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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, 1999,
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)
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 offices)
(817) 884-4630
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
- ---------------------------- ------------------------
Units of Beneficial Interest New York Stock Exchange
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 April 12, 2000, there were 46,608,796 Units of Beneficial Interest of the
Trust outstanding with an aggregate market value on that date of $463,174,910.
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, 1999 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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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
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Trust receives more than the amount due under the Royalty, it shall not be
obligated to return such overpayment, 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
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received from the Trust's independent petroleum engineers, the Trust properties
contain 3,204 gross (897 net) economic wells, including dual completions.
Production from conventional gas wells is 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, 1999, 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 1999, BROG incurred approximately $10.5 million of capital
expenditures for the drilling and completion of 71 gross (7.22 net) conventional
wells, recompletion of 4 gross (1.36 net) conventional wells, drilling and
completion of 3 gross (.93 net) coal seam wells, 1 gross (.54 net) coal seam
well recompletion, and 10 gross (.07 net) coal seam recavitations. There were 53
gross (20.14 net) new conventional wells, 25 gross (3.77 net) conventional well
recompletions, 3 gross (.39 net) coal seam wells, 7 gross (.79 net) coal seam
recompletions, and 38 gross (.75 net) coal seam recavitations in progress as of
December 31, 1999.
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 gross (1.46 net) new conventional wells, one gross
(.05 net) coal seam recompletion, and three gross (.12 net) coal seam
recavitations in progress as of December 31, 1998.
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.
The Trust has been advised that capital expenses for 2000 are projected
to be approximately $20.5 million. Approximately 95% of that amount will be
attributable to conventional projects. Of the 400 planned projects, 57 will be
conventional new drill locations at a cost of approximately $13.7 million, 99
will be attributable to workovers at a cost of $5.2 million, and 244 of the
projects will be miscellaneous facilities projects at a cost of $1.6 million. Of
the 57 new drilling projects planned for 2000, 21 are on properties in which
BROG owns 100% of the working interest, so that the Trust's share of the planned
capital expenditures is increased as compared to wells in which BROG owns only a
partial working interest.
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, 1999
were as follows:
<TABLE>
<CAPTION>
1999 1998 1997
----------------------- ----------------------- -----------------------
Oil Gas Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Production ......... 35,341 19,527,666 37,067 18,904,906 50,860 24,236,419
Average Price ...... $ 14.41 $ 1.78 $ 13.55 $ 1.75 $ 19.35 $ 2.21
</TABLE>
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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 39,940,175 Mcf during 1999.
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.
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 agreed that, except for a pre-existing contract which
has since expired, all 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.
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. BROG has entered into a contract dated November 10, 1999 for the sale
of all volumes of Trust gas to Duke Energy and Marketing L.L.C. That contract
provides for delivery of gas at various delivery points over a period commencing
January 1, 2000 and ending October 31, 2001 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.
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.
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:
"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
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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. "Estimated future net
revenues" are sometimes referred to in this Form 10-K as "estimated
future net cash flows."
"Present value of estimated future net revenues" is computed
using the estimated future net revenues (as defined above) and a
discount rate of 10%.
"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.
The independent petroleum engineers' reports as to the proved oil and gas
reserves as of December 31, 1997, 1998 and 1999 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1996 to
December 31, 1999 (in thousands):
<TABLE>
<CAPTION>
CRUDE NATURAL
OIL GAS
(Bbls) (Mcf)
-------- --------
<S> <C> <C>
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
-------- --------
Revisions of previous estimates .................. 120 53,936
Extensions, discoveries and other additions ...... 29 14,498
Production ....................................... (32) (17,650)
-------- --------
Reserves as of December 31, 1999 ................. 450 214,215
======== ========
</TABLE>
Estimated quantities of proved developed reserves of crude oil and natural gas
as of December 31, 1999, 1998 and 1997 were as follows (in thousands):
<TABLE>
<CAPTION>
CRUDE NATURAL
OIL GAS
(Bbls) (Mcf)
------ -------
<S> <C> <C>
1999 ............................................. 422 201,891
1998 ............................................. 328 159,454
1997 ............................................. 547 199,753
</TABLE>
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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.
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 1999, 1998 and 1997 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>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Balance, January 1 ......................................... $ 144,472 $ 213,504 $ 439,037
Revisions of prior-year estimates, change in prices
and other ............................................... 90,172 (63,731) (227,855)
Extensions, discoveries and other additions ................ 13,257 3,667 7,915
Accretion of discount ...................................... 14,447 21,350 43,904
Royalty income ............................................. (32,627) (30,318) (49,497)
----------- ----------- -----------
Balance, December 31 ....................................... $ 229,721 $ 144,472 $ 213,504
=========== =========== ===========
</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 $2.39 per Mcf of conventional gas, $1.49 per
Mcf of coal seam gas and $22.30 per Bbl of oil were used at December 31, 1999,
in determining future net revenue. The upward revision is primarily due to
significantly higher gas prices in December 1999.
