<PAGE>
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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, 1997, or
[_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-8032
SAN JUAN BASIN ROYALTY TRUST
(Exact name of registrant as specified in the San Juan Basin Royalty Trust
Indenture)
<TABLE>
<S> <C>
TEXAS 75-6279898
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NUMBER)
BANK ONE, TEXAS, N.A. 76113
TRUST DEPARTMENT (ZIP CODE)
P. O. BOX 2604
FORT WORTH, TEXAS
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
</TABLE>
(817) 884-4630
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON
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 March 25, 1998, there were 46,608,796 Units of Beneficial Interest of the
Trust outstanding with an aggregate market value on that date of $372,870,368.
DOCUMENTS INCORPORATED BY REFERENCE
"Units of Beneficial Interest" at page 2; "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 1997 and 1996" 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 security holders for fiscal year ended December 31, 1997 are
incorporated herein by reference for Item 2 (Properties), Item 3 (Legal
Proceedings), Item 5 (Market for Units of the Trust and Related Security
Holder Matters), Item 7 (Management's Discussion and Analysis of Financial
Condition and Results of Operation) and Item 8 (Financial Statements and
Supplementary Data) of Part II of this Report.
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<PAGE>
PART I
ITEM 1. BUSINESS
The San Juan Basin Royalty Trust (the "Trust") is an express trust created
under the laws of the state of Texas by the "San Juan Basin Royalty Trust
Indenture" (the "Trust Indenture") entered into on November 3, 1980, between
Southland Royalty Company ("Southland Royalty") and The Fort Worth National
Bank, a banking association organized under the laws of the United States, as
Trustee. The Trustee is now Bank One, Texas, N.A. The principal office of the
Trust (sometimes referred to herein as the "Registrant") is located at 500
Throckmorton Street, Fort Worth, Texas 76102, Attention: Corporate Trust
Department (telephone number 817/884-4630).
On October 23, 1980, the stockholders of Southland Royalty approved and
authorized that company's conveyance of a net overriding royalty interest
(equivalent to a net profits interest) to the Trust for the benefit of the
stockholders of Southland Royalty of record at the close of business on the
date of the conveyance consisting of a 75% net overriding royalty interest
carved out of that company's oil and gas leasehold and royalty interests in
the San Juan Basin of northwestern New Mexico. The conveyance of this interest
(the "Royalty") was made on November 3, 1980, effective as to production from
and after November 1, 1980 at 7:00 A.M.
The Royalty was carved out of and now burdens those properties and interests
as more particularly described under "Item 2. Properties" herein.
The Royalty constitutes the principal asset of the Trust and the beneficial
interests in the Royalty are divided into that number of Units of Beneficial
Interest (the "Units") of the Trust equal to the number of shares of the
common stock of Southland Royalty outstanding as of the close of business on
November 3, 1980. Each stockholder of Southland Royalty of record at the close
of business on November 3, 1980, received one Unit for each share of the
common stock of Southland Royalty then held.
The function of the Trustee is to collect the income attributable to the
Royalty, to pay all expenses and charges of the Trust, and then distribute the
remaining available income to the Unit holders. The Trust is not empowered to
carry on any business activity and has no employees, all administrative
functions being performed by the Trustee.
In 1985, Southland Royalty became a wholly-owned subsidiary of Burlington
Northern Inc. ("BNI"). In 1988, BNI transferred its natural resource
operations to Burlington Resources Inc. ("BRI") as a result of which Southland
Royalty became a wholly-owned indirect subsidiary of BRI. As a result of these
transactions, El Paso Natural Gas Company ("El Paso"), Meridian Oil, Inc.
("MOI") and Meridian Oil Trading Inc. ("MOTI") also became indirect
subsidiaries of BRI. Effective January 1, 1996, Southland Royalty, a wholly-
owned subsidiary of MOI, was merged with and into MOI, by which action the
separate corporate existence of Southland Royalty ceased and MOI survived and
succeeded to the ownership of all of the assets, has the rights, powers and
privileges and assumed all of the liabilities and obligations of Southland
Royalty. Subsequent to the merger, MOI changed its name to Burlington
Resources Oil & Gas Company ("BROG").
The term "net proceeds" as used in the November 3, 1980 conveyance means the
excess of "gross proceeds" received by BROG during a particular period over
"production costs" for such period. "Gross proceeds" means the amount received
by BROG (or any subsequent owner of the interests from which the Royalty was
carved) from the sale of the production attributable to the interests from
which the Royalty was carved (the "Underlying Properties"), subject to certain
adjustments. "Production costs" generally means costs incurred on an accrual
basis by BROG in operating its properties and interests out of which the
Royalty was carved, including both capital and non-capital costs. For example,
these costs include development drilling, production and processing costs,
applicable taxes, and operating charges. If production costs exceed gross
proceeds in any month, the excess is recovered out of future gross proceeds
prior to the making of further payment to the Trust, but the Trust is not
otherwise liable for any production costs or other costs or liabilities
attributable to these properties and interests or the minerals produced
therefrom. If at any time the Trust receives
1
<PAGE>
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.
As the year 2000 approaches, there are uncertainties concerning whether
computer systems will properly recognize date-sensitive information when the
year changes to 2000. Systems that do not properly recognize such information
could generate erroneous data or fail. The Trust is in communication with
third parties with which it deals, but it is not yet possible to fully assess
the effect of a third party's inability to adequately address year 2000
issues.
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 the Trustee by BROG.
2
<PAGE>
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. Based upon information received from the Trust's
independent petroleum engineers, the Trust properties contain 3,038 gross (909
net) economic wells, including dual completions. Production from conventional
gas wells is primarily from the Pictured Cliffs, Mesa Verde and Dakota
formations. During 1988, Southland Royalty began development of coal seam
reserves in the Fruitland 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, 1997, 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 1997, BROG incurred approximately $7.2 million of capital
expenditures for the drilling and completion of 64 gross (3.53 net)
conventional wells, recompletion of 14 gross (5.4 net) conventional wells,
drilling and completion of 1 gross (.84 net) coal seam well, and 21 gross
(2.32 net) coal seam recavitations. There were 5 (1.22 net) new conventional
wells, 3 (1.08 net) conventional recompletions, 11 gross (.42 net) coal seam
recompletions, 5 (.20 net) coal seam recavitations, and 1 (.04 net) coal seam
well in progress as of December 31, 1997. During 1996, there were 14 gross
(1.50 net) conventional wells completed. There was 1 gross (.05 net) coal seam
well and 17 gross (1.96 net) conventional wells in progress at December 31,
1996. There were 4 gross (.16 net) conventional wells recompleted as coal seam
wells, 17 gross (5.63 net) coal seam wells recavitated and 9 gross (5.93 net)
conventional wells recompleted through December 31, 1996.
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, 1997
were as follows:
<TABLE>
<CAPTION>
1997 1996 1995
------------------- ------------------- -------------------
OIL GAS OIL GAS OIL GAS
(BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF)
------- ----------- ------- ----------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Production......... 50,860 24,236,419 36,792 17,927,785 29,424 13,331,758
Average Price...... $ 19.35 $ 2.21 $ 19.64 $ 1.30 $ 14.43 $ 1.25
</TABLE>
PRICING INFORMATION
Gas produced in the San Juan Basin is sold in both interstate and intrastate
commerce. Reference is made to "Regulation" for information as to federal
regulation of prices of oil and natural gas. Gas production from the
properties from which the Royalty was carved totaled 41,948,567 Mcf during
1997.
Prior to 1985, sales contracts with El Paso, Sunterra Gas Gathering Company,
formerly Southern Union Gathering Company ("Sunterra"), and Northwest Pipeline
Company ("Northwest") generally provided for payment of the maximum lawful
prices permitted under the Natural Gas Policy Act of 1978 ("NGPA"). Sunterra
is a subsidiary of Public Service Company of New Mexico ("PNM").
In 1985, Sunterra sold its gas gathering, transportation and distribution
facilities in New Mexico and its rights as purchaser under its San Juan Basin
gas contracts to PNM. Under such contracts, gas prices were to be redetermined
annually on April 1 to an average of the highest price levels being paid in
New Mexico. Also in 1985, PNM announced its intention to attempt to
renegotiate the gas contracts with gas producers in the San Juan Basin,
including Southland Royalty, with its objective being to reduce the overall
price for such gas. During the course of these negotiations PNM unilaterally
reduced the price paid for gas sales below the level required by the gas
contracts.
