cubic feet.
BROG: Burlington Resources Oil & Gas Company.
BTU: British thermal unit; the amount of heat necessary to raise the
temperature of one pound of water one degree Fahrenheit.
COAL SEAM TAX CREDIT: A federal income tax credit available under Sec. 29 of
the Internal Revenue Code for producing coal seam gas (and other
non-conventional fuels) from wells drilled prior to January 1, 1993; and for
production from wells drilled after December 31, 1979, but prior to January
1, 1993, to a formation beneath a qualifying coal seam formation, which are
later completed into such formation.
COAL SEAM WELL: A well completed to a coal deposit found to contain and emit
natural gas.
COMMINGLED WELL: A well which produces from two or more formations through a
common well casing and a single tubing string.
CONVENTIONAL WELL: A well completed to a formation historically found to
contain deposits of oil or gas (for example, in the San Juan Basin, the
Pictured Cliffs, Dakota and Mesa Verde formations) and operated in the
conventional manner.
DEPLETION: The exhaustion of a petroleum reservoir; the reduction in value of
a wasting asset by removing the minerals; for tax purposes, the removal and
sale of minerals from a mineral deposit.
DISTRIBUTABLE INCOME: an amount paid to unitholders equal to the royalty
income received by the Trustee during a given period plus interest, less the
general and administrative expenses of the Trust, adjusted by any changes in
cash reserves.
DUAL COMPLETION: The completion of a well into two separate producing formations
at different depths, generally through one string of pipe, inside of which is a
smaller string of pipe producing from the other formation.
ESTIMATED FUTURE NET REVENUES: An estimate computed by applying current prices
of oil and gas (with consideration of price changes only to the extent provided
by contractual arrangements and allowed by federal regulation) to estimated
future production of proved oil and gas reserves as of the date of the latest
balance sheet presented, less estimated future expenditures (based on current
costs) to be incurred in developing and producing the proved reserves, and
assuming continuation of existing economic conditions; sometimes referred to as
"estimated future net cash flows."
GRANTOR TRUST: A trust (or portion thereof) with respect to which the grantor or
an assignee of the grantor, rather than the trust, is treated as the owner of
the trust properties and is taxed directly on the trust income for federal
income tax purposes under Sections 671 through 679 of the Internal Revenue Code.
GROSS ACRES OR WELLS: The interests of all persons owning interests in such
acres or wells.
GROSS PROCEEDS: The amount received by BROG (or any subsequent owner of the
interests from which the Royalty was carved) from the sale of the production
attributable to such interests.
LEASE OPERATING EXPENSES: Expenses incurred in the operation of a producing
property as apportioned among the several parties in interest.
MCF: 1,000 cubic feet; the standard unit for measuring the volume of natural
gas.
MMBTU: One million British thermal units.
MULTIPLE COMPLETION WELL: A well which produces simultaneously through
separate tubing strings from two or more producing horizons or alternatively
from each.
NET ACRES OR WELLS: The interests of BROG (from which the Royalty was carved)
in such acres or wells.
NET OVERRIDING ROYALTY INTEREST: A share of gross production from a property,
measured by net profits from operation of the property and carved out of the
working interest, i.e., a net profits interest.
NET PROCEEDS: The excess of gross proceeds received by BROG during a
particular period over production costs for such period.
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES: A computation using the
estimated future net revenues (as defined above) and a discount rate of 10%.
PRODUCTION COSTS: Costs incurred on an accrual basis by BROG in operating the
Underlying Properties, including both capital and non-capital costs and
including, for example, development drilling, production and processing
costs, applicable taxes, and operating charges.
PROVED DEVELOPED RESERVES: Those proved reserves which can be expected to be
recovered through existing wells with existing equipment and operating
methods.
PROVED RESERVES: Those estimated quantities of crude oil, natural gas and
natural gas liquids, which, upon analysis of geological and engineering data,
appear with reasonable certainty to be recoverable in the future from known
oil and gas reservoirs under existing economic and operating conditions.
PROVED UNDEVELOPED RESERVES: Those proved reserves which are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required.
RECAVITATED WELL: A coal seam well, the production from which has been
enhanced or extended by the enlargement of the cavity within the coal deposit
to which the well has been completed.
RECOMPLETED WELL: A well completed by drilling a separate well-bore from an
existing casing in order to reach the same reservoir, or re-drilling the same
well bore to reach a new reservoir after production from the original reservoir
has been abandoned.
