<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
(Fee Required)
For the fiscal year ended December 31, 1996, or
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(No Fee Required)
For the transition period from to Commission file number 1-8032
SAN JUAN BASIN ROYALTY TRUST
(Exact name of registrant as specified in the San Juan Basin Royalty Trust
Indenture)
TEXAS 75-6279898
(State or other jurisdiction of (I.R.S. Employer)
incorporation or Organization) Identification Number)
76113
BANK ONE, TEXAS, NA (Zip Code)
TRUST DEPARTMENT
P.O. BOX 2604
FORT WORTH, TEXAS
(Address of principal executive offices)
(817) 884-4630
(Registrant's Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH
UNITS OF BENEFICIAL INTEREST REGISTERED
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, 1997, there were 46,608,796 Units of Beneficial Interest of the
Trust outstanding with an aggregate market value on that date of $367,044,269.
DOCUMENTS INCORPORATED BY REFERENCE
"Units of Beneficial Interest" at page 2; "Description of the Properties" at
page 4; "Trustee's Discussion and Analysis" at pages 6 and 7; "Results of the
4th Quarters of 1996 and 1995" 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, 1996 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, NA. The principal office of the
Trust (sometimes referred to herein as the "Registrant") is located at 500
Throckmorton Street, Suite 704, Fort Worth, Texas 76102 (telephone number
817/844-4630).
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 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.
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.
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, subject to certain adjustments. "Production
costs" means, generally, costs incurred on an accrual basis by BROG in
operating its properties and interests out of which the Royalty was carved,
including both capital and non-capital costs. For example, these costs include
development drilling, production and processing costs, applicable taxes, and
operating charges. If production costs exceed gross proceeds in any month, the
excess is recovered out of future gross proceeds prior to the making of
further payment to the Trust, but the Trust is not otherwise liable for any
production costs or other costs or liabilities attributable to these
properties and interests or the minerals produced therefrom. If at any time
the Trust receives more than the amount due under the Royalty, it shall not be
obligated to return such overpayment, 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.
1
<PAGE>
Certain of the properties and interests out of which the Royalty was carved
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 and
interests, either under existing sales contracts or under future arrangements
at the best prices and on the best terms it shall deem reasonable 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 properties from which the Royalty
was carved.
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 properties from which the Royalty was carved are primarily gas producing
properties. Normally there is a greater demand for gas in the winter months
than during the rest of the year. Otherwise, the income to the Trust
attributable to the Royalty is not subject to seasonal factors nor in any
manner related to or dependent upon patents, licenses, franchises or
concessions. The Trust conducts no research activities.
ITEM 2. PROPERTIES
The 75% net overriding royalty conveyed to the Trust was carved out of
Southland Royalty's working interest and royalty interests in the San Juan
Basin in northwestern New Mexico. References below to "net" wells and acres
are to the interests of BROG (from which the Royalty was carved) in the
"gross" wells and acres.
Unless otherwise indicated, the following information in Item 2 is based
upon data and information furnished the Trustee by BROG.
PRODUCING ACREAGE, WELLS AND DRILLING
BROG's working interests and royalty interests in the San Juan Basin consist
of 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 3,180 gross (960
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, 1996, is
herein incorporated by reference.
2
<PAGE>
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 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. During 1995, there were 24 gross (6.36
net) wells completed including 5 gross (2.54 net) coal seam wells. There were
4 gross (1.89 net) coal seam wells and 7 gross (2.24 net) conventional wells
in progress at December 31, 1995. There were 24 gross (11.41 net) coal seam
wells and 38 gross (8.61 net) conventional wells recompleted through December
31, 1995. During 1994, there were 21 gross (6.76 net) wells completed
including 8 gross (4.80 net) coal seam wells. There were 4 gross (2.55 net)
coal seam wells and 23 gross (7.69 net) conventional wells in progress at
December 31, 1994. There were 17 gross (10.57 net) coal seam wells and 44
gross (12.96 net) conventional wells recompleted through December 31, 1994.
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, 1996
were as follows:
<TABLE>
<CAPTION>
1996 1995 1994
----------------- ------------------ ------------------
OIL GAS OIL GAS OIL GAS
(BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF)
------ ---------- ------ ---------- ------ ----------
<S> <C> <C> <C> <C> <C> <C>
Production................ 36,792 17,927,785 29,424 13,331,758 36,769 15,459,542
Average Price............. $19.64 $1.30 $14.43 $1.25 $13.09 $1.66
</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 40,738,422 Mcf during
1996.