3
<PAGE>
In May 1988, PNM filed suit in the United States District Court in New
Mexico seeking (i) a declaratory judgment that PNM had no prior liability for
gas purchased at prices below the contract prices and (ii) a permanent
injunction prohibiting future claims against PNM for gas purchases at prices
below the contract prices. PNM claimed the pricing provisions were the result
of a conspiracy in violation of antitrust laws. Southland Royalty counter-
claimed against PNM alleging breach of both the pricing provisions and the
minimum take requirements of the gas purchase contracts. In June 1988,
Southland Royalty filed a separate breach of contract suit in a State District
Court in Harris County, Texas on these same claims against PNM alleging
damages in excess of $40 million. During 1988, both El Paso and Northwest
abandoned the Natural Gas Act ("NGA") service obligation to purchase gas in
accordance with Federal Energy Regulatory Commission ("FERC") Order 490 and
490-A.
Southland Royalty informed the Trust that effective March 1, 1990 a
settlement of this litigation was reached. Under the terms of the settlement
agreement, Southland Royalty released all claims that it had against PNM,
Sunterra and Gas Company of New Mexico (a division of PNM) ("Gas
Company")under the intrastate gas purchase contracts, as well as claims it
held on gas sold pursuant to the interstate contracts discussed previously.
PNM and Sunterra agreed to pay Southland Royalty $54.5 million in
installments. An initial payment of $18,166,000 was paid in connection with
the execution of the settlement agreement. The second payment of $18,167,000
was paid on March 1, 1991. The remaining balance of $18,167,000 was paid on
March 2, 1992 plus interest of $1,635,300.
Southland Royalty distributed to the Trust 75% (the amount of its net
overriding royalty interest) of the $49,435,300 in cash received in settlement
that it attributed to past and future pricing claims under the intrastate and
interstate gas purchase contracts, less amounts attributed by Southland
Royalty to royalties and production taxes. Southland Royalty retained a total
of $6,700,000 from the settlement proceeds that it attributed to quantity
claims.
Because of the difficulty in determining the exact value of consideration
received under the renegotiated contracts referred to below, Southland Royalty
informed the Trust that it would not attribute value to quantity claims under
the renegotiated contracts and the Trust would receive 75% (the amount of its
net overriding royalty interest) of any value that ultimately inured to those
contracts.
Southland Royalty also informed the Trust that the settlement also provided
for new gas purchase agreements replacing the then current intrastate and
interstate gas purchase agreements. Southland Royalty entered into five-year
gas purchase, gas processing and gas gathering agreements with Sunterra and
gas Company that were effective as of July 1, 1990. The new contracts applied
to all lands previously dedicated to Sunterra and Gas Company for first sales
of natural gas sold into interstate or intrastate markets, except that the new
gas purchase contracts exclude all gas produced and sold from coal seam wells.
The new gas purchase contracts provided for purchase rights and obligations
during the winter heating season only. During the remainder of the year,
Southland Royalty through MOTI could market the gas through any arrangements
it deemed advisable. Under the new gas contracts, Southland Royalty would
receive prices, inclusive of severance taxes, ranging from approximately $2.35
per month MMBtu to $3.37 per MMBtu over the life of the contracts. The
contracts provided for certain "take-or-pay obligations" if specified
quantities of gas (66% of the maximum volume that can be produced into the
gathering system against the Assumed Working Pressure of a purchase period and
lawfully made available for sale to the gas purchaser each day during a
purchase period) are not taken by the purchasers during the winter heating
season. Should the required minimum not be taken, then a reservation fee was
to be paid to Southland Royalty to be determined by multiplying 20% of the
price of gas for the applicable time period times the deficiency for the
purchase period. See Note 5 of Notes to Financial Statements of the Trust's
Annual Report to security holders for the year ended December 31, 1997 for
further discussion of this settlement and its impact upon the Trust.
The gas gathering contract provided for transportation of gas not taken by
Sunterra and Gas Company during the winter heating season and during the
remainder of the year. The gas processing agreement provided that Southland
Royalty received 80% of the plant products derived from processing the gas.
The processing company was to retain the remaining 20% as its fee for
processing the gas.
4
<PAGE>
In 1991, due to the low level of natural gas prices, Sunterra informed
Southland Royalty that it would not take any significant volume of gas during
the 1991-1992 winter heating season and would simply pay the "take or pay
obligation" amount. Consequently, the majority of the wells subject to the
contracts would remain shut-in during the winter heating season. Southland
Royalty informed the Trustee that, in an attempt to maximize production and
revenue from the Trust properties, it had entered into an agreement that would
amend the terms of the contracts discussed above for only the 1991-1992 winter
heating season. The amendment provided that Sunterra and gas Company could
purchase approximately 35% of the contract provided take levels at a wellhead
price slightly higher than the spot wellhead index price for the San Juan
Basin. Any gas purchased by Sunterra or Gas Company above this level would
average $2.63 per MMBtu. Southland Royalty would be free to market the
remaining deliverable gas to other purchasers. During 1992 Gas Company and
Sunterra purchased 702,629 Mcf and 3,241,500 Mcf, respectively, at average
prices of $2.25 and $1.98 per Mcf, respectively, from the properties from
which the Royalty was carved.
Southland Royalty informed the Trust that a one year contract amendment was
agreed to with Gas Company and Sunterra for the 1992-1993 winter heating
season. Gas Company and Sunterra were required to purchase a minimum of 11,500
MMBtu per day under the intrastate contract and a minimum of 16,550 MMBtu per
day under the interstate contracts at the contract specified prices of $2.695
per MMBtu and $2.94 per MMBtu, respectively. A portion of the excess gas up to
9,000 MMBtu per day for the intrastate contracts and 12,000 MMBtu per day for
the interstate contracts was released for spot sales, with a recall provision
at an average contract price. Southland Royalty waived any claims for
deficiency payments under the reservation fees.
Southland Royalty informed the Trust that a similar amendment was entered
into for the 1993-1994 winter heating season. Gas Company and Sunterra were
required to purchase a minimum of 1,696,485 MMBtu with an average minimum of
5,100 MMBtu per day under the intrastate contracts between November 1, 1993
and March 1994 and a minimum of 1,401,570 MMBtu with an average minimum of
7,000 MMBtu per day under the interstate contract between December 1, 1993 and
February 28, 1994 at the contract specified prices of $2.884 per MMBtu
and$3.146 per MMBtu, respectively. All remaining intrastate gas in excess of
11,300 MMBtu per day during the period November 1, 1993 and through March
31,1994 and all remaining interstate gas in excess of 15,600 MMBtu per day
during the period December 1, 1993 through February 28, 1994 was released for
spot sales, with a recall provision at a price during the months of November
1993 and March 1994 of $2.884 per MMBtu and $3.015 per MMBtu for the months
December 1993, January 1994, and February 1994.
Southland Royalty informed the Trust that an amendment was also entered into
for the 1994-1995 winter heating season. Gas Company and Sunterra were
required to purchase, at the wellhead, an average volume of 10,529 MMBtu per
day at $2.884 per MMBtu for the period beginning November 1, 1994 and ended
March 31, 1995 and an additional 14,900 MMBtu per day at $3.146 per MMBtu for
the period beginning December 1, 1994 and ended February 28, 1995. Gas Company
and Sunterra were granted a make-up period of four months beginning April
1,1995 to fulfill this purchase obligation. Gas Company and Sunterra were also
granted recall rights on volumes up to 15,000 MMBtu per day at the tailgate of
the Kutz and Lybrook plants, provided they nominated the full contract volume
specified above. The price for recall was to be the average of the first and
second issues of the Inside FERC EPNG SJ Index.
The Trust was informed that effective July 1, 1995, Williams Field Services
("Williams") purchased the Kutz and Lybrook processing plants and the
gathering systems behind these plants which were owned by Sunterra, Gas
Company and Sunterra Gas Processing Company ("SGPC") and that new gathering
and processing agreements with Williams were entered into which contain
acceptable rates, terms and conditions. The new agreements replaced the then
current gathering and processing agreements with Gas Company, Sunterra and
SGPC effective on the closing date of the sale of these facilities to
Williams.
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.
5
<PAGE>
Agreement was reached, among other things, regarding marketing arrangements
for the sale of Trust gas, oil and natural gas liquids products going forward
as follows:
(i) BROG's pre-existing contract with a third-party purchaser covering
baseload gas volumes in the firm amount of 45,000 MMBtus/day was to remain
effective for a period of one year from July 1, 1996. The remaining volumes
of Trust gas were marketed by an independent marketer, El Paso Energy
Marketing Company ("El Paso"), a subsidiary of El Paso Energy Corporation,
beginning October 1, 1996. BROG agreed that subsequent contracts for the
sale of Trust gas would require the written approval of an independent gas
marketing consultant acceptable to the Trust;
(ii) BROG will continue to market the Trust oil and natural gas liquids
but will 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; and
(iii) The Trust has retained access to BROG's current gas
transportation, gathering, processing and treating agreements with third
parties through the remainder or their primary terms. Additionally, El Paso
could utilize BROG's eastern transportation agreement for delivery from the
San Juan Basin on the El Paso Natural Gas Company pipeline to pipelines in
West Texas of up to 13,333 MMBtu's/day of gas produced from Trust
properties for a period of one year commencing October 1, 1996.