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.
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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, 1999, 1998 and 1997 (in thousands except amounts per
Unit):
<TABLE>
<CAPTION>
1999 1998 1997
--------------------- --------------------- ---------------------
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 ............ $ 408,609 $ 229,721 $ 241,205 $ 144,472 $ 372,830 $ 213,504
Proved Developed ........ $ 383,356 $ 219,677 $ 234,973 $ 142,095 $ 365,509 $ 211,580
Total Proved Per Unit ... $ 8.77 $ 4.93 $ 5.18 $ 3.10 $ 8.00 $ 4.58
</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 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
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<PAGE> 9
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.
Section 29 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 1999, this tax credit will be
approximately $1.04 per MMBtu. To benefit from the credit, each Unit holder
must determine from the tax information he receives from the Trust his pro rata
share of qualifying production of the Trust, based upon the number of Units
owned during each month of the year, and the amount of available credit per
MMbtu for the year, and then apply the tax credit against his own income tax
liability, but such credit may not reduce his regular tax 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.
BROG provides the Trustee with certain Section 29 tax credit
information, including coal seam volumes produced from Trust Properties. In
1999, the Tenth Circuit Court upheld the position of the IRS and the Tax Court
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 decisions of the Tenth Circuit
Court or the Tax Court. The courts may hear other cases regarding this matter
and it is not possible to predict the likely outcome. In the event the IRS
position is ultimately upheld, the ability of the Unit holders to utilize
allocated Section 29 credits in full could be questioned. But on December 23,
1999, a petition was filed with the FERC by a coalition of energy producers
seeking reinstatement of the certification process. By letter dated January 14,
2000, the U.S. Department of Energy expressed its support of that petition and
on January 27, 2000 the FERC issued notice of proposed rulemaking by which its
regulations would be amended to reinstate certain regulations involving well
category determinations for Section 29 tax credits for certain well
recompletions commenced after January 1, 1993. It is not yet possible to predict
the likely outcome of this rulemaking process.
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.
8
<PAGE> 10
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 for purposes of the calculation of net proceeds payable 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.
The $19,822,005 (or $.425285 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 was commenced on September 1, 1995 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. 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 where the case is 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, but the plaintiffs have renewed their request for class
certification. Discovery in this matter is closed. BROG anticipates summary
judgment proceedings to occur in the summer of 2000. 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, an administrative claim was initiated on March 17, 1997 by
the Mineral Management Service of the United States Department of the Interior
(the "MMS") against BROG regarding a gas 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. In June 1997 BROG
filed its statement of reasons thereby contesting whether the royalties are
payable as claimed. BROG has informed the Trust that the administrative claim is
in the appeal process. If the MMS claim is successful, royalty income received
by the Trust could decrease.
9
<PAGE> 11
BROG is in negotiations with the State of New Mexico for a tax refund
based upon a claim for reimbursement of compression costs used in calculating
wellhead values. BROG has obtained the approval of the Attorney General of New
Mexico of a settlement in the amount of $4,200,000 and payment has been
received. BROG has not informed the Trust of the proportion of the settlement
proceeds which will be attributable to the Trust.
In February 1999, the Trust's auditors notified the Trust of an
apparent gas imbalance. A gas imbalance occurs where more than one party is
entitled to the economic benefit of the production of natural gas, but the gas
is sold for the account of less than all of the parties. The resulting imbalance
may be corrected by various means including a cash settlement and/or a volume
adjustment whereby an increased percentage of future production is sold for the
account of the underproduced party or parties. The Trust's auditors suggested
that the subject imbalance might relate to the acquisition by BROG's
predecessor, Southland Royalty, of mineral properties which had been operated
under a Joint Operating Agreement between Southland Royalty and Unicon, the
seller of the properties. The Trust made inquiry of BROG concerning the
imbalance and BROG agreed to investigate the records. The Trustee met with BROG
representatives in June 1999 to discuss the investigation, and by correspondence
of September 24, 1999, BROG reported that the imbalance probably related to
problems experienced in the 1980's and early 1990's by Southland Royalty and
Unicon in their dealings with Public Service Company of New Mexico. BROG
reported that Unicon was flowing gas to its account while Southland Royalty was
not producing and that this created a gas imbalance. The imbalance was
addressed, as between Southland Royalty and Unicon, by a reduction in the total
purchase price for Unicon assets acquired by Southland Royalty in June 1990.