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.
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
3
<PAGE>
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 shall receive 75% (the amount of its
net overriding royalty interest) of any value that ultimately inures 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, 1996 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.
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
4
<PAGE>
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.
Southland Royalty also informed the Trust 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 have been 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 Trust has further been informed by Southland Royalty that MOTI
negotiated an agreement with Gas Company providing for transportation service
on Gas Company's Albuquerque mainline. This agreement was effective on the
closing date of the sale of Gas Company's gathering and processing facilities
to Williams. This transportation agreement facilitates delivery of volumes of
gas behind the Lybrook processing plant to mainline delivery points.
Southland Royalty further informed the Trust that on September 13, 1994,
MOTI entered into a gas sales agreement with Gas Company for the five winter
periods beginning November 1, 1995 and ending March 31,
5
<PAGE>
2000. MOTI purchased the gas supplied for this sale from MOI producing
affiliates and third party sellers. Sales were based on a monthly published
index. BROG has informed the Trust that as a result of the Litigation (as
hereinafter defined), no gas produced from the properties from which the
Royalty was carved will be applied in performance of such agreement with Gas
Company. It is the understanding of the Trustee that Gas Company is now known
as PNM Gas Services.
On September 4, 1996, the Trustee announced the settlement of the litigation
(the "Litigation") filed by the Trustee against BROG and Southland Royalty
Company. The Litigation, which was filed in the state district court of Santa
Fe County, New Mexico, Cause No. SF 94-1982(c), was dismissed on September 12,
1996.
Agreement was reached, among other things, regarding marketing arrangements
for the sale of Trust gas, oil and natural gas liquids products going forward
as follows:
(i) BROG's pre-existing contract with a third-party purchaser will
continue as pertains to baseload gas volumes in the firm amount of 45,000
MMBtus/day for a period of one year from July 1, 1996. Negotiations for the
sale of these volumes after June 30, 1997, will be entered into prior to
the expiration of the primary term of the contract;
(ii) The remaining volumes of Trust gas will be marketed by an
independent marketer, El Paso Energy Marketing Company ("El Paso"), a
subsidiary of El Paso Energy Corporation, beginning October 1, 1996, under
an arrangement which provides for a sharing of amounts, if any, earned in
excess of established gas price thresholds. El Paso's compensation for its
marketing services consists solely of its proportionate part of any amounts
for which the gas is sold in excess of the thresholds. BROG's contract with
El Paso is for a two-year term beginning October 1, 1996, subject to
renewal by agreement of the parties;
(iii)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
(iv) 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 may 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.
See Note 5 of Notes to Financial Statements of the Trust's Annual Report to
securityholders for the year ended December 31, 1996 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
6
<PAGE>
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."
"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, 1994, 1995 and 1996 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1993
to December 31, 1996 (in thousands);
<TABLE>
<CAPTION>
NATURAL
OIL GAS
(BBLS) (MCF)
------ -------
<S> <C> <C>
Reserves as of December 31, 1993......................... 712 248,101
Revisions of previous estimates.......................... (63) (31,236)
Extensions, discoveries and other additions.............. -0- -0-
Production............................................... (37) (15,460)
---- -------
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
==== =======
</TABLE>
Estimated quantities of proved developed reserves of crude oil and natural
gas as of December 31, 1996, 1995 and 1994 were as follows (in thousands):
<TABLE>
<CAPTION>
CRUDE NATURAL
OIL GAS
(BBLS) (MCF)
------ -------
<S> <C> <C>
1996....................................................... 637 239,962
1995....................................................... 418 159,650
1994....................................................... 612 186,915
</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.
7
<PAGE>
Estimates of proved oil and gas reserves are by their nature imprecise.
Estimates of future net revenue attributable to proved reserves are sensitive
to the unpredictable prices of oil and gas and other variables. Accordingly,
under the allocation method used to derive the Trust's quantity of proved
reserves, changes in prices will result in changes in quantities of proved oil
and gas reserves and estimated future net revenues.