The gas purchase contracts described in subparagraph (i), above, were
continued, by agreement of the parties until December 31, 1997. Effective
January 1, 1998, all volumes of Trust gas became subject to the terms of a
Natural Gas Sales and Purchase Contract between BROG and El Paso. That
contract is for a term of two years through and including December 31, 1999
and provides for the sale of Trust gas at prices which will fluctuate in
accordance with published indices for gas sold in the San Juan Basin of New
Mexico. BROG entered into the contract with El Paso after soliciting and
receiving competitive bids in late 1997 from six major gas marketing firms to
market and/or purchase the Trust gas. While it is impossible to predict the
exact economic value of gas contracts, the Trust has been advised by its
independent gas marketing consultant that the contract with El Paso should
provide for the average highest sales price for natural gas in the San Juan
Basin over the two-year term of the contract.
See Note 5 of Notes to Financial Statements of the Trust's Annual Report to
securityholders for the year ended December 31, 1997 for further discussion of
this settlement and its impact on the Trust.
OIL AND GAS RESERVES
The following are definitions adopted by the Securities and Exchange
Commission ("SEC") and the Financial Accounting Standards Board which are
applicable to terms used within this Item:
"Proved reserves" are those estimated quantities of crude oil, natural
gas and natural gas liquids, which, upon analysis of geological and
engineering data, appear with reasonable certainty to be recoverable in the
future from known oil and gas reservoirs under existing economic and
operating conditions.
"Proved developed reserves" are those proved reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.
"Proved undeveloped reserves" are those proved reserves which are
expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required.
"Estimated future net revenues" are computed by applying current prices
of oil and gas (with consideration of price changes only to the extent
provided by contractual arrangements and allowed by federal regulation) to
estimated future production of proved oil and gas reserves as of the date
of the latest balance sheet presented, less estimated future expenditures
(based on current costs) to be incurred in developing and producing the
proved reserves, and assuming continuation of existing economic conditions.
"Estimated future net revenues" are sometimes referred to herein as
"estimated future net cash flows."
6
<PAGE>
"Present value of estimated future net revenues" is computed using the
estimated future net revenues and a discount rate of 10%.
The independent petroleum engineers' reports as to the proved oil and gas
reserves as of December 31, 1995, 1996 and 1997 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1994
to December 31, 1997 (in thousands):
<TABLE>
<CAPTION>
NATURAL
OIL GAS
(BBLS) (MCF)
------ -------
<S> <C> <C>
Reserves as of December 31, 1994............................. 612 201,405
Revisions of previous estimates.............................. (165) (22,529)
Extensions, discoveries and other additions.................. 0 906
Production................................................... (29) (13,332)
---- -------
Reserves as of December 31, 1995............................. 418 166,450
Revisions of previous estimates.............................. 272 95,106
Extensions, discoveries and other additions.................. 4 2,367
Production................................................... (37) (17,928)
---- -------
Reserves as of December 31, 1996 657 245,995
---- -------
Revisions of previous estimates.............................. (81) (25,734)
Extensions, discoveries and other additions.................. 34 7,314
Production................................................... (51) (24,236)
Reserves as of December 31, 1997............................. 559 203,339
==== =======
Estimated quantities of proved developed reserves of crude oil and natural
gas as of December 31, 1997, 1996 and 1995 were as follows (in thousands):
<CAPTION>
CRUDE NATURAL
OIL GAS
(BBLS) (MCF)
------ -------
<S> <C> <C>
1997......................................................... 547 199,753
1996......................................................... 637 239,962
1995......................................................... 418 159,650
</TABLE>
Generally, the calculation of oil and gas reserves takes into account a
comparison of the value of the oil or gas to the cost of producing those
minerals, in an attempt to cause minerals in the ground to be included in
reserve estimates only to the extent that the anticipated costs of production
will be exceeded by the anticipated sales revenue. Accordingly, an increase in
sales price and/or a decrease in production cost can itself result in an
increase in estimated reserves and declining prices and/or increasing costs
can result in reserves reported at less than the physical volumes actually
thought to exist. The Financial Accounting Standards Board requires
supplemental disclosures for oil and gas producers based on a standardized
measure of discounted future net cash flows relating to proved oil and gas
reserve quantities. Under this disclosure, future cash inflows are estimated
by applying year-end prices of oil and gas relating to the enterprise's proved
reserves to the year-end quantities of those reserves. Future price changes
are only considered to the extent provided by contractual arrangements in
existence at year-end. The standardized measure of discounted future net cash
flows is achieved by using a discount rate of 10% a year to reflect the timing
of future net cash flows relating to proved oil and gas reserves.
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.
7
<PAGE>
The 1997, 1996 and 1995 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>
1997 1996 1995
--------- -------- --------
<S> <C> <C> <C>
Balance, January 1........................... $ 439,037 $106,937 $157,627
Revisions of prior-year estimates, change in
prices
and other................................... (227,855) 338,208 (51,819)
Extensions, discoveries and other additions.. 7,915 4,612 522
Accretion of discount........................ 43,904 10,694 15,763
Royalty income............................... (49,497) (21,414) (15,156)
--------- -------- --------
Balance, December 31......................... $ 213,504 $439,037 $106,937
========= ======== ========
</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 $2.21 per Mcf of conventional gas, $1.55 per Mcf
of coal seam gas and $15.97 per Bbl of oil were used at December 31, 1997, in
determining future net revenue. The downward revision is primarily due to
significantly lower gas prices in December 1997 as compared to December 1996.
December average prices of $4.04 per Mcf of conventional gas, $2.84 per Mcf
of coal seam gas and $23.18 per Bbl of oil were used at December 31, 1996, in
determining future net revenue. The upward revision is primarily due to
significantly higher gas prices in December 1996.
December average prices of $1.36 per Mcf of conventional gas, $0.85 per Mcf
of coal seam gas and $17.24 per Bbl of oil were used at December 31, 1995, in
determining future net revenue.
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, 1997, 1996 and 1995 (in thousands except amounts per
Unit):
<TABLE>
<CAPTION>
1997 1996 1995
------------------ ------------------ ------------------
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............ $372,830 $213,504 $822,131 $439,037 $184,055 $106,937
Proved Developed........ $365,509 $211,580 $799,664 $430,365 $175,824 $104,378
Total Proved Per Unit... $ 8.00 $ 4.58 $ 17.64 $ 9.42 $ 3.95 $ 2.29
</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.
8
<PAGE>
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 or 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 FERC. The Natural Gas Wellhead Decontrol
Act of 1989 ("Decontrol Act") terminated federal price controls on wellhead
sales of domestic natural gas on January 1, 1993. Consequently, sales of
natural gas may be made at market prices, subject to applicable contract
provisions. The FERC's jurisdiction over natural gas transportation and
storage was unaffected by the Decontrol Act.
Sales of natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation
remain subject to extensive federal and state regulation. Several major
regulatory changes have been implemented by Congress and the FERC from 1985 to
the present that affect the economics of natural gas production,
transportation, and sales. In addition, the FERC continues to promulgate
revisions to various aspects of the rules and regulations affecting those
segments of the natural gas industry, most notably interstate natural gas
transmission companies, that remain subject to the FERC's jurisdiction. These
initiatives may also affect the intrastate transportation of gas under certain
circumstances. The stated purpose of many of these regulatory changes is to
promote competition among the various sectors of the natural gas industry and
these initiatives generally reflect more light-handed regulation of the
natural gas industry. The ultimate impact of the rules and regulations issued
by the FERC since 1985 cannot be predicted. In addition, many aspects of these
regulatory developments have not become final but are still pending judicial
and FERC final decisions.
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 recently
pursued 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. The Trust is not able to predict what effect, if any, these
regulations will have on it, but other factors being equal, the regulations
may tend to increase transportation costs or reduce wellhead prices for crude
oil.
Coal Seam Tax Credit
The Trust began receiving royalty income from coal seam wells beginning in
1989. Under Section 29 of the Internal Revenue Code, production from coal seam
gas wells drilled prior to January 1, 1993, qualifies for the federal income
tax credit for producing non-conventional fuels. Production from wells drilled
after December 31, 1979 but prior to January 1, 1993, to a formation beneath
qualifying coal seam formation which are later completed into such formation
also qualifies for the tax credit. This tax credit for 1997 was approximately
$1.05 per MMBtu and applies to production through the year 2002. Each
Unitholder must determine his pro rata share
9
<PAGE>
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.