ROYALTY: The principal asset of the Trust; the 75% net overriding royalty
interest conveyed to the Trust on November 3, 1980, by Southland Royalty
Company, the predecessor to BROG, which was carved out of certain oil and gas
working interests and royalty interests owned by it in the San Juan Basin.
SPOT PRICE: The price paid for gas, oil or oil products sold under contracts
for the purchase and sale of such minerals on a short-term basis.
UNDERLYING PROPERTIES: The working interests and royalty interests in the San
Juan Basin of northwest New Mexico owned by Southland Royalty Company, the
predecessor to BROG, out of which the Royalty was carved.
UNITS OF BENEFICIAL INTEREST: The units of ownership of the Trust, equal to
the number of shares of common stock of Southland Royalty Company outstanding
at the close of business on November 3, 1980.
WORKING INTEREST: The operating interest under an oil and gas lease.
4
<PAGE> 6
DESCRIPTION OF THE PROPERTIES
The working interests and the royalty interests in the San Juan Basin from
which the Trust's net overriding royalty interest was carved (the "Underlying
Properties") are located in San Juan, Rio Arriba and Sandoval Counties of
northwestern New Mexico. The Underlying Properties contain 151,900 gross
(119,000 net) producing acres and 2,951 gross (812 net) producing wells,
including dual completions. "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.
The Underlying Properties have historically produced gas primarily from
conventional wells drilled to three major formations: the Pictured Cliffs, the
Mesaverde and the Dakota, ranging in depth from 1,500 to 8,000 feet. The
characteristics of these reservoirs result in the wells having very long
productive lives. A production index for oil and gas properties is the number of
years derived by dividing remaining reserves by current production. Based upon
the reserve report prepared by independent petroleum engineers as of December
31, 1998, the production index for the San Juan Basin properties is estimated to
be approximately 9 years. The production index is subject to change from year to
year based on reserve revisions and production levels.
Among the factors considered by engineers in estimating remaining reserves
of natural gas is the current sales price for gas. As the sales price increases,
the producer can justify expending higher lifting costs and therefore reasonably
expect to recover more of the known reserves. Accordingly, as gas prices rise
the production index increases and vice versa.
BROG announced that the New Mexico Oil Conservation Division has approved
plans for 80-acre infill drilling of the Mesaverde Formation in the San Juan
Basin. The Mesaverde Formation was originally developed in the 1950s on 320-acre
spacing, with infill drilling initiated in the early 1970s 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 this massive reservoir. A
pilot program began in 1997 and was expanded in 1998 to include two additional
areas.
During 1988, a drilling program was initiated involving development of
Fruitland Coal gas reserves. Wells drilled in the Fruitland Coal range in depth
from 2,500 to 3,500 feet, generally on 320-acre spacing. BROG has informed the
Trust that based on its success in 1997 it anticipates increasing the density of
its drilling operations in the Fruitland Coal, with wells drilled on 160-and
80-acre spacing.
The process of removing coal seam gas is often referred to as
degasification or desorption. Millions of years ago, natural gas was generated
in the process of coal formation and adsorbed into the coal. Water later filled
the natural fracture system. When the water is removed from the natural fracture
system, reservoir pressure is lowered and the gas desorbs from the coal. The
desorbed gas then flows through the fracture system and is produced at the well
bore. The volume of formation water production typically declines with time and
the gas production may increase for a period of time before starting to decline.
In order to dispose of the formation water, surface facilities including pumping
units are required, which results in the cost of a completed well being as much
as $500,000. During 1998, these coal seam wells produced a total of
approximately 16,059,564 MMBtu of gas from the Underlying Properties, which was
sold at an average price of $1.57 per MMBtu.
Production from coal seam wells drilled prior to January 1, 1993, qualifies
for Federal income tax credits through 2002. For 1998 the credit was
approximately $1.06 per MMBtu. During 1998, potential Section 29 tax credits of
approximately $.168314 per Unit were generated for Trust Unit holders from
production from coal seam wells.
During 1998, BROG incurred approximately $12.8 million of capital
expenditures for the drilling and completion of 36 gross (11.89 net)
conventional wells, recompletion of 25 gross (13.8 net) conventional wells, 2
gross (.08 net) coal seam well recompletions, and 37 gross (2.28 net) coal seam
well recavitations.
There were 17 gross (1.46 net) new conventional wells, 1 gross (.045 net)
coal seam recompletion and 3 gross (.12 net) coal seam recavitations in progress
as of December 31, 1998.
During 1997, BROG participated in the drilling and completion of 64 gross
(3.53 net) conventional wells, recompletion of 14 gross (5.4 net) conventional
wells, drilling and completion of 1 gross (.84 net) coal seam well, and 21 gross
(2.32 net) coal seam recavitations and other maintenance activities and
facilities costs at a total cost of $7,231,699.