The 1996, 1995 and 1994 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>
1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Balance, January 1......................... $106,937 $157,627 $274,215
Revisions of prior-year estimates, change
in prices and other....................... 338,208 (51,819) (120,730)
Extensions, discoveries and other
additions................................. 4,612 522 -0-
Accretion of discount...................... 10,694 15,763 27,422
Royalty income............................. (21,414) (15,156) (23,280)
-------- -------- --------
Balance, December 31....................... $439,037 $106,937 $157,627
======== ======== ========
</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 $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 downward revision is primarily due to
lower gas prices in 1995.
An average price of $1.56 per Mcf and $13.78 per barrel were used at
December 31, 1994, in determining estimated future net revenues. The downward
revision was primarily due to lower gas prices in 1994.
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, 1996, 1995 and 1994 (in thousands except amounts per
Unit):
<TABLE>
<CAPTION>
1996 1995 1994
------------------ ------------------ ------------------
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.......... $822,131 $439,037 $184,055 $106,937 $287,401 $157,627
Proved Developed...... $799,664 $430,365 $175,824 $104,378 $265,477 $149,241
Total Proved Per Unit. $ 17.64 $ 9.42 $ 3.95 $ 2.29 $ 6.17 $ 3.38
</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,
8
<PAGE>
the present values shown above should not be considered as the market values
of such oil and gas reserves or the costs that would be incurred to acquire
equivalent reserves. A market value determination would include many
additional factors.
REGULATION
Many aspects of the production, pricing and marketing of crude oil and
natural gas are regulated by federal and state agencies. Legislation affecting
the oil and gas industry is under constant review for amendment or expansion,
frequently increasing the regulatory burden on affected members of the
industry.
Exploration and production operations are subject to various types of
regulation at the federal, state and local levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements
in order to drill or operate wells, and regulating the location of wells, the
method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled and the plugging and abandonment of
wells. Natural gas and oil operations are also subject to various conservation
laws and regulations that regulate the size of drilling and spacing units or
proration units and the density of wells which may be drilled and unitization
or pooling of oil and gas properties. In addition, state conservation laws
establish maximum allowable production from natural gas and oil wells,
generally prohibit the venting or flaring 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 ("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.
Commencing in 1992, FERC issued Orders Nos. 636, 636-A, 636-B and 636-C
(collectively, "Order No. 636"), which generally opened access to interstate
gas pipelines by requiring such pipelines to "unbundle" their transportation
services and allow shippers to choose and pay for only the services they
require, regardless of whether the shipper purchases gas from such pipelines
or from other suppliers. These orders also require upstream pipelines to
permit downstream pipelines to assign upstream capacity to their shippers and
place analogous, unbundled access requirements on the downstream pipelines.
Through individual pipeline restructuring proceedings, Order No. 636 has been
implemented on all U.S. interstate pipelines. There are currently a number of
judicial challenges to these individual proceedings, which are now pending
before the U.S. Court of Appeals for the District of Columbia Circuit (the
"D.C. Circuit"). In July 1996, the D.C. Circuit largely upheld the terms of
the Order No. 636 rulemaking. Certain aspects of the D.C. Circuit's ruling
have been appealed to the U.S. Supreme Court.
Although Order No. 636 does not regulate the Trust, FERC has stated that
Order No. 636 is intended to foster increased competition within all phases of
the natural gas industry. In many instances, the result of Order No. 636 and
related initiatives have been to substantially reduce or eliminate the
interstate pipelines' traditional role as wholesalers of natural gas in favor
of providing only storage and transportation services. It is unclear what
impact, if any, increased competition within the natural gas industry under
Order No. 636 will have on the Trust.
The FERC has recently announced its intention to reexamine certain of its
transportation-related policies, including the appropriate manner for setting
rates for new interstate pipeline construction, the manner in which
9
<PAGE>
interstate pipeline shippers may release interstate pipeline capacity under
Order No. 636 for resale in the secondary market, and the use of market-based
rates for interstate gas transmission. While any resulting FERC action would
affect the Trust only indirectly, FERC's stated intention is to further
enhance competition in natural gas markets.
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.
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 a
qualifying coal seam formation which are later completed into such formation
also qualifies for the tax credit. This tax credit for 1996 was approximately
$1.03 per MMBtu and 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 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 taxypayer'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 Trust 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
Trust 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.
10
<PAGE>
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 unit
holders 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, Notes 5 and 6 of
the Notes to Financial Statements at pages 13 through 15 of the Trust's Annual
Report to security holders for the year ended December 31, 1996 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, 1996.