Other Regulation
The oil and natural gas industry is also subject to compliance with various
other federal, state and local regulations and laws, including, but not
limited to, environmental protection, occupational safety, resource
conservation and equal employment opportunity.
ITEM 3. LEGAL PROCEEDINGS
On September 4, 1996, the Trustee announced the settlement of the Litigation
filed by the Trustee against BROG and Southland Royalty Company. The
Litigation, which was filed in the state district court of Santa Fe County,
New Mexico, Cause No. SF 94-1982(c), was dismissed on September 12, 1996.
The claims asserted on behalf of the Trust in the Litigation included breach
of contract, breach of the covenant of good faith and fair dealing, breach of
express good faith duty, constructive fraud, unjust enrichment, prima facie
tort, intentional interference with contract and conspiracy. The relief sought
included compensatory and punitive damages, an accounting and an injunction
relating to marketing the production from the Underlying Properties. BROG has
denied and continues to deny the allegations made against it in the
Litigation, but the parties have agreed to settle the Litigation as outlined
herein.
BROG agreed (i) to pay $19,750,000 in cash plus interest earnings thereon
from September 5, 1996, in settlement of underpayment of royalty claims of the
Trust; and (ii) commencing in 1997, to credit the Trust with $250,000 per year
for five years as an offset against lease operating expenses chargeable to the
Trust. BROG also agreed to make certain adjustments that represent cost
reductions favorable to the Trust in the ongoing charges for coal seam gas
gathering and treating on BROG's Val Verde system. Additionally, the Trustee
and BROG established a formal protocol intended to provide the Trustee and its
representatives improved access to BROG's books and records applicable to the
Underlying Properties.
Agreement was also reached regarding marketing arrangements for the sale of
Trust gas, oil and natural gas liquids products going forward as more
particularly described in "Pricing Information" under Item 2. Properties
herein.
The $19,750,000 (or $.423739 per unit of beneficial interest) was paid to
the Trust on September 30, 1996 and distributed on October 15, 1996, to
unitholders of record as of September 30, 1996, (the "Record Date"). The
distribution is taxable to unit holders as of such Record Date. This
distribution was in addition to the regular monthly distribution on October
15, 1996.
For additional information concerning legal proceedings, Note 5 of the Notes
to Financial Statements at pages 13 and 14 of the Trust's Annual Report to
security holders for the year ended December 31, 1997 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, 1997.
10
<PAGE>
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 31,1997, is
herein incorporated by reference.
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------------------------
1997 1996 1995 1994 1993
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Royalty income(1)....... $ 49,497,479 $ 41,236,424 $ 15,156,292 $ 23,280,188 $ 37,576,121
Distributable income.... 48,648,930 37,803,167 13,790,101 22,632,493 36,760,797
Distributable income per
Unit.................... 1.043770 0.811072 0.295867 0.485584 0.788710
Distributions per Unit.. 1.043770 0.811072 0.295867 0.485584 0.788710
Total assets, December
31...................... 61,231,280 65,935,976 70,554,982 75,531,405 82,701,203
</TABLE>
- --------
(1) The royalty income distributions for 1993 and 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
1997 and 1996" at pages 7 through 9 of the Trust's Annual Report to
securityholders for the year ended December 31, 1997, are herein incorporated
by reference.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Not applicable
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Financial Statements of the Trust and the and the notes thereto at page
10 et seq., of the Trust's Annual Report to security holders for the year ended
December 31, 1997, are herein incorporated by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
11
<PAGE>
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
Unitholders, by the affirmative vote of the holders of a majority of all the
Units then outstanding.
ITEM 11. EXECUTIVE COMPENSATION
During the year ended December 31, 1997, 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 $132,880(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, 1997, information with respect to each person
known to own beneficially more than 5% of the outstanding Units of the Trust:
<TABLE>
<CAPTION>
AMOUNT AND
NATURE OF BENEFICIAL
NAME AND ADDRESS OWNERSHIP PERCENT OF CLASS
---------------- -------------------- ----------------
<S> <C> <C>
Fund American Enterprises
Holdings, Inc.(1) ............... 5,994,876 Units 14.4%
80 South Main Street
Hanover, New Hampshire 03755
Capital Guardian Trust Company
(2).............................. 4,078,800 Units 8.8%
333 South Hope Street, 52nd Floor
Los Angeles, California 90071
</TABLE>
- --------
(1) This information was provided to the Trust on Form 4, dated December 3,
1997, as filed with the Securities and Exchange Commission (the "SEC") by
Fund American Enterprises Holdings, Inc.("FAEH"), which indicated that
these Units were owned by Fund American Enterprises, Inc.
The Form 4 and an Amendment Number 8 to Schedule 13D, dated December 2,
1997 filed by FAEH with the SEC may be reviewed for more detailed
information concerning the matters summarized herein.
(2) This information was provided to the SEC and to the Trust in Amendment
Number 4 to Schedule 13G, dated February 10, 1998, filed jointly by The
Capital Group Companies, Inc. ("Capital Group") and Capital Guardian Trust
Company ("Capital Guardian"). Capital Guardian is a wholly-owned operating
subsidiary of Capital Group. Capital Guardian exercised investment
discretion with respect to the 4,078,800 Units which were owned by various
institutional investors. Capital Group disclaims beneficial ownership of
such Units pursuant to Rule 13d-4 of the Securities Exchange Act of 1934.
Both Capital Group and Capital Guardian report sole voting power over
3,403,800 Units and sole dispositive power over 4,078,800 Units.
The Amendment Number 4 to Schedule 13G filed by Capital Group and Capital
Guardian with the SEC may be reviewed for more detailed information
concerning the matters summarized herein.
III-1
<PAGE>
(b) Security Ownership of Management. In various fiduciary capacities, Bank
One, Texas, N.A. owned, as of December 31, 1997, an aggregate of 29,272 Units
with the sole right to vote 23,672 of these Units and no right to vote 5,600
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, 1997
and Item 12(b) for information concerning Units owned by Bank One, Texas, N.A.
in various fiduciary capacities.
III-2
<PAGE>
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, 1997:
Independent Auditors' Report
Statement of Assets, Liabilities and Trust Corpus
Statements of Distributable Income
Statements of Changes in Trust Corpus
Notes to Financial Statements
FINANCIAL STATEMENT SCHEDULES
Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required information
is given in the financial statements or notes thereto.
<TABLE>
<CAPTION>
EXHIBITS
<C> <S>
(4)(a) --San Juan Basin Royalty Trust Indenture, dated November 3, 1980,
between Southland Royalty Company and The Fort Worth National Bank
(now Bank One, Texas, N.A.), as Trustee, heretofore filed as Exhibit
4(a) to the Trust's Annual Report on Form 10-K to the SEC for the
fiscal year ended December 31, 1980, is incorporated herein by
reference.*
(b) --Net Overriding Royalty Conveyance from Southland Royalty Company to
the Forth Worth National Bank (now Bank One, Texas, N.A.), as
Trustee, dated November 3, 1980 (without Schedules), heretofore
filed as Exhibit 4(b) to the Trust's Annual Report on Form 10-K to
the SEC for the fiscal year ended December 31, 1980, is incorporated
herein by reference.*
(13) --Registrant's Annual Report to security holders for fiscal year
ended December 31, 1997.**
(23) --Consent of Cawley, Gillespie & Associates, Inc., reservoir
engineer.**
(27) --Financial Data Schedule.**
</TABLE>
- --------
* A copy of this Exhibit is available to any Unit holder, at the actual cost
of reproduction, upon written request to the Trustee, Bank One, Texas,
N.A., P.O. Box 2604, Fort Worth, Texas 76113.
** Filed herewith.
REPORTS ON FORM 8-K
During the last quarter of the Trust fiscal year ended December 31, 1997, no
reports on Form 8-K were filed with the Securities and Exchange Commission by
the Trust.
IV-1
<PAGE>
SIGNATURE
Pursuant to the Requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
BANK ONE, TEXAS, N.A.