Due to the size of the coal seam drilling program in the San Juan Basin in
the late 1980s by various operators, there was more gas deliverability than
available pipeline capacity. As a result, several natural gas transportation
companies commenced pipeline expansion projects which almost doubled the
available transportation
5
<PAGE> 7
DESCRIPTION OF THE PROPERTIES
capacity out of the San Juan Basin. These projects were completed during 1992
and production increased to 26.6 Bcf for 1992 and to 40.7 Bcf for 1994. BROG has
advised the Trustee that mainline capacity out of the San Juan Basin is
estimated at 3 Bcf per day for El Paso Natural Gas Pipeline and 1.5 Bcf per day
for Transwestern Pipeline Company and that pipelines from the San Juan Basin are
now capable of transporting approximately 1.2 Bcf per day to markets east of the
San Juan Basin.
BROG has advised the Trust that capital projections for 1999 are estimated
to be $9.5 million. Approximately 95% of the $9.5 million will be attributable
to conventional projects. Of the 400 planned projects, 38 will be conventional
new drill locations at a cost of approximately $3 million. There are 21 planned
Fruitland Coal recavitations at an estimated cost of $40,000. BROG anticipates
adding compressors to 10 Fruitland Coal wells at a cost of approximately
$127,000. There are approximately 104 miscellaneous conventional projects
planned at a cost estimated to be $3.4 million. These projects will be aimed at
improving production from existing wells and will include payadds into the Lewis
Shale and Menefee Coal formations of the Mesaverde. Additionally, BROG plans to
undertake 177 miscellaneous facilities projects at a cost of approximately
$2,150,400. BROG anticipates that non-operated projects would be at a cost of
approximately $699,008. Development plans are dependent upon numerous factors,
including, but not limited to, drilling results of gas wells, anticipated demand
for gas, the sales price of gas, cost to drill the wells and other factors that
BROG may deem appropriate.
The Federal Energy Regulatory Commission is primarily responsible for
federal regulation of natural gas. For a further discussion of gas pricing, gas
purchasers, gas production and regulatory matters affecting gas production see
Item 2, "Properties," in the accompanying Form 10-K.
[MAP]
6
<PAGE> 8
TRUSTEE'S DISCUSSION AND ANALYSIS
Distributable income consists of Royalty Income plus interest, less the
general and administrative expenses of the Trust and any changes in cash
reserves established by the Trustee. For the year ended December 31, 1998,
distributable income decreased to $29,598,402 from $48,648,930 distributed in
1997. The decrease was primarily attributable to significantly lower gas and oil
prices. Interest income decreased from $99,403 in 1997 to $68,648 in 1998
primarily due to decreased funds available for investment.
Total gas and oil production from the Underlying Properties for the five
years ended December 31, 1998, were as follows:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Gas - Mcf ..... 41,507,353 41,948,567 40,738,422 34,387,190 34,222,189
Mcf per day.... 113,719 114,928 111,307 94,211 93,759
Oil - Bbls .... 81,888 89,492 83,552 75,014 84,648
Bbls per day... 224 245 228 206 232
- ---------------------------------------------------------------------------------------------
</TABLE>
Since the oil and gas sales attributable to the Royalty are based on an
allocation formula dependent 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.
Royalty Income for the calendar year is associated with actual gas and oil
production during the period from November of the preceding year through October
of the current year. Gas and oil sales attributable to the Royalty for the past
five years (excluding portions attributable to the litigation settlement
proceeds described in Note 5 to accompanying Financial Statements) are
summarized in the following table:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Gas - Mcf ................ 18,904,906 24,236,419 17,927,785 13,331,758 15,459,542
Average Price (per Mcf)... $ 1.75 $ 2.21 $ 1.30 $ 1.25 $ 1.66
Oil - Bbls ............... 37,067 50,860 36,792 29,424 36,769
Average Price (per Bbl)... $ 13.55 $ 19.35 $ 19.64 $ 14.43 $ 13.09
- -------------------------------------------------------------------------------------------------------------------------
</TABLE>
The fluctuations in annual gas production that have occurred during these
five years generally resulted from changes in the demand for gas during that
time, marketing conditions and production from new wells. Production from the
Underlying Properties is influenced by the line pressures of the gas gathering
systems in the San Juan Basin. Production increased from 1995 to 1996 primarily
due to increased coal seam volumes. As noted above, oil and gas sales
attributable to the Royalty are based on an allocation formula dependent on many
factors, including oil and gas prices and capital expenditures.