11
<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 2 of the
Trust's Annual Report to security holders for the year ended December 31,
1996, is herein incorporated by reference.
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
1996 1995 1994 1993 1992
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Royalty income(1)....... $41,236,424 $15,156,292 $23,280,188 $37,576,121 $32,494,453
Distributable income.... 37,803,167 13,790,101 22,632,493 36,760,797 31,705,994
Distributable income per
Unit................... 0.811072 0.295867 0.485584 0.788710 0.680257
Distributions per Unit.. 0.811072 0.295867 0.485584 0.788710 0.680257
Total assets, December
31..................... 65,935,976 70,554,982 75,531,405 82,701,203 90,372,116
</TABLE>
- --------
(1) The royalty income distributions for 1992 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
1996 and 1995" at pages 6, 7, and 9 of the Trust's Annual Report to security
holders for the year ended December 31,1996, are herein incorporated by
reference.
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, 1996, are herein incorporated by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
12
<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 Unit
holders, by the affirmative vote of the holders of a majority of all the Units
then outstanding.
ITEM 11. EXECUTIVE COMPENSATION
During the year ended December 31, 1996, the Trustee received total
remuneration as follows:
<TABLE>
<CAPTION>
NAME OF INDIVIDUAL OR NUMBER OF
PERSONS IN GROUP CAPACITIES IN WHICH SERVED CASH COMPENSATION
------------------------------- -------------------------- -----------------
<S> <C> <C>
Bank One, Texas, N.A...... Trustee $189,219(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, 1996, 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
NAME AND ADDRESS OF BENEFICIAL OWNERSHIP PERCENT OF CLASS
---------------- ----------------------- ----------------
<S> <C> <C>
Fund American Enterprises Holdings,
Inc. (1)............................. 10,994,876 Units 23.6%
The 1820 House, Main Street
Norwich, Vermont 05055
Capital Guardian Trust Company (2).... 4,004,800 Units 8.6%
333 South Hope Street, 52nd Floor
Los Angeles, California 90071
</TABLE>
- --------
(1) This information was provided to the Securities and Exchange Commission
and to the Trust in a Form 4 dated July 9, 1996, filed with the Securities
and Exchange Commission by Fund American Enterprises Holdings, Inc.
("FAEH") which indicated that these Units were owned by FAEH.
According to such Form 4, FAEH owns 157,215 Units directly and 10,837,661
Units indirectly as follows: 10,759,876 Units indirectly through its
wholly-owned subsidiary Fund American Enterprises, Inc. ("FAE") and 77,785
Units indirectly through its wholly-owned subsidiary White Mountain
Holdings, Inc. and certain of its wholly-owned subsidiaries.
The Form 4 filed by FAEH with the Securities and Exchange Commission may be
reviewed for more detailed information concerning the matters summarized
herein.
(2) This information was provided to the Securities and Exchange Commission
and to the Trust in Amendment 3 to Schedule 13G dated February 12, 1997,
filed jointly with the Securities and Exchange Commission by The Capital
Group Companies, Inc. ("Capital Group") and Capital Guardian Trust Company
("Capital Guardian"). Capital Guardian is a bank wholly-owned operating
subsidiary of Capital Group. Capital Guardian exercised investment
discretion with respect to the 4,004,800 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
3,249,800 Units and sole dispositive power over 4,004,800 Units.
The Amendment 3 to Schedule 13G filed by Capital Group and Capital Guardian
with the Securities and Exchange Commission may be reviewed for more
detailed information concerning the matters summarized herein.
13
<PAGE>
(b) Security Ownership of Management. The Trustee owns beneficially no
securities of the Trust. In various fiduciary capacities, Bank One, Texas, NA
owned, as of December 31, 1996, an aggregate of 23,672 Units with the sole
right to vote 7,520 of these Units and shared right to vote 16,152 of these
Units. Such Bank 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, NA.
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, 1996
and Item 12(b) for information concerning Units owned by Bank One, Texas, NA
in various fiduciary capacities.
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, 1996:
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.