TRUSTEE OF THE SAN JUAN BASIN
ROYALTY TRUST
By: /s/ Lee Ann Anderson
_____________________________________
(Lee Ann Anderson)
Vice President
Date: March 31, 1998
(The Trust has no directors or executive officers)
<PAGE>
EXHIBIT 13
[PHOTO APPEARS HERE]
SAN JUAN BASIN ROYALTY TRUST 1997 ANNUAL REPORT & 10K
<PAGE>
The San Juan Basin Royalty Trust is building a World Wide Web
site for the convenience of investors. By mid-May
1998, information about the Trust and
its functions will be found at
www.sjbrt.com
The
principal asset of
the San Juan Basin Royalty
Trust consists of a 75% net overriding royal-
ty interest carved out of certain oil and gas leasehold and
royalty interests in the San Juan Basin of northwestern New Mexico.
<PAGE>
THE TRUST
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." From January 1, 1996, to
December 31, 1997, quarterly high and low sales prices and the aggregate amount
of monthly distributions per Unit paid each quarter were as follows:
- --------------------------------------------------------------------------------
Distributions
1995 High Low Paid
- ---- -------- ------- ----------
First Quarter__________________________ $ 8.8750 $7.5000 $ 0.391930
Second Quarter_________________________ 8.3125 7.2500 0.183766
Third Quarter__________________________ 10.1250 7.9375 0.206076
Fourth Quarter_________________________ 10.5626 8.6875 0.261998
----------
Total for 1997______________________ $ 1.043770
==========
1996
- ----
First Quarter__________________________ $ 6.8750 $5.8750 $ .084239
Second Quarter_________________________ 6.5000 5.6250 .063143
Third Quarter__________________________ 7.5000 6.0000 .488979
Fourth Quarter_________________________ 8.6250 6.1250 .174711
----------
Total for 1996______________________ $ .811072
==========
- -------------------------------------------------------------------------------
At December 31, 1997, 46,608,796 Units outstanding were held by 2,505 Unit
holders of record. The following table presents information relating to the
distribution of ownership Units:
Number of
TYPE OF UNIT HOLDERS Unit Holders Units Held
- -------------------- ------------ ----------
Individuals_______________________________________ 2,113 3,520,866
Fiduciaries_______________________________________ 356 1,190,649
Institutions______________________________________ 16 289,777
Brokers, Dealers and Nominees_____________________ 5 39,912,462
Corporations and Partnerships_____________________ 8 1,649,092
Miscellaneous_____________________________________ 7 45,950
------------ ----------
Total__________________________________________ 2,505 46,608,796
============ ==========
- --------------------------------------------------------------------------------
<PAGE>
TO UNIT HOLDERS
We are pleased to present the 1997 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,
1997, without exhibits. Production figures provided in this letter and in the
Trustee's Discussion and Analysis are based on information provided by
Burlington Resources Oil & Gas Company ("BROG").
The Trust was established in November 1980 by Trust Indenture between
Southland Royalty and The Fort Worth National Bank. Pursuant to the Indenture,
Southland Royalty conveyed to the Trust a 75% net overriding royalty interest
(equivalent to a net profits interest) carved out of Southland Royalty's oil and
gas leasehold and royalty interest in the San Juan Basin of northwestern New
Mexico. This net overriding royalty interest (the "Royalty") is the principal
asset of the Trust. The Form 10-K contains important information concerning,
among other things, the oil and gas reserves attributable to the Royalty and the
properties from which the Royalty was carved.
Under the Trust Indenture, Bank One, Texas, N.A. (successor trustee) as
Trustee, has the primary function of collecting monthly net proceeds ("Royalty
Income") attributable to the Royalty and making the monthly distributions to the
Unit holders after deducting administrative expenses and any amounts necessary
for cash reserves.
Income to Unit holders for the year 1997 was $48,648,930 or $1.043770 per
Unit. This distributable income consisted of Royalty Income of $49,497,479 plus
interest income of $99,403, less administrative expenses of $947,952.
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.
On January 2, 1996, Southland Royalty was merged with and became a wholly-
owned subsidiary of MOI. Subsequent to the merger, MOI changed its name to
Burlington Resources Oil & Gas Company.
Information about the Trust's estimated proved reserves of gas, including
coal seam gas, and of oil as well as the present value of net revenues
discounted at 10% can be found in Item 2 of the accompanying Form 10-K.
Royalty Income is generally considered portfolio income under the passive
loss rules enacted by the Tax Reform Act of 1986. Therefore, it appears that
Unit holders should not consider the taxable income from the Trust to be passive
income in determining net passive income or loss. Unit holders should consult
their tax advisors for further information.
Unit holders of record will continue to receive an individualized tax
information letter for each of the quarters ending March 31, June 30 and
September 30, 1998, and for the year ending December 31, 1998. Unit holders
owning Units in nominee name may obtain monthly tax information from the Trustee
upon request.
We are pleased to announce that the new Web site for the Trust will be
accessible in mid-May 1998. Please visit the site at www.sjbrt.com to access our
news releases, reports, SEC filings and tax information.
Bank One, Texas, NA., Trustee
By: /s/ LEE ANN ANDERSON
Lee Ann Anderson
Vice President
2
<PAGE>
[PHOTO APPEARS HERE]
The
San Juan
Basin Royalty Trust
is a New York Stock
Exchange-listed entity, with
Units trading under the symbol "SJT."
<PAGE>
[PHOTO APPEARS HERE]
Cash
distributions
from the San Juan
Basin Royalty Trust are
declared and paid monthly to
holders of its Units of beneficial interest.
<PAGE>
DESCRIPTION OF THE PROPERTIES
The San Juan Basin properties from which the Trust's net overriding royalty
interest was carved are located in San Juan, Rio Arriba and Sandoval counties of
northwestern New Mexico (the "Underlying Properties"). The Underlying Properties
contain 151,900 gross (119,000 net) producing acres and 3,038 gross (909 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
Mesa Verde 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, 1997, the production index for the San Juan Basin properties is
estimated to be approximately 8 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.
During 1988, a drilling program was initiated involving development of
Fruitland Coal Seam gas reserves. Wells drilled in the Fruitland Coal Seam range
in depth from 2,500 to 3,500 feet, generally on 320-acre spacing. BROG has
informed the Trust that based on its success in 1997 it anticipates increasing
the density of its drilling operations in the Fruitland Coal, with wells drilled
on 160 and 80 -acre spacing.
The process of removing coal seam gas is often referred to as
degasification or desorption. Millions of years ago, natural gas was generated
in the process of coal formation and adsorbed into the coal. Water later filled
the natural fracture system. When the water is removed from the natural fracture
system, reservoir pressure is lowered and the gas desorbs from the coal. The
desorbed gas then flows through the fracture system and is produced at the well
bore. The volume of formation water production typically declines with time and
the gas production may increase for a period of time before starting to decline.
In order to dispose of the formation water, surface facilities including pumping
units are required, which results in the cost of a completed well being as much
as $500,000. During 1997, these coal seam wells produced a total of
approximately 9,570,183 MMBtu of gas from the Underlying Properties, which was
sold at an average price of $2.03 per MMBtu.
Production from coal seam wells drilled prior to January 1, 1993, qualifies
for Federal income tax credits through 2002. For 1997 the credit was
approximately $1.05 per MMBtu. During 1997, potential Section 29 tax credits of
approximately $.215593 per Unit were generated for Trust Unit holders from
production from coal seam wells.
During 1997, BROG incurred approximately $7.2 million of capital
expenditures for the drilling and completion of 64 gross (3.53 net) conventional
wells, recompletion of 14 gross (5.4 net) conventional wells, drilling and
completion of 1 gross (.84 net) coal seam well, and 21 gross (2.32 net) coal
seam recavitations. There were 5 gross (1.22 net) new conventional wells, 3
gross (1.08 net) conventional recompletions, 11 gross (.42 net) coal seam
recompletion, 5 gross (.20 net) coal seam recavitations, and 1 gross (.04 net)
coal seam well in progress as of December 31, 1997. During 1996, BROG
participated in the completion of 13 gross (1.96 net) conventional wells,
drilling and recompletion of 8 gross (4.80 net) conventional wells as coal seam
wells, recompleting 44 gross (12.96 net) conventional wells and other
maintenance activities and facilities costs at a total cost of $9,409,000.