However, there was no payment made to the Trust at the time of that acquisition.
BROG proposes to address the imbalance with the Trust based upon the
terms of a Gas Balancing Agreement it indicates was in place between Southland
Royalty and Unicon, in connection with the Joint Operating Agreement applicable
to the subject properties and has offered $3,100,000 as a cash settlement.
The Trust is considering the appropriateness of this proposed means of
resolution and this offer and is consulting with its advisors. No assurance can
be given as to when and how this issue will be resolved.
For additional information concerning legal proceedings, Note 5 of the
Notes to Financial Statements on pages 14 and 15 of the Trust's Annual Report
to security holders for the year ended December 31, 1999 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, 1999.
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, 1999,
is herein incorporated by reference.
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
For the Year Ended December 31,
--------------------------------------------------------------------------------
1999 1998 1997 1996 1995
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Royalty income ............... $ 32,626,966 $ 30,317,860 $ 49,497,479 $ 41,236,424(1) $ 15,156,292
Distributable income ......... 31,795,667 29,598,402 48,648,930 37,803,167 13,790,101
Distributable income per
Unit ...................... 0.682182 0.635039 1.043770 0.811072 0.295867
Distributions per Unit ....... 0.682182 0.635039 1.043770 0.811072 0.295867
Total assets, December 31 .... 49,048,652 53,753,582 61,231,280 65,935,976 70,554,982
</TABLE>
10
<PAGE> 12
- ----------
(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 1999 and 1998" at pages 7 through 9 of the Trust's Annual Report
to securityholders for the year ended December 31, 1999, 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 1999. 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, 1999, are herein incorporated by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
NONE.
11
<PAGE> 13
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
The Trust has no directors or executive officers. During the year ended
December 31, 1999, 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 $ 88,163(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, 1999, 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>
Alpine Capital L.P.(1).................................. 15,049,200 Units 32.3%
201 Main Street, Suite 3100
Fort Worth, Texas 76102
Societe General Asset Management Corp.(2)............... 5,180,000 Units 11.1%
1221 Avenue of the Americas
New York, New York 10020
Arnhold and S. Bleichroeder, Inc.(3).................... 3,250,000 Units 6.9%
Arnhold and S. Bleichroeder Advisers, Inc.
1345 Avenue of the Americas
New York, New York 10105
McMorgan and Company(4)................................. 3,000,000 Units 6.4%
1 Bush Street, Suite 800
San Francisco, CA 94104
</TABLE>
- ----------
(1) This information was provided to the Trust on Amendment Number 18 to
Schedule 13D, dated March 15, 2000, as filed with the Securities and
Exchange Commission (the "SEC") by Alpine Capital L.P. ("Alpine"),
which indicated that these Units were beneficially owned by Alpine. The
Amendment Number 18 to Schedule 13D may be reviewed for more detailed
information concerning the matters summarized herein.
12
<PAGE> 14
(2) This information was provided to the Trust on Amendment Number 3 to
Schedule 13G, dated January 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 Trust in Amendment Number 4 to
Schedule 13G, dated February 15, 2000. Arnhold and S. Bleichroeder,
Inc. and Arnhold and S. Bleichroeder Advisers, Inc. report shared
voting power over 3,250,000 Units and shared dispositive power over
3,250,000 Units. The Amendment Number 4 to Schedule 13G filed with the
SEC may be reviewed for more detailed information concerning the
matters summarized herein.
(4) This information was provided to the Trust in a Schedule 13G dated July
12, 1999, as filed with the SEC. The Schedule 13G may be reviewed for
more detailed information concerning the matters summarized herein.
(b) Security Ownership of Management. In various fiduciary capacities,
Bank One, Texas, N.A. owned, as of December 31, 1999, an aggregate of 42,472
Units with the sole right to vote 34,672 of these Units and no right to vote
7,800 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, 1999 and
Item 12(b) for information concerning Units owned by Bank One, Texas, N.A. in
various fiduciary capacities.
13
<PAGE> 15
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, 1999:
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.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
(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, 1999.**
(23) -- Consent of Cawley, Gillespie & Associates, Inc., reservoir
engineer.**
(27) -- Financial Data Schedule.**
- ----------
* 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,
1999, no reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust.
14
<PAGE> 16
SIGNATURE
Pursuant to the Requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BANK ONE, TEXAS, N.A.