7
<PAGE> 9
TRUSTEE'S DISCUSSION AND ANALYSIS
Royalty Income for the five years ended December 31, 1998, was determined as
shown in the following table:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Gross Proceeds from
the underlying properties:
Gas .......................... $71,247,501 $91,495,060 $51,865,730 $41,483,305 $54,375,586
Oil .......................... 1,088,228 1,728,296 1,638,753 1,084,262 1,140,738
Other ........................ -0- -0- -0- 2,952 -0-
----------- ----------- ----------- ----------- -----------
Total .................. 72,335,729 93,223,356 53,504,483 42,570,159 55,498,324
=========== =========== =========== =========== ===========
Less Production Costs:
Capital Costs ................ 12,828,300 7,231,696 7,223,281 6,560,277 9,409,462
Severance Tax - Gas .......... 7,341,098 8,989,202 5,654,831 4,694,750 5,864,834
Severance Tax - Oil .......... 117,454 167,844 176,379 115,474 117,028
Other ........................ 66,892 61,832 59,089 117 -0-
Leasing Operating Expenses ... 11,558,172 10,776,145 11,838,345 10,991,152 9,066,750
----------- ----------- ----------- ----------- -----------
Total .................. 31,911,916 27,226,719 24,951,925 22,361,770 24,458,074
----------- ----------- ----------- ----------- -----------
Net Profits .................. 40,423,813 65,996,637 28,552,558 20,208,389 31,040,250
Royalty Percentage ........... 75% 75% 75% 75% 75%
Royalty Income ............... $30,317,860 $49,497,479 $21,414,419 $15,156,292 $23,280,188
=========== =========== =========== =========== ===========
- --------------------------------------------------------------------------------------------------------------
</TABLE>
The higher capital costs in 1994 were primarily attributable to
recompletions into the coal seam as part of a program which was initiated in
1988. The increase in capital costs incurred by BROG on the Underlying
Properties for the year ended December 31, 1998, was primarily attributable to
increased drilling activity. The Royalty Income amount of $21,414,419 for 1996
does not include the $19,822,005 paid to the Trust on September 30, 1996, in
settlement of the litigation described in Note 5 to the accompanying Financial
Statements. Operating costs in 1997 and 1998 include the impact of the receipt
of $250,000 from BROG as an offset to lease operating expense in connection with
the settlement of that litigation. Excluding the impact of the offset, monthly
operating costs in 1998 averaged approximately $964,669, which is higher than
the $899,000 average in 1997.
YEAR 2000 ISSUE
Many existing computer programs use only two digits to identify a year in
the date field. These programs were designed and developed without considering
the impact of the upcoming change in the century. If not corrected, many
computer applications could fail or create erroneous results by the Year 2000.
The Year 2000 issue affects virtually all companies and organizations. If a
company or organization does not successfully address its Year 2000 issues, it
may face material adverse consequences.
As the Trust does not directly maintain any systems, the Trust will not
incur any direct costs related to the Year 2000 issue. However, the Trust is
reliant on the performance of others, including the Trustee, BROG and third
party vendors (collectively, the "suppliers") for such things as the calculation
and receipt of Royalty income, payment of expenses and disbursement of
distributable income. The Trust has made formal inquiries to the suppliers
requesting information on their state of readiness for the Year 2000. Based upon
responses received and reviewed by the Trust with respect to its material
suppliers, all are currently addressing the Year 2000 issue and making efforts
to be compliant prior to the Year 2000. The Trust can provide no assurance as to
whether the suppliers will successfully address the Year 2000 issue. Failure to
successfully address the Year 2000 issue by the suppliers could have a material
adverse impact on the Trust and its Unit holders. At this time, the Trust
believes the most adverse impact as a result of the suppliers' failure to
successfully address the Year 2000 issue is that the Trust would not receive and
in turn would not be able to distribute royalty income to the Unit holders.
8
<PAGE> 10
RESULTS OF THE 4TH QUARTERS OF 1998 AND 1997
Distributable income for the three months ended December 31, 1998, totaled
$5,585,582 ($.119840 per Unit) as compared to $12,211,435 ($.261998 per Unit)
for the quarter ended December 31, 1997. The amount distributed in the fourth
quarter of 1998 was lower than that of 1997 primarily because of the lower
average gas and oil prices.