Due to size of the coal seam drilling program in the San Juan Basin in the
late 1980s by various operators, there was more gas deliverability than
available pipeline capacity. As a result, several natural gas transportation
companies commenced pipeline expansion projects which almost doubled the
available transportation capacity out of the San Juan Basin. These projects were
completed during 1992 and production increased to 26.6 Bcf for 1992 and to 40.7
Bcf for 1994. BROG has advised the Trustee that current mainline capacity out of
the San Juan Basin is estimated at 3 Bcf per day for El Paso Natural Gas
Pipeline and 1.5 Bcf per day for Transwestern Pipeline Company and that
pipelines from the San Juan Basin are now capable of transporting approximately
1.2 Bcf per day to markets east of the San Juan Basin.
5
<PAGE>
DESCRIPTION OF THE PROPERTIES
Based on available geological and pricing information, the Trust has been
advised that approximately 71 net conventional wells are projected to be drilled
on the Underlying Properties. Proved undeveloped reserves have been assigned to
these wells. BROG has advised the Trust that its 1998 capital projections for
Trust working interests are estimated to be $10 million. Fruitland Coal is
estimated to be approximately 15% of the total and the remainder would be
conventional projects. Of the 300 planned projects, 47 will be conventional new
drill locations at a cost of approximately $3.2 million. There are 47 planned
Fruitland Coal recavitations at an estimated cost of $500,000, 39 of which will
be in the 39-6 Federal Unit. BROG anticipates adding compressors to 56 Fruitland
Coal wells at a cost of approximately $700,000. There are approximately 100
miscellaneous conventional projects planned, mostly projects aimed at improving
production from existing wells, at a cost estimated to be $5 million. BROG
anticipates that non-operated projects would be at a cost of approximately
$600,000. Development plans are dependent upon numerous factors, including, but
not limited to, drilling results of gas wells, anticipated demand for gas, the
sales price of gas, cost to drill the wells and other factors that BROG may deem
appropriate.
The Federal Energy Regulatory Commission is primarily responsible for
federal regulation of natural gas. For a further discussion of gas pricing, gas
purchasers, gas production and regulatory matters affecting gas production see
Item 2, "Properties" in the accompanying Form 10-K.
[PHOTO APPEARS HERE]
6
<PAGE>
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, 1997,
distributable income increased to $48,648,930 from $37,803,167 distributed in
1996. The increase was primarily attributable to significantly higher gas
prices. Interest income increased from $76,346 in 1996 to $99,403 in 1997
primarily due to increased funds available for investment.
Total gas and oil production from the Underlying Properties for the five
years ended December 31, 1997, were as follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Gas - Mcf_________________ 41,948,567 40,738,422 34,387,190 34,222,189 40,736,391
Mcf per day_______________ 114,928 111,307 94,211 93,759 111,607
Oil - Bbls________________ 89,492 83,552 75,014 84,648 88,466
Bbls per day______________ 245 228 206 232 242
- -------------------------------------------------------------------------------------------------------------------
</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 volumes from the Underlying Properties may
not provide a meaningful comparison to volumes attributable to the Royalty.
Royalty Income for the calendar year is associated with actual gas and oil
production during the period from November of the preceding year through October
of the current year. Gas and oil sales attributable to the royalty for the past
five years, (excluding portions attributable to the litigation settlement
proceeds described in Note 5 to accompanying Financial Statements), are
summarized in the following table:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
1997 1996 1995 1994 1993
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Gas - Mcf_________________ 24,236,419 17,927,785 13,331,758 15,459,542 23,895,506
Average Price (per Mcf)___ $2.21 $1.30 $1.25 $1.66 $1.70
Oil - Bbls________________ 50,860 36,792 29,424 36,769 51,921
Average Price (per Bbl)___ $19.35 $19.64 $14.43 $13.09 $15.58
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
The fluctuations in annual gas production that have occurred during these
five years generally resulted from changes in the demand for gas during that
time, marketing conditions and production from new wells. Production from the
Underlying Properties is influenced by the line pressures of the gas gathering
systems in the San Juan Basin. Expansion during 1992 of the gas transmission
systems that transport gas out of the San Juan Basin resulted in increased
production beginning in 1992. Higher volumes in 1993 can be partially attributed
to gas balancing in the San Juan 30-6 Federal Unit which occurred in the 3rd and
4th quarters of 1993. Production from the 30-6 Unit was more normalized
beginning in 1994. Production increased from 1995 to 1996 primarily due to
increased coal seam volumes.
7
<PAGE>
TRUSTEE'S DISCUSSION AND ANALYSIS
Royalty Income for the five years ended December 31, 1997, was determined as
shown in the following table:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------
1997 1996 1995 1994 1993
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
GROSS PROCEEDS FROM
THE UNDERLYING PROPERTIES:
- --------------------------
Gas_______________________________ $91,495,060 $51,865,730 $41,483,305 $54,375,586 $69,266,623
Oil_______________________________ 1,728,296 1,638,753 1,084,262 1,140,738 1,384,468
Other_____________________________ -0- -0- -0- -0- -0-
----------- ----------- ----------- ----------- -----------
Total___________________________ 93,223,356 53,504,483 42,570,159 55,498,324 70,651,091
=========== =========== =========== =========== ===========
LESS PRODUCTION COSTS:
- ---------------------
Capital Costs ____________________ 7,231,696 7,223,281 6,560,277 9,409,462 3,988,136
Severance Tax - Gas_______________ 8,989,202 5,654,831 4,694,750 5,864,834 6,543,615
Severance Tax - Oil ______________ 167,844 176,379 115,474 117,028 153,072
Other_____________________________ 61,832 59,089 117 -0- -0-
Leasing Operating Expenses________ 10,776,145 11,838,345 10,991,152 9,066,750 9,864,773
----------- ----------- ----------- ----------- -----------
Total___________________________ 27,226,719 24,951,925 22,361,770 24,458,074 20,549,596
----------- ----------- ----------- ----------- -----------
Net Profits_______________________ 65,996,637 28,552,558 20,208,389 31,040,250 50,101,495
Royalty Percentage_______________ 75% 75% 75% 75% 75%
Royalty Income____________________ $49,497,479 $21,414,419 $15,156,292 $23,280,188 $37,576,121
=========== =========== =========== =========== ===========
- -----------------------------------------------------------------------------------------------------------------
</TABLE>
The higher capital costs in 1994 were primarily attributable to
recompletions into the coal seam as part of a program which was initiated in
1988. The capital costs incurred by BROG on the Underlying Properties for the
year ended December 31, 1997, amounted to $7,231,696 versus $7,223,281 for 1996.
The increase 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 include the impact of the receipt of $250,000 from BROG as an offset to
lease operating expense in connection with the settlement of that litigation.
Excluding the impact of the offset, monthly operating costs in 1997 averaged
approximately $899,000, which is lower than the $955,000 average in 1996.
8
<PAGE>
Distributable income for three months ended December 31, 1997, totaled
$12,211,435 ($.261999 per Unit) as compared to $8,143,076 ($.174711 per Unit)
for the quarter ended December 31, 1996. The amount distributed in the fourth
quarter of 1997 was higher than that of 1996 primarily because of the higher
average gas prices.
Royalty Income of the Trust for the fourth quarter is associated with
actual gas and oil production during August through October of each year. Gas
and oil sales for the quarters ended December 31, 1997 and 1996 were as follows:
- --------------------------------------------------------------------------------
UNDERLYING PROPERTIES 1997 1996
- -------------------- ---------- ----------
Gas - Mcf___________________________ 10,441,818 10,535,177
Average Price (per Mcf)___________ $2.15 $1.64
Oil - Bbls__________________________ 19,438 19,460
Average Price (per Bbl)___________ $17.90 $21.06
ATTRIBUTABLE TO ROYALTY
- -----------------------
Gas - Mcf____________________________ 6,113,834 5,478,137
Oil - Bbls___________________________ 11,400 10,260
- --------------------------------------------------------------------------------
The average price of gas increased the fourth quarter of 1997 primarily due
to increases in spot prices. The average of oil decreased compared to the prior
year. Gas production decreased slightly primarily due to a decrease in coal seam
production. During the fourth quarter of 1997, coal seam production from the
Underlying Properties averaged 1,547,000 Mcf per month compared to 1,728,000 Mcf
per month during the fourth quarter of 1996.
Capital costs for the fourth quarter of 1997 totaled $1,579,932 compared to
$1,996,490 during the same period of 1996. The decrease was due to a decrease in
drilling activity in the fourth quarter of 1997. Operating costs in 1997
include the impact of the receipt of $250,000 from BROG as an offset to lease
operating expense in connection with the settlement of litigation. Excluding the
impact of the offset, lease operating costs for the fourth quarter of 1997
averaged $858,000 per month compared to $926,000 per month in the fourth quarter
of 1996.