TRUSTEE OF THE SAN JUAN BASIN
ROYALTY TRUST
By: /s/ LEE ANN ANDERSON
---------------------------------
(Lee Ann Anderson)
Vice President
Date: April 14, 2000
(The Trust has no directors or executive officers)
<PAGE> 17
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
(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, 1999.**
(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
SAN JUAN BASIN ROYALTY TRUST
1999 annual report & form 10k
<PAGE> 2
SAN JUAN BASIN ROYALTY TRUST
post office box 2604 o fort worth, texas 76113 o 817-884-4630 o www.sjbrt.com
<PAGE> 3
[IMAGE]
<PAGE> 4
SAN JUAN BASIN ROYALTY TRUST
Bank One, Texas, N.A., Trustee
Post Office Box 2604
Fort Worth, Texas 76113
817-884-4630
www.sjbrt.com
[email protected]
AUDITORS
Deloitte & Touche LLP
Fort Worth, Texas
LEGAL COUNSEL
Vinson & Elkins L.L.P.
Dallas, Texas
TAX COUNSEL
Winstead Sechrest & Minick, P.C.
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 312-360-5300.
[RECYCLE ICON] Printed on recycled paper
<PAGE> 5
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 Beneficial Interest of the Trust ("Units") are traded on the New
York Stock Exchange under the symbol "SJT." At April 12, 2000, the latest
practicable date, the sale price of a Unit was $9.9375. From January 1, 1998, to
December 31, 1999, quarterly high and low sales prices and the aggregate amount
of monthly distributions per Unit paid each quarter were as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Distributions
1999 High Low Paid
- ---- -------- ------- -------------
<S> <C> <C> <C>
First Quarter.......... $ 6.8750 $5.3125 $ .145721
Second Quarter......... 8.3125 6.3125 .127528
Third Quarter.......... 9.2500 7.5000 .166611
Fourth Quarter......... 10.3750 7.8125 .242322
----------
Total for 1999 $ .682182
==========
1998
- ----
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
==========
- --------------------------------------------------------------------------------
</TABLE>
At December 31, 1999, 46,608,796 Units outstanding were held by 2,245 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........................ 1,962 3,353,918
Fiduciaries........................ 222 661,550
Institutions....................... 42 1,960,148
Brokers, Dealers and Nominees...... 5 40,463,558
Corporations and Partnerships...... 3 113,292
Miscellaneous...................... 11 56,330
----- ----------
Total 2,245 46,608,796
===== ==========
- --------------------------------------------------------------------------------
</TABLE>
1
<PAGE> 6
To Unit Holders
We are pleased to present the 1999 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,
1999, 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"). o
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. o 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 1999 was $31,795,667 or $.682182 per
Unit. This distributable income consisted of Royalty Income of $32,626,966 plus
interest income of $65,029, less administrative expenses of $896,328. o 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 Seam
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. o 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. o 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. o 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. o 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, 2000,
and for the year ending December 31, 2000. Unit holders owning Units in nominee
name may obtain monthly tax information from the Trustee upon request. o 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> 7
[IMAGE]
indian paintbrush
<PAGE> 8
GLOSSARY OF TERMS
AGGREGATE MONTHLY DISTRIBUTION: An amount paid to Unit holders 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 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 Mesaverde formations) and operated in the conventional manner.
DEPLETION: The exhaustion of a petroleum reservoir; the reduction in value of a
wasting asset by removing minerals; for tax purposes, the removal and sale of
minerals from a mineral deposit.
DISTRIBUTABLE INCOME: An amount paid to Unit holders 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 and royalty interest owned by it in the San Juan Basin.
SECTION 29 TAX CREDIT: A Federal income tax credit available under Section 29 of
the Internal Revenue Code for producing coal seam gas (and other nonconventional
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.
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> 9
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 1,204 gross (897 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, 1999, the production index for the San Juan Basin properties is estimated to
be approximately 11 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.
In 1998, BROG announced that the New Mexico Oil Conservation Division
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
Trustee that there is an application pending in New Mexico for approval of
160-acre infill drilling in the Fruitland Coal.
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 1999, these coal seam wells produced a total of
approximately 14,439,628 MMBtu of gas from the Underlying Properties, which was
sold at an average price of $1.58 per MMBtu.
Production from coal seam wells drilled prior to January 1, 1993, qualifies
for Federal income tax credits through 2002. For 1999 the credit was
approximately $1.04 per MMBtu. During 1999, potential Section 29 tax credits of
approximately $.163594 per Unit were generated for Trust Unit holders from
production from coal seam wells.
During 1999, BROG incurred approximately $10.5 million of capital
expenditures for the drilling and completion of 71 gross (7.22 net) conventional
wells, recompletion of 4 gross (1.36 net) conventional wells, drilling and
completion of 3 gross (.93 net) coal seam wells, recompletion of 1 gross
(.54 net) coal seam well and recavitation of 10 gross (.07 net) coal seam wells.