Royalty Income of the Trust for the fourth quarter is associated with
actual gas and oil production during August through October of each year. Gas
and oil sales for the quarters ended December 31, 1998 and 1997 were as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Underlying Properties 1998 1997
- --------------------- ---- ----
<S> <C> <C>
Gas - Mcf .......................... 10,243,360 10,441,818
Average Price (per Mcf)....... $ 1.44 $ 2.15
Oil - Bbls ......................... 18,194 19,438
Average Price (per Bbl)....... $ 11.50 $ 17.90
Attributable to the royalty
Gas - Mcf .......................... 4,183,417 6,113,834
Oil - Bbls ......................... 7,361 11,400
- --------------------------------------------------------------------------------
</TABLE>
The average price of gas and oil decreased compared to the prior year. The
price per barrel of oil during the fourth quarter of 1998 was $6.40 per Bbl
lower than that received in the fourth quarter of 1997 due to decreases in oil
prices in world markets generally, including the posted prices applicable to the
Royalty. Gas production decreased slightly primarily due to a decrease in coal
seam production. During the fourth quarter of 1998, coal seam production from
the Underlying Properties averaged 1,401,000 Mcf per month compared to 1,547,000
Mcf per month during the fourth quarter of 1997.
Capital costs for the fourth quarter of 1998 totaled $2,780,132 compared to
$1,579,932 during the same period of 1997. The increase was due to an increase
in drilling activity in the fourth quarter of 1998. Operating costs in 1998 and
1997 include the impact of the receipt of $250,000 from BROG as an offset to
lease operating expense in connection with the settlement of litigation.
Excluding the impact of the offset, lease operating costs for the fourth quarter
of 1998 averaged $1,073,500 per month in the fourth quarter compared to $858,000
per month in the fourth quarter of 1997.
9
<PAGE> 11
SAN JUAN BASIN ROYALTY TRUST
Statements of Assets, Liabilities and Trust Corpus
December 31, 1998 and 1997
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------
Assets 1998 1997
- ------ ---- ----
<S> <C> <C>
Cash and Short-term Investments ...................... $ 2,665,562 $ 5,111,832
Net Overriding Royalty Interests in Producing Oil and
Gas Properties - Net (Notes 2 and 3) ........... 51,088,020 56,119,448
----------- -----------
$53,753,582 $61,231,280
=========== ===========
Liabilities and Trust Corpus
Distribution Payable to Unit Holders ................. $ 2,665,562 $ 5,111,832
Contingencies (Note 5)
Trust Corpus - 46,608,796 Units of Beneficial Interest
Authorized and Outstanding ..................... 51,088,020 56,119,448
----------- -----------
$53,753,582 $61,231,280
=========== ===========
- --------------------------------------------------------------------------------------
</TABLE>
Statements of Distributable Income
for the Three Years Ended December 31, 1998
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Royalty Income (Notes 2, 3 and 5) .............. $30,317,860 $49,497,479 $41,236,424
Interest Income ................................ 68,648 99,403 76,346
----------- ----------- -----------
30,386,508 49,596,882 41,312,770
Expenditures - General and Administrative ...... 788,106 947,952 3,509,603
----------- ----------- -----------
Distributable Income ........................... $29,598,402 $48,648,930 $37,803,167
=========== =========== ===========
Distributable Income per Unit (46,608,796
Units) ....................................... $ .635039 $ 1.043770 $ .811072
=========== =========== ===========
- ------------------------------------------------------------------------------------------------
</TABLE>
Statements of Changes in Trust Corpus
for the Three Years Ended December 31, 1998
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Trust Corpus, Beginning of Period ............. $ 56,119,448 $ 62,808,148 $ 70,133,536
Amortization of Net Overriding Royalty Interest
(Notes 2 and 3) ......................... (5,031,428) (6,688,700) (7,325,388)
Distributable Income .......................... 29,598,402 48,648,930 37,803,167
Distributions Declared ........................ (29,598,402) (48,648,930) (37,803,167)
============ ============ ============
Trust Corpus, End of Period ................... $ 51,088,020 $ 56,119,448 $ 62,808,148
============ ============ ============
- -----------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
10
<PAGE> 12
[PHOTO]
11
<PAGE> 13
[PHOTO]
12
<PAGE> 14
SAN JUAN BASIN ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS
1. TRUST ORGANIZATION AND PROVISIONS
The San Juan Basin Royalty Trust ("Trust") was established as of November 1,
1980. Bank One, Texas, N.A. ("Trustee") is Trustee for the Trust. Southland
Royalty Company ("Southland") conveyed to the Trust a 75% net overriding
royalty interest ("Royalty") in Southland's working interests and royalty
interests in the properties located in the San Juan Basin in northwestern New
Mexico out of which the Royalty was carved (the "Underlying Properties").