9
<PAGE>
SAN JUAN BASIN ROYALTY TRUST
Statements of Assets, Liabilities and Trust Corpus
December 31, 1997 and 1996
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
ASSETS 1997 1996
- ------ ----------- -----------
<S> <C> <C>
Cash and Short-term investments______________________________ $ 5,111,832 $ 3,127,828
Net Overriding Royalty Interests in Producing Oil and
Gas Properties - Net (Notes 2 and 3)_____________________ 56,119,448 62,808,148
----------- -----------
$61,231,280 $65,935,976
=========== ===========
LIABILITIES AND TRUST CORPUS
- ----------------------------
Distribution Payable to Unit Holders_________________________ $ 5,111,832 $ 3,127,828
Contingencies (Note 5)
Trust Corpus - 46,608,796 Units of Beneficial interest
Authorized and Outstanding______________________________ 56,119,448 62,808,148
----------- -----------
$61,231,280 $65,935,976
=========== ===========
- ------------------------------------------------------------------------------------------------------------
</TABLE>
Statements of Distributable Income
for the Three Years Ended December 31, 1997
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
1997 1996 1995
------------ ----------- -----------
<S> <C> <C> <C>
Royalty Income (Notes 2, 3 and 5)____________________________ $ 49,497,479 $41,236,424 $15,156,292
Interest Income______________________________________________ 99,403 76,346 31,978
------------ ----------- -----------
49,596,882 41,312,770 15,188,270
Expenditures - General and Administrative____________________ 947,952 3,509,603 1,398,169
------------ ----------- -----------
Distributable Income_________________________________________ $ 48,648,930 $37,803,167 $13,790,101
============ =========== ===========
Distributable Income per Unit (46,608,796 Units)_____________ $ 1.043770 $ .811072 $ .295867
============ =========== ===========
- ------------------------------------------------------------------------------------------------------------
</TABLE>
Statements of Changes in Trust Corpus
for the Three Years Ended December 31, 1997
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
1997 1996 1995
------------ ----------- -----------
<S> <C> <C> <C>
Trust Corpus, Beginning of Period____________________________ $ 62,808,148 $70,133,536 $74,942,040
Amortization of Net Overriding Royalty Interest
(Notes 2 and 3)___________________________________________ (6,688,700) (7,325,388) (4,808,504)
Distributable Income_________________________________________ 48,648,930 37,803,167 13,790,101
Distributions Declared_______________________________________ (48,648,930) (37,803,167) (13,790,101)
============ =========== ===========
Trust Corpus, End of Period__________________________________ $ 56,119,448 $62,808,148 $70,133,536
============ =========== ===========
- ------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
10
<PAGE>
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 San Juan Basin in northwestern New Mexico.
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:
. 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;
. 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;
. the Trustee may establish a cash reserve for the payment of any liability
which is contingent or uncertain in amount;
. the Trustee is authorized to borrow funds to pay liabilities of the Trust;
and
. 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. To the extent the distribution amount is a negative number, the
amount will be carried forward and deducted from future monthly distributions
until the cumulative distribution calculation becomes a positive number, at
which time a distribution will be made. Unit holders of record will be entitled
to receive the calculated Monthly Distribution Amount for each month on or
before ten business days after the monthly record date, which is generally the
last business day of each calendar month.
The cash received by the Trustee consists of the amounts received by the
owner of the interest burdened by the Royalty from the sale of production less
the sum of applicable taxes, accrued production costs, development and drilling
costs, operating charges and other costs and deductions, multiplied by 75%.
Royalty income for 1996 was comprised of $21,414,419, which represents the net
overriding royalty interest in the net profits of the properties from which the
net overriding royalty was carved, and $19,822,005 paid to the Trust as a result
of the settlement of litigation involving the Trustee, Meridian Oil Inc. ("MOI")
and Southland. For more information regarding the settlement of the litigation,
see Note 5.
The initial carrying value of the Royalty ($133,275,528) represented
Southland's historical net book value at the date of the transfer to the Trust.
Accumulated amortization as of December 31, 1997 and 1996 aggregated $77,156,080
and $70,467,380, respectively.
3. BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on the following basis:
. Royalty income recorded for a month is the amount computed and paid by
the working interest owner, Southland, to the Trustee on behalf of the
Trust. Royalty income consists of the amounts received by the owner of the
interest burdened by the net overriding royalty interest from the sale of
production less accrued production costs, development and drilling costs,
applicable taxes, operating charges, and other costs and deductions,
multiplied by 75%.
. Trust expenses recorded are based on liabilities paid and cash reserves
established from Royalty income for liabilities and contingencies.
. Distributions to Unit holders are recorded when declared by the Trustee.
. The conveyance which transferred the overriding royalty 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 and certain cash reserves
11
<PAGE>
SAN JUAN BASIN ROYALTY TRUST
may be established for contingencies which would not be accrued in
financial statements prepared in accordance with GAAP. Amortization of the
Royalty calculated on a unit-of-production basis is charged directly to
trust corpus.
4. FEDERAL INCOME TAXES
For Federal income tax purposes, the Trust constitutes a fixed investment trust
which is taxed as a grantor trust. A grantor trust is not subject to tax at the
trust level. The Unit holders are considered to own the Trust's income and
principal as though no trust were in existence. The income of the Trust is
deemed to have been received or accrued by each Unit holder at the time such
income is received or accrued by the Trust rather than when distributed by the
Trust.
The Royalty constitutes an "economic interest" in oil and gas properties
for Federal income tax purposes. Unit holders must report their share of the
revenues of the Trust as ordinary income from oil and gas royalties, and are
entitled to claim depletion with respect to such income. The Royalty is treated
as a single property for depletion purposes.
The Trust has on file technical advice memoranda confirming the tax
treatment described above.
The Trust began receiving royalty income from coal seam wells beginning in
1989. Under Section 29 of the Internal Revenue Code, production from coal seam
gas wells drilled prior to January 1, 1993, qualifies for the Federal income tax
credit for producing non-conventional fuels. Production from coal seam wells
drilled prior to January 1, 1993, qualifies for Federal income tax credits
through 2002. Production from wells drilled after December 31, 1979, but prior
to January 1, 1993, to a formation beneath a qualifing coal seam formation which
are later completed into such formation, also qualifies for the tax credit. This
tax credit was approximately $1.05 per MMBtu for the year 1997 and is adjusted
for inflation annually. The credit currently applies to production through the
year 2002. 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 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.
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 certain of Southland's oil and gas
leasehold and royalty interests in the San Juan Basin located in San Juan, Rio
Arriba and Sandoval counties of northwestern New Mexico (the "Underlying
Properties"). MOI and Southland were the operators of the Underlying Properties.
On January 2, 1996, Southland was merged with and became a wholly owned
subsidiary of MOI. Subsequent to the merger, MOI changed its name to Burlington
Resources Oil & Gas Company ("BROG").
The claims asserted on behalf of the Trust in the lawsuit included breach
of contract, breach of the covenant of good faith and fair dealing, breach of
express good faith duty, constructive fraud, unjust enrichment, 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 Underlying 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
Underlying 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:
12
<PAGE>
[PHOTO APPEARS HERE]
The
Trust made
distributions total-
ing $1.04377 per Unit of
beneficial interest in 1997.
<PAGE>
SAN JUAN BASIN ROYALTY TRUST
[MAP OF SAN JUAN BASIN APPEARS HERE]
1. BROG's pre-existing contract with a third-party purchaser covering
baseload gas volumes in the firm amount of 45,000 MMBtu per day remained
effective for a period of one year from July 1, 1996.
The remaining volumes of gas from the Underlying Properties were marketed
by an independent marketer, El Paso Energy Marketing Company, a subsidiary of El
Paso Energy Corporation, beginning October 1, 1996. BROG agreed that subsequent
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 Trust oil and natural gas liquids 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. Additionally, El Paso could utilize BROG's
eastern transportation agreement for delivery from the San Juan Basin on El Paso
Natural Gas Company pipeline to pipelines in West Texas of up to 13,333 MMBtu
per day of gas produced from Underlying Properties for a period of one year
commencing October 1, 1996.
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
Southland entered into five-year gas, gas processing and gas gathering
agreements with Sunterra Gas Gathering Company (a subsidiary of Public Service
Company of New Mexico) ("Sunterra") and Gas Company of New Mexico (a division of
Public Service Company of New Mexico) ("Gas Company") that were effective as of
July 1,1990. The new contracts applied to all lands previously dedicated to
Sunterra and Gas Company for first sales of natural gas sold into interstate or
intrastate markets, except that the new gas purchase contracts excluded all gas
produced and sold from coal seam wells. The new gas purchase contracts provided
for purchases by Sunterra and Gas Company for winter heating season only. During
the remainder of the year, Southland could market the gas through any
arrangements it deemed advisable. Under the new gas purchase contracts,
Southland received prices, inclusive of severance taxes, ranging from
approximately $2.35 per MMBTu to $3.37 per MMBtu over the life of the contracts.
The contracts also provided for certain "take-or-pay obligations" if certain
minimum levels of natural gas sales are not reached.