There were 53 gross (20.14 net) conventional wells, 25 gross (3.77 net)
conventional well recompletions, 3 gross (.39 net) coal seam wells, 7 gross
(.79 net) coal seam recompletions and 38 gross (.75 net) coal seam recavitations
in progress as of December 31, 1999.
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.
By letter dated April 7, 2000, BROG notified the Trust that BROG had
undercharged the Trust for capital expenditures and lease operating charges
related to non-operated properties
5
<PAGE> 10
DESCRIPTION OF THE PROPERTIES
since January of 1999. For the 1999 reporting period, these charges were
estimated by BROG to be approximately $1.2 million for lease operating charges
and $0.5 million for capital expenditures. For the 2000 reporting period, these
charges were estimated by BROG to be $0.5 million for lease operating charges
and $140,000 for capital expenditures. As a result, BROG asserts that it has
overpaid the Trust in the aggregate amount of $1.8 million. BROG intends to
deduct these charges from its April and May distributions to the Trust. The
Trust is considering the appropriateness of this proposed means of resolution
and is consulting with its advisors. No assurance can be given as to when and
how this issue will be resolved.
BROG has advised the Trust that capital projections for 2000 are estimated
to be $20.5 million. Approximately 95% of that amount will be attributable to
conventional projects. Of the 400 planned projects, 57 will be conventional new
drill locations at a cost of approximately $13.7 million, 99 ($5.2 million)
will be attributable to workovers, and 244 of the projects at a cost of $1.6
million will be miscellaneous facilities projects. Twenty-one of the 57 new
drilling projects planned for 2000 are on properties in which BROG owns 100% of
the working interest, so that the Trust's share of planned capital expenditures
is increased as compared to wells in which BROG owns only a partial working
interest.
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> 11
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, 1999,
distributable income increased to $31,795,667 from $29,598,402 distributed in
1998. The increase was primarily attributable to slightly higher gas and oil
prices and lower capital expenditures and lease operating expense. Included in
the 1999 distributable income was a payment by Burlington to the Trust in March
1999 of $892,498. After a rupture of the Williams "Trunk S" Pipeline disrupted a
significant flow of gas from BROG properties, BROG filed claims with insurance
carriers and subsequently received payments of its claims. Some of the claims
filed related to properties burdened by the Royalty. The amount of insurance
proceeds applicable to such properties was determined to be $1,189,996, of which
the Trust received 75% or $892,498. Interest income decreased from $68,648 in
1998 to $65,029 in 1999 primarily due to lower interest rates.
Total gas and oil production from the Underlying Properties for the five
years ended December 31, 1999, were as follows:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Gas - Mcf..... 39,940,175 41,507,353 41,948,567 40,738,422 34,387,190
Mcf per day... 109,425 113,719 114,928 111,307 94,211
Oil - Bbls.... 72,223 81,888 89,492 83,552 75,014
Bbls per day.. 198 224 245 228 206
- -----------------------------------------------------------------------------
</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 the portion attributable to the litigation settlement
proceeds described in Note 5 to the accompanying Financial Statements) are
summarized in the following table:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
-------------- -------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
Gas - Mcf................ 19,527,666 18,904,906 24,236,419 17,927,785 13,331,758
Average Price (per Mcf).. $ 1.78 $ 1.75 $ 2.21 $ 1.30 $ 1.25
Oil - Bbls............... 35,341 37,067 50,860 36,792 29,424
Average Price (per Bbl).. $ 14.41 $ 13.55 $ 19.35 $ 19.64 $ 14.43
- ------------------------------------------------------------------------------------------------------------
</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 pressure 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> 12
Royalty Income for the five years ended December 31, 1999, was determined as
shown in the following table:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Gross Proceeds from
the Underlying Properties:
- --------------------------
Gas........................... $ 69,928,312 $ 71,247,501 $ 91,495,060 $ 51,865,730 $ 41,483,305
Oil........................... 1,028,862 1,088,228 1,728,296 1,638,753 1,084,262
Other......................... 1,189,996 -0- -0- -0- -0-
------------ ------------ ------------ ------------ ------------
Total..................... $ 72,147,170 $ 72,335,729 $ 93,223,356 $ 53,504,483 $ 42,570,159
============ ============ ============ ============ ============
Less Production Costs:
- ----------------------
Capital Costs................. 10,556,159 12,828,300 7,231,696 7,223,281 6,560,277
Severance Tax - Gas........... 7,180,973 7,341,098 8,989,202 5,654,831 4,694,750
Severance Tax - Oil........... 106,335 117,454 167,844 176,379 115,474
Other......................... (95,445) 66,892 61,832 59,089 117
Lease Operating Expenses...... 10,896,526 11,558,172 10,776,145 11,838,345 10,991,152
------------ ------------ ------------ ------------ ------------
Total.................... 28,644,548 31,911,916 27,226,719 24,951,925 22,361,770
------------ ------------ ------------ ------------ ------------
Net Profits................... 43,502,622 40,423,813 65,996,637 28,552,558 20,208,389
Royalty Percentage............ 75% 75% 75% 75% 75%
Royalty Income................ $ 32,626,966 $ 30,317,860 $ 49,497,479 $ 21,414,419 $ 15,156,292
============ ============ ============ ============ ============
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
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. The receipt of the $250,000 from BROG for 1999
was received in January 2000 and distributed to Unit holders in February. The
final $250,000 offset will be made in December 2000. Excluding the impact of the
offset, monthly operating costs in 1999 averaged approximately $880,000, which
is lower than the $965,000 average in 1998. However, BROG has recently notified
the Trustee that the Trust was undercharged for approximately $1.2 million of
lease operating expenses related to non-operated properties since January 1999.