On November 3, 1980, units of beneficial interest ("Units") in the Trust
were distributed to the Trustee for the benefit of Southland shareholders of
record as of November 3, 1980, who received one Unit in the Trust for each
share of Southland common stock held. The Units are traded on the New York
Stock Exchange.
The terms of the Trust Indenture provide, among other things, that:
o The Trust shall not engage in any business or commercial activity of
any kind or acquire any assets other than those initially conveyed to
the Trust;
o the Trustee may not sell all or any part of the Royalty unless
approved by holders of 75% of all Units outstanding, in which case the
sale must be for cash and the proceeds promptly distributed;
o the Trustee may establish a cash reserve for the payment of any
liability which is contingent or uncertain in amount;
o the Trustee is authorized to borrow funds to pay liabilities of the
Trust; and
o the Trustee will make monthly cash distributions to Unit holders (see
Note 2).
2. NET OVERRIDING ROYALTY INTEREST AND
DISTRIBUTION TO UNIT HOLDERS
The amounts to be distributed to Unit holders ("Monthly Distribution
Amounts") are determined on a monthly basis. The Monthly Distribution Amount
is an amount equal to the sum of cash received by the Trustee during a
calendar month attributable to the Royalty, any reduction in cash reserves
and any other cash receipts of the Trust, including interest, reduced by the
sum of liabilities paid and any increase in cash reserves. If the Monthly
Distribution Amount for any monthly period is a negative number, then the
distribution will be zero for such month and such negative amount will be
carried forward and deducted from future monthly distributions until the
cumulative distribution calculation becomes a positive number, at which time
a distribution will be made. Unit holders of record will be entitled
to receive the calculated Monthly Distribution Amount for each month on or
before ten business days after the monthly record date, which is generally
the last business day of each calendar month.
The cash received by the Trustee consists of the amounts received by the
owner of the interest burdened by the Royalty from the sale of production less
the sum of applicable taxes, accrued production costs, development and drilling
costs, operating charges and other costs and deductions, multiplied by 75%.
Royalty income for 1996 was comprised of $21,414,419, which represents the net
overriding royalty interest, and $19,822,005 paid to the Trust as a result of
the settlement of litigation involving the Trustee, Meridian Oil Inc. ("MOI")
and Southland. For more information regarding the settlement of the litigation,
see Note 5.
The initial carrying value of the Royalty ($133,275,528) represented
Southland's historical net book value at the date of the transfer to the Trust.
Accumulated amortization as of December 31, 1998 and 1997 aggregated $82,187,508
and $77,156,080, respectively.
3. BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on the following basis:
o Royalty income recorded for a month is the amount computed and paid by
the working interest owner to the Trustee on behalf of the Trust.
Royalty income consists of the amounts received by the owner of the
interest burdened by the net overriding royalty interest 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%.
o Trust expenses recorded are based on liabilities paid and cash
reserves established from Royalty income for liabilities and
contingencies.
o Distributions to Unit holders are recorded when declared by the
Trustee.
o The conveyance which transferred the overriding royalty interests 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 generally accepted accounting principles ("GAAP")
because revenues are
13
<PAGE> 15
SAN JUAN BASIN ROYALTY TRUST
not accrued in the month of production and certain cash reserves may
be established for contingencies which would not be accrued in
financial statements prepared in accordance with GAAP. Amortization of
the Royalty calculated on a unit-of-production basis is charged
directly to trust corpus.
4. 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 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 seams 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 1998, this tax credit is expected,
subject to the determination of the Treasury Department no later than April 1,
1999, to be in the range of approximately $1.05 (the approximate 1997 rate) to
$1.09 per MMBtu. For qualifying production of the Trust, each Unit holder must
determine his pro rata share of such production based upon the number of Units
owned during each month of the year and apply the tax credit against his own
income tax liability, but such credit may not reduce his regular liability
(after the foreign tax credit and certain other non-refundable credits) below
his 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 his 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 Section 29 tax credit information related to Trust
Properties by BROG. In 1997, the Tax Court upheld the IRS position that
nonconventional fuel such as coal seam gas does not qualify for the Section 29
credit unless the producer received a formal certification from the Federal
Energy Regulatory Commission ("FERC"). The FERC's certification authority
expired effective January 1, 1993. Many producers believe that wells meeting the
certification requirements are eligible for the Section 29 credit regardless of
FERC certification. However, this position is not in accordance with the IRS
position or the decision of the Tax Court. The court decision is on appeal and
it is not possible to predict the likely outcome. In the event the appeal is not
successful, the ability of the Unit holders to utilize allocated Section 29
credits in full could be in question.