In 1991, due to the low level of natural gas prices, Sunterra informed
Southland that it would not take any significant volume of gas during the 1991-
1992 winter heating season and would simply pay the "take-or-pay obligation"
amount. Consequently, the majority of the wells subject to the contracts would
have remained shut-in during the winter heating season. In an attempt to
maximize production and revenues from the Underlying Properties, Southland
informed the Trustee that it entered into an agreement with Sunterra and Gas
Company that amended the terms of the contracts discussed above for only the
1991-1992 winter heating season. The amendment provided that Sunterra and Gas
Company could purchase approximately 35% of the contract provided take levels at
a wellhead price slightly higher than the spot market well-head index price for
the San Juan Basin. Any gas purchased by Sunterra and Gas Company above this
level averaged $2.63 per MMBtu. Southland was free to market the remaining
deliverable gas to other purchasers. During 1992, Sunterra and Gas Company
purchased 3,241,550 Mcf and 702,629 Mcf, respectively, at average prices of
$1.98 and $2.25 per Mcf, respectively, from the Underlying Properties.
To continue to maximize production and revenues from Trust Properties,
Southland again informed the Trustee that it negotiated an agreement with
Sunrerra and Gas Company that amended the terms of the original contracts
discussed above for only the 1992-1993 winter heating season. The amendment
provided that Gas Company and Sunterra were required to purchase a minimum of
11,500 MMBtu per day at $2.695 per MMBtu under the intrastate and a minimum of
16,550 MMBtu per day at $2.94 per MMBtu under the interstate contracts. A
portion of the excess gas
14
<PAGE>
SAN JUAN BASIN ROYALTY TRUST
was released for spot sales, with a recall provision at an average contract
price.
Southland informed the Trust that a similar amendment was entered into for
the 1993-1994 winter heating season. Gas Company and Sunterra paid the contract
specified prices of $2.88 and $3.15 per MMBtu, respectively, on a minimum
purchase of 1.4 Bcf and 1.2 Bcf, respectively. All remaining gas was released
for spot sales with a recall provision at an average contract price. Southland
waived any claims for deficiency payment under the reservation fee.
Southland informed the Trust an amendment had also been entered into for
the 1994-1995 winter heating season. Gas Company and Sunterra were required to
purchase, at the wellhead, an average volume of 10,529 MMBtu per day at $2.884
per MMBtu for the period beginning November 1,1994, and ending March 31, 1995,
and an additional 14,900 MMBtu per day at $3.146 per MMBtu for the period
beginning December 1, 1994, and ending February 28, 1995. Gas Company and
Sunterra were granted a make-up period of four months beginning April 1, 1995,
to fulfill this purchase obligation.
Gas Company and Sunterra were also granted recall rights on volumes up to
15,000 MMBtu per day at the tailgate of the Kutz and Lybrook plants, provided
they nominated the full contract volume specified above. The price for recall
gas was the average of the first and second issues of the Inside FERC EPNG SJ
Index.
The Trust was advised that effective July 1, 1995, Williams Field Services
("Williams") purchased the Kutz and Lybrook processing plants and the gathering
systems behind these plants which were owned by Sunterra, Gas Company and
Sunterra Gas Processing Company ("SGPC") and that new gathering and processing
agreements with Williams were entered into which contain acceptable rates, terms
and conditions. The new agreements replaced the then current gathering and
processing agreements with Gas Company, Sunterra and SGPC effective on the
closing date of the sale of these facilities to Williams.
The gas purchase contracts described in Note 5 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 Energy Marketing Company ("El Paso"). That
contract is for a term of two years through and including December 31, 1999 and
provides for the sale of Trust gas at prices which will fluctuate in accordance
with published indices for gas sold in the San Juan Basin of New Mexico. BROG
entered into the contract with El Paso after soliciting and receiving
competitive bids in late 1997 from six major gas marketing firms to market
and/or purchase the Trust gas. While it is impossible to predict the exact
economic value of gas contracts, the Trust has been advised by its independent
gas marketing consultant that the contract with El Paso should provide for the
average highest sales price for natural gas in the San Juan Basin over the two-
year term of the contract.
Confidentiality agreements with purchasers of gas produced from the
Underlying Properties prohibit public disclosure of certain terms and conditions
of gas sales contracts with those entities, including specific pricing terms,
gas receipt points, etc. Such disclosure could compromise the ability to compete
effectively in the marketplace for the sale of gas produced from the Underlying
Properties.
7. SIGNIFICANT CUSTOMERS
Information as to significant purchasers of oil and gas production attributable
to the Trust's economic interests is included in Item 2 of the Trust's annual
report on Form 10-K which is included in this report.
8. PROVED OIL AND GAS RESERVES (UNAUDITED)
Proved oil and gas reserve information is included in Item 2 of the Trust's
annual report on Form 10-K which is included in this report.
9. QUARTERLY SCHEDULE OF DISTRIBUTABLE INCOME (UNAUDITED)
The following is a summary of the unaudited quarterly schedule of distributable
income for the two years ended December 31, 1997 (in thousands, except unit
amounts):
=============================================================
Distributable
Income and
Royalty Distributable Distribution
1997 Income Income Per Unit
- ---- ------- ------------- -------------
First Quarter_________ $18,471 $18,267 $ .391930
Second Quarter________ 8,900 8,565 .183766
Third Quarter_________ 9,764 9,605 .206076
Fourth Quarter________ 12,363 12,212 .261998
------ ------ ---------
Total_______________ $49,498 $48,649 $1.043770
======= ======= =========
1996
- ----
First Quarter_________ $ 4,708 $ 3,926 $ .084239
Second Quarter________ 4,408 2,943 .063143
Third Quarter_________ 24,135 22,791 .488979
Fourth Quarter________ 8,345 8,143 .174711
------- ------- ---------
Total_______________ $41,236 $37,803 $ .811072
======= ======= =========
=============================================================
15
<PAGE>
INDEPENDENT AUDITORS' REPORT
Bank One, Texas, N.A. as Trustee for the San Juan Basin Royalty Trust:
We have audited the accompanying statements of assets, liabilities and trust
corpus of the San Juan Basin Royalty Trust ("Trust") as of December 31, 1997 and
1996, and the related statements of distributable income and changes in trust
corpus for each of the three years in the period ended December 31, 1997. 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, 1997 and 1996, and the distributable income and changes
in trust corpus for each of the three years in the period ended December 31,
1997, on the basis of accounting described in Note 3.
/s/ DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Fort Worth, Texas
March 25, 1998
- --------------------------------------------------------------------------------
SAN JUAN BASIN ROYALTY TRUST TAX COUNSEL
Bank One, Texas, NA., Trustee Butler & Binion, L.L.P.
Post Office Box 2604 Houston, Texas
Fort Worth, Texas 76113
817-884-4630
Web site: www.sjbrt.com TRANSFER AGENT
Harris Trust & Savings Bank
AUDITORS 311 West Monroe Street, 11th Floor
Chicago, Illinois 60606
Deloitte & Touche LLP
Fort Worth, Texas For questions about distribution checks,
address changes, and transfer
procedures, call 800-573-4048 or
LEGAL COUNSEL 312-461-6001.
Vinson & Elkins L.L.P
Dallas, Texas
16
<PAGE>
EXHIBIT 23
MARCH 27, 1998
San Juan Basin Royalty Trust
Bank One, Texas, N.A.
7th Floor, Suite 704
Fort Worth, Texas 76102
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, 1997 and in the
San Juan Basin Royalty Trust Annual Report for the year ended December 31,
1997 based on reserve reports dated March 25, 1998 prepared by Cawley,
Gillespie & Associates, Inc.
Sincerely,
/s/ CAWLEY, GILLESPIE & ASSOCIATES, INC.
Cawley, Gillespie & Associates, Inc.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
UNAUDITED CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS OR SAN
JUAN BASIN ROYALTY TRUST AS OF DECEMBER 31, 1997, AND THE RELATED CONDENSED
STATEMENTS OF DISTRIBUTABLE INCOME AND CHANGES IN TRUST CORPUS FOR THE
TWELVE-MONTH PERIOD ENDED DECEMBER 31, 1997.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 5,111,832
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 5,111,832
<PP&E> 133,275,528
<DEPRECIATION> 77,156,080
<TOTAL-ASSETS> 61,231,280
<CURRENT-LIABILITIES> 5,111,832
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 56,119,448
<TOTAL-LIABILITY-AND-EQUITY> 61,231,280
<SALES> 0
<TOTAL-REVENUES> 49,596,882
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 947,952
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 48,648,930
<INCOME-TAX> 0
<INCOME-CONTINUING> 48,648,930
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 48,648,930
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