BROG intends to pass these additional charges through to the Trust in April and
May 2000. For additional information on capital expenditures, see "Description
of the Properties."
8
<PAGE> 13
RESULTS OF THE FOURTH QUARTERS OF 1999 AND 1998
Distributable income for the three months ended December 31, 1999, totaled
$11,294,344 ($.242322 per Unit) as compared to $5,585,582 ($.119840 per Unit)
for the quarter ended December 31, 1998. The amount distributed in the fourth
quarter of 1999 was higher than that of 1998 primarily because of higher average
gas and oil prices and lower capital costs.
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, 1999 and 1998 were as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------
Underlying Properties 1999 1998
- --------------------- ---------- -----------
<S> <C> <C>
Gas - Mcf........................ 9,815,852 10,243,360
Average Price (per Mcf)...... $ 2.33 $ 1.44
Oil - Bbls....................... 16,866 18,194
Average Price (per Bbl)...... $ 19.37 $ 11.50
Attributable to the Royalty
- ---------------------------
Gas - Mcf........................ 5,373,827 4,183,417
Oil - Bbls....................... 9,245 7,361
- --------------------------------------------------------------
</TABLE>
The average price of gas and oil increased in 1999 compared to the prior
year. The average price per barrel of oil during the fourth quarter of 1999 was
$7.87 per Bbl higher than that received in the fourth quarter of 1998 due to
increases 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 1999, coal seam
production from the Underlying Properties averaged 1,342,978 Mcf per month
compared to 1,401,000 Mcf per month during the fourth quarter of 1998.
Capital costs for the fourth quarter of 1999 totaled $2,565,094 compared to
$2,780,132 during the same period of 1998. The decrease was due to decreased
drilling activity in the fourth quarter of 1999. Operating costs in 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 litigation. The receipt of the
$250,000 from BROG for 1999 was not received by the Trust until January 2000.
Excluding the impact of the offset, lease operating costs for the fourth quarter
of 1999 averaged $971,839 per month in the fourth quarter compared to $1,073,500
per month in the fourth quarter of 1998.
9
<PAGE> 14
SAN JUAN BASIN ROYALTY TRUST
<TABLE>
<CAPTION>
Statements of Assets, Liabilities and Trust Corpus
December 31, 1999 and 1998
- ---------------------------------------------------------------------------------
Assets 1999 1998
- ------ ----------- -----------
<S> <C> <C>
Cash and Short-term Investments.................... $ 3,862,453 $ 2,665,562
Net Overriding Royalty Interests in Producing Oil and
Gas Properties - Net (Notes 2 and 3)........... 45,186,199 51,088,020
----------- -----------
$49,048,652 $53,753,582
=========== ===========
Liabilities and Trust Corpus
Distribution Payable to Unit Holders............... $ 3,862,453 $ 2,665,562
Trust Corpus - 46,608,796 Units of Beneficial Interest
Authorized and Outstanding..................... 45,186,199 51,088,020
----------- -----------
$49,048,652 $53,753,582
=========== ===========
- ---------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Statements of Distributable Income
for the Three Years Ended December 31, 1999
- -----------------------------------------------------------------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Royalty Income (Notes 2, 3 and 5).................. $32,626,966 $30,317,860 $49,497,479
Interest Income.................................... 65,029 68,648 99,403
----------- ----------- -----------
32,691,995 30,386,508 49,596,882
Expenditures - General and Administrative.......... 896,328 788,107 947,952
----------- ----------- -----------
Distributable Income............................... $31,795,667 $29,598,402 $48,648,930
=========== =========== ===========
Distributable Income per Unit (46,608,796 Units)... $ .682182 $ .635039 $ 1.043770
=========== =========== ===========
- -----------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Statements of Changes in Trust Corpus
for the Three Years Ended December 31, 1999
- ---------------------------------------------------------------------------------------------------
1999 1998 1997
------------ ----------- -----------
<S> <C> <C> <C>
Trust Corpus, Beginning of Period.................. $ 51,088,020 $ 56,119,448 $ 62,808,148
Amortization of Net Overriding Royalty Interest
(Notes 2 and 3)................................ (5,901,821) (5,031,428) (6,668,700)
Distributable Income............................... 31,795,667 29,598,402 48,648,930
Distributions Declared............................. (31,795,667) (29,598,402) (48,648,930)
============ ============ ============
Trust Corpus, End of Period........................ $ 45,186,199 $ 51,088,020 $ 56,119,448
============ ============ ============
- ---------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Financial Statements are an integral part
of these statements.