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.
5. LITIGATION SETTLEMENT
On June 4, 1992, the Trustee filed suit (the "Litigation") against MOI and
Southland in New Mexico. The principal asset of the Trust consists of a 75% net
overriding royalty interest carved out of the Underlying Properties. MOI and
Southland were the operators of the Underlying Properties. On January 2, 1996,
Southland was merged with and became a wholly owned subsidiary of MOI.
Subsequent to the merger, MOI changed its name to Burlington Resources Oil & Gas
Company ("BROG" ).
The claims asserted on behalf of the Trust in the lawsuit included breach
of contract, breach of the covenant of good faith and fair dealing, breach of
express good faith duty, constructive fraud, unjust enrichment, prim a facie
tort, intentional interference with contract and conspiracy. The relief sought
included compensatory and punitive damages, an accounting and a permanent
injunction relating to the operation of the Trust Properties.
On September 4, 1996, the Trustee announced the settlement of the
Litigation. The Litigation was dismissed on September 12, 1996. BROG denied
and continues to deny the allegations made against it in the Litigation, but
the parties agreed to settle the Litigation as outlined herein.
BROG agreed (i) to pay $19,750,000 in cash plus interest earnings thereon
from September 5, 1996, in settlement of underpayment of royalty claims of the
Trust; and (ii) commencing
14
<PAGE> 16
SAN JUAN BASIN ROYALTY TRUST
in 1997, to credit the Trust with $250,000 per year for five years as an offset
against lease operating expenses chargeable to the Trust. BROG also agreed to
make certain adjustments that represent cost reductions favorable to the Trust
in the ongoing charges for coal seam gas gathering and treating on BROG's Val
Verde system. Additionally, the Trustee and BROG established a formal protocol
that will provide the Trustee and its representatives improved access to BROG's
books and records applicable to the Trust Properties.
Agreement was also reached regarding marketing arrangements for the sale of
gas, oil and natural gas liquids products from the Underlying Properties going
forward as follows:
1. BROG agreed that contracts for the sale of gas from the Underlying
Properties would require the written approval of an independent gas marketing
consultant acceptable to the Trust. For a discussion of the current contract
covering the sale of gas from the Underlying Properties, see Note 6.
2. BROG will continue to market the oil and natural gas liquids from the
Underlying Properties but will remit to the Trust actual proceeds from such
sales. BROG will no longer use posted prices as the basis for calculating
proceeds to the Trust nor make a deduction for marketing fees associated with
sales of oil or natural gas liquids products.
3. The Trust retained access to BROG's current gas transportation,
gathering, processing and treating agreements with third parties through the
remainder of their primary terms.
The $19,822,005 settlement proceeds of the Litigation (or $.425285 per Unit
of beneficial interest) was paid to the Trust on September 30 and distributed on
October 15, 1996, to Unit holders of record as of September 30, 1996 (the
"Record Date"). The distribution was taxable to Unit holders as of such Record
Date. This distribution was in addition to the regular monthly distribution on
October 15.
6. CERTAIN CONTRACTS
Effective January 1, 1998, all volumes of Trust gas became subject to the terms
of a Natural Gas Sales and Purchase Contract between BROG and El Paso Energy
Marketing company ("El Paso"). That contract is for a term of two years through
and including December 31, 1999 and provides 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. BROG entered into the contract with El Paso after
soliciting and receiving competitive bids in late 1997 from six major gas
marketing firms to market and/or purchase the Trust gas. While it is impossible
to predict the exact economic value of gas contracts, the Trust has been advised
by its independent gas marketing consultant that the contract with El Paso
should provide for the average highest sales price for natural gas in the San
Juan Basin over the two-year term of the contract. The gas marketing consultant
currently advising the Trust is in communication with BROG concerning BROG's
plans for the marketing of gas subject to the Royalty following the expiration
of the contract with El Paso at the end of 1999.
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.
7. SIGNIFICANT CUSTOMERS
Information as to significant purchasers of oil and gas production attributable
to the Trust's economic interests is included in Item 2 of the Trust's annual
report on Form 10-K which is included in this report.
8. PROVED OIL AND GAS RESERVES (UNAUDITED)
Proved oil and gas reserve information is included in Item 2 of the Trust's
annual report on Form 10-K which is included in this report.