10
<PAGE> 15
[IMAGE]
pear cactus
<PAGE> 16
[IMAGE]
yucca brifolia
<PAGE> 17
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%.
The initial carrying value of the Royalty ($133,275,528) represented
Southland's historical net book value at the date of the transfer of the Trust.
Accumulated amortization as of December 31, 1999 and 1998 aggregated $88,089,329
and $82,187,508, 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, Burlington Resources Oil & Gas Company
("BROG"), to the Trustee for the Trust. Royalty income consists of the
amounts received by the owner of the interest burdened by the net
overriding royalty interest 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
not accrued in the month of production; certain cash reserves may be
established for contingencies which would not be accrued in financial
statements prepared in accordance with GAAP; and amortization of the
Royalty calculated on a unit-of-production basis is charged directly to
trust corpus.
13
<PAGE> 18
SAN JUAN BASIN ROYALTY TRUST
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 seam formations thereafter), generally qualifies for the Federal income tax
credit for producing nonconventional fuels if such production and the sale
thereof occurs before January 1, 2003. For 1999, this tax credit will be
approximately $1.04 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 summary Section 29 tax credit information related to
Trust properties by BROG, which information is then passed along to the Unit
holders. In Nielson-True Partnership, et al. v. Commissioner, a 1997 Tax Court
decision, the court ruled that nonconventional fuel (such a coal seam gas)
produced from a well drilled and completed in an otherwise qualifying formation
prior to December 31, 1992, is not eligible for the Section 29 credit unless the
producer has received an appropriate well category determination from the
Federal Energy Regulatory Commission ("FERC"). On March 23, 1999, the U.S. Court
of Appeals for the 10th Circuit affirmed that decision. Dictum (i.e., language
in the appeals court's decision which is not binding as precedent) even suggests
that, contrary to the clear implication of a 1993 Internal Revenue Service
ruling, lack of such a well category determination may render the Section 29
credit unavailable in respect of production from wells recompleted in a
qualified formation after January 1, 1993, the date that FERC's authority to
render well category determinations ended (so that obtaining the requisite
determination for any such well was impossible). Many producers assert that
wells meeting the definitional requirements applied by FERC in rendering well
category determinations are eligible for the Section 29 credit regardless of
whether a well category determination is actually applied for or received,
particularly for wells recompleted in qualifying formations after January 1,
1993, and additional litigation or other initiatives on this issue are to be
expected. In fact, on December 23, 1999, a petition was filed with the FERC by a
coalition of energy producers seeking reinstatement of the certification
process. By letter dated January 14, 2000, the U.S. Department of Energy
expressed its support of that petition and on January 27, 2000, the FERC issued
notice of proposed rulemaking by which its regulations would be amended to
reinstate certain regulations involving well category determinations for Section
29 tax credits for certain well recompletions commenced after January 1, 1993.
In some cases the extent to which production from the various coal seam gas
wells in which the Trust holds an interest would qualify for the Section 29
credit under the standards applied in the Nielson-True case is unclear, and the
Trustee has requested that BROG provide clarification and an assessment of the
effects of the foregoing, if any, on the Trust and its Unit holders. Pending
such clarification and assessment, or further developments, or both, however,
the availability of Section 29 credits to Unit holders in respect of some
portion of the Trust's coal seam gas production could be subject to debate and
challenge.