9. QUARTERLY SCHEDULE OF DISTRIBUTABLE INCOME (UNAUDITED)
The following is a summary of the unaudited quarterly schedule of
distributable income for the two years ended December 31, 1998 (in thousands,
except unit amounts):
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Distributable
Income and
Royalty Distributable Distribution
1998 Income Income Per Unit
- ---- ------ ------ --------
<S> <C> <C> <C>
First Quarter........... $11,663 $11,442 $ .245489
Second Quarter.......... 6,679 6,407 .137462
Third Quarter........... 6,277 6,164 .132248
Fourth Quarter.......... 5,699 5,585 .119840
Total ............ $30,318 $29,598 $ .635039
1997
- ----
First Quarter........... $18,471 $18,267 $ .391930
Second Quarter.......... 8,900 8,565 .183766
Third Quarter........... 9,764 9,605 .206076
Fourth Quarter.......... 12,363 12,212 .261998
Total ............ $49,498 $48,649 $1.043770
- --------------------------------------------------------------------------------
</TABLE>
15
<PAGE> 17
INDEPENDENT AUDITORS' REPORT
Bank One, Texas, N.A. as Trustee for the San Juan Basin Royalty Trust:
We have audited the accompanying statements of assets, liabilities and
trust corpus of the San Juan Basin Royalty Trust ("Trust") as of December 31,
1998 and 1997, and the related statements of distributable income and changes in
trust corpus for each of the three years in the period ended December 31, 1998.
These financial statements are the responsibility of the Trustee. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by the
Trustee, as well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
As described in Note 3 to the financial statements, these financial
statements were prepared on a modified cash basis, which is a comprehensive
basis of accounting other than generally accepted accounting principles.
In our opinion, such financial statements present fairly, in all material
respects, the assets, liabilities and trust corpus of the San Juan Basin Royalty
Trust as of December 31, 1998 and 1997, and the distributable income and changes
in trust corpus for each of the three years in the period ended December 31,
1998, on the basis of accounting described in Note 3.
/s/ DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Fort Worth, Texas
March 22, 1999
- --------------------------------------------------------------------------------
SAN JUAN BASIN ROYALTY TRUST
Bank One, Texas, N.A., Trustee
Post Office Box 2604
Fort Worth, Texas 76113
817-884-4630
Web site: www.sjbrt.com
AUDITORS
Deloitte & Touche LLP
Fort Worth, Texas
LEGAL COUNSEL
Vinson & Elkins L.L.P.
Dallas, Texas
TAX COUNSEL
Butler & Binion, L.L.P.
Houston, Texas
TRANSFER AGENT
Harris Trust & Savings Bank
311 West Monroe Street, 11th Floor
Chicago, Illinois 60606
For questions about distribution checks,
address changes, and transfer procedures,
call 800-573-4048 or 312-461-6001.
16
<PAGE> 18
SAN JUAN BASIN ROYALTY TRUST
1998 ANNUAL REPORT & FORM 10K
<PAGE> 1
EXHIBIT 23
[CAWLEY, GILLESPIE & ASSOCIATES, INC. LETTERHEAD]
March 25, 1999
San Juan Basin Royalty Trust
Bank One, Texas, N.A.
Corporate Trust Department
500 Throckmorton Street, Suite 801
Fort Worth, Texas 76102
Ladies and Gentlemen:
Cawley, Gillespie & Associates, Inc. hereby consents to the use of the oil
and gas reserve information in the San Juan Basin Royalty Trust Securities &
Exchange Commission Form 10-K for the year ended December 31, 1998 and in the
San Juan Basin Royalty Trust Annual Report for the year ended December 31, 1998
based on reserve reports dated March 25, 1999 prepared by Cawley, Gillespie &
Associates, Inc.
Sincerely,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
UNAUDITED CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS OF SAN
JUAN BASIN ROYALTY TRUST AS OF DECEMBER 31, 1998, AND THE RELATED CONDENSED
STATEMENTS OF DISTRIBUTABLE INCOME AND CHANGES IN TRUST CORPUS FOR THE TWELVE
MONTH PERIOD ENDED DECEMBER 31, 1998.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 2,665,562
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 2,665,562
<PP&E> 133,275,528
<DEPRECIATION> 82,187,508
<TOTAL-ASSETS> 53,753,582
<CURRENT-LIABILITIES> 2,665,562
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 51,088,020
<TOTAL-LIABILITY-AND-EQUITY> 53,753,582
<SALES> 0
<TOTAL-REVENUES> 30,386,508
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 788,106
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 29,598,402
<INCOME-TAX> 0
<INCOME-CONTINUING> 29,598,402
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 29,598,402
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