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 sub-
14
<PAGE> 19
SAN JUAN BASIN ROYALTY TRUST
sidiary 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, prima 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 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 was for a term of two years through
and including December 31, 1999, and provided 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. BROG has entered into a
contract dated November 10, 1999, for the sale of all volumes of Trust gas to
Duke Energy and Marketing L.L.C. That contract provides for delivery of gas at
various delivery points over a period commencing January 1, 2000, and ending
October 31, 2001, 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.
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. GAS IMBALANCE
In February 1999, the Trust's auditors notified the Trust of an apparent gas
imbalance. A gas imbalance occurs where more than one party is entitled to the
economic benefit of the production of natural gas, but the gas is sold for the
account of less than all of the parties. The resulting imbalance may be
corrected by various means including a cash settlement and/or a volume
adjustment whereby an increased percentage of future production is sold for the
account of the underproduced party or parties. The Trust's auditors suggested
that the subject imbalance might relate to the acquisition by BROG's
predecessor, Southland Royalty, of mineral properties which had been operated
under a Joint Operating Agreement between Southland Royalty and Unicon, the
seller of the properties. The Trust made inquiry of BROG concerning the
imbalance and BROG agreed to investigate the records. The Trustee met with BROG
representatives in June 1999 to discuss the investigation, and by correspondence
of September 24, 1999, BROG reported that the imbalance probably related to
problems experienced in the
15
<PAGE> 20
SAN JUAN BASIN ROYALTY TRUST
1980s and early 1990s by Southland Royalty and Unicon in their dealings with
Public Service Company of New Mexico. BROG reported that Unicon was flowing gas
to its account while Southland Royalty was not producing and that this created a
gas imbalance. The imbalance was addressed, as between Southland Royalty and
Unicon, by a reduction in the total purchase price for Unicon assets acquired by
Southland Royalty in June 1990. However, there was no payment made to the Trust
at the time of that acquisition.
BROG proposes to address the imbalance with the Trust based upon the terms
of a Gas Balancing Agreement it indicates was in place between Southland Royalty
and Unicon in connection with the Joint Operating Agreement applicable to the
subject properties and has offered $3,100,000 as a cash settlement. The Trust is
considering the appropriateness of this proposed means of resolution and this
offer and is consulting with its advisors. No assurance can be given as to when
and how this issue will be resolved.
8. 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.
9. 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.
10. 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, 1999 (in thousands, except unit
amounts):
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
Distributable
Income and
Royalty Distributable Distribution
1999 Income Income Per Unit
- ---- -------- ------------- --------------
<S> <C> <C> <C>
First Quarter....... $ 7,045 $ 6,792 $ .145721
Second Quarter...... 6,252 5,944 .127528
Third Quarter....... 7,909 7,766 .166611
Fourth Quarter...... 11,421 11,294 .242322
-------- -------- ---------
Total............ $ 32,627 $ 31,796 $ .682182
======== ======== =========
1998
- ----
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
======== ======== =========
- --------------------------------------------------------------------------
</TABLE>
INDEPENDENT AUDITOR'S 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, 1999 and
1998, and the related statements of distributable income and changes in trust
corpus for each of the three years in the period ended December 31, 1999. 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, 1999 and 1998, and the distributable income and changes
in trust corpus for each of the three years in the period ended December 31,
1999, on the basis of accounting described in Note 3.
/s/ DELOITTE & TOUCH LLP
Deloitte & Touche LLP
Fort Worth, Texas
March 24, 2000
16
<PAGE> 1
EXHIBIT 23
[CAWLEY, GILLESPIE & ASSOCIATES, INC. LETTERHEAD]
March 28, 2000
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, 1999 and in the
San Juan Basin Royalty Trust Annual Report for the year ended December 31, 1999
based on reserve reports dated March 22, 2000 prepared by Cawley, Gillespie &
Associates, Inc.
Sincerely,
/s/ CAWLEY, GILLESPIE & ASSOCIATES, INC.
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, 1999, AND THE RELATED CONDENSED
STATEMENTS OF DISTRIBUTABLE INCOME AND CHANGES IN TRUST CORPUS FOR THE TWELVE
MONTH PERIOD ENDED DECEMBER 31, 1999.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 3,862,453
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 3,862,453
<PP&E> 133,275,528
<DEPRECIATION> 88,089,329
<TOTAL-ASSETS> 49,048,652
<CURRENT-LIABILITIES> 3,862,453
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 45,186,199
<TOTAL-LIABILITY-AND-EQUITY> 49,048,652
<SALES> 0
<TOTAL-REVENUES> 32,691,995
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 896,328
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 31,795,667
<INCOME-TAX> 0
<INCOME-CONTINUING> 31,795,667
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 31,795,667
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