EXHIBITS
<TABLE>
<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, NA), as Trustee, heretofore filed as Exhibit
4(a) to the Trust's Annual Report on Form 10-K to the Securities and
Exchange Commission for the fiscal year ended December 31, 1980, is
incorporated herein by reference.*
(b) --Net Overriding Royalty Conveyance from Southland Royalty Company to
The Forth Worth National Bank (now Bank One, Texas, NA), as Trustee,
dated November 3, 1980 (without Schedules), heretofore filed as
Exhibit 4(b) to the Trust's Annual Report on Form 10-K to the
Securities and Exchange Commission for the fiscal year ended December
31, 1980, is incorporated herein by reference.*
(13) --Registrant's Annual Report to security holders for fiscal year ended
December 31, 1996.**
(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, NA,
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, 1996, no
reports on Form 8-K were filed with the Securities and Exchange Commission by
the Trust.
14
<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, NA
TRUSTEE OF THE SAN JUAN BASIN
ROYALTY TRUST
/s/ Lee Ann Anderson
By: _________________________________
(Lee Ann Anderson)
Vice President
Date: March 31, 1997
(The Trust has no directors or executive officers)
15
<PAGE>
EXHIBIT 13
SAN JUAN BASIN ROYALTY TRUST
1996 ANNUAL REPORT & FORM 10-K
------------------
<PAGE>
The powerful energy of natural gas took a very long time to get to the surface
of the beautiful San Juan Basin of New Mexico. Accompanying the text in this
report is an artist's view of that eons-old process.
<PAGE>
THE TRUST
The principal asset of the San Juan Basin Royalty Trust (the "Trust") consists
of a 75% net overriding royalty interest carved out of certain of Southland
Royalty Company's ("Southland Royalty") oil and gas leasehold and royalty
interests in the San Juan Basin of northwestern New Mexico.
UNITS OF BENEFICIAL INTEREST
The Units of Beneficial Interest of the Trust ("Units") are traded on the New
York Stock Exchange under the symbol "SJT." From January 1, 1995, to December
31, 1996, quarterly high and low sales prices and the aggregate amount of
monthly distributions per Unit paid each quarter were as follows:
<TABLE>
<CAPTION>
1996 HIGH LOW DISTRIBUTION
- -----------------------------------------------
<S> <C> <C> <C>
First Quarter $6.875 $5.875 $.084239
Second Quarter 6.500 5.625 .063143
Third Quarter 7.500 6.000 .488979
Fourth Quarter 8.625 6.125 .174711
--------
Total for 1996 $.811072
========
1995 HIGH LOW DISTRIBUTION
- -----------------------------------------------
First Quarter $7.375 $5.875 $.090595
Second Quarter 7.250 5.625 .108430
Third Quarter 7.000 5.875 .071482
Fourth Quarter 6.875 5.750 .025360
--------
Total for 1995 $.295867
========
</TABLE>
At December 31, 1996, 46,608,796 Units outstanding were held by 2,580 Unit
holders of record. The following table presents information relating to the
distribution of ownership Units:
<TABLE>
<CAPTION>
TYPE OF NUMBER OF
UNIT HOLDERS UNIT HOLDERS UNITS HELD
- ---------------------------------------------------------
<S> <C> <C>
Individuals 2,031 3,475,705
Fiduciaries 477 882,299
Institutions 55 942,934
Brokers, Dealers and Nominees 8 39,653,276
Corporations and Partnerships 7 1,614,512
Miscellaneous 2 40,070
----- ----------
Total 2,580 46,608,796
===== ==========
</TABLE>
2
<PAGE>
TO UNIT HOLDERS
We are pleased to present the 1996 Annual Report of the San Juan Basin
Royalty Trust. The report includes a copy of the Trust's Annual Report on Form
10-K filed with the Securities and Exchange Commission for the year ended
December 31, 1996, without exhibits. The Form 10-K contains important
information concerning the Trust's properties, including the oil and gas
reserves attributable to the net overriding royalty interest owned by the Trust.
Production figures provided in this letter and in the Trustee's Discussion and
Analysis are based on information provided by Burlington Resources Oil & Gas
Company ("BROG").
The Trust was established in November 1980 by Trust Indenture between
Southland Royalty and Texas American Bank/Fort Worth, N.A. 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.
Under the Trust Indenture, Bank One, Texas, NA (successor trustee) as
Trustee, has the primary function of collecting monthly net proceeds ("Royalty
Income") attributable to the Royalty and making the monthly distributions to
the Unit holders after deducting administrative expenses and any amounts
necessary for cash reserves.
Income distributed to Unit holders for the year 1996 was $37,803,167 or
$.811072 per Unit. This distributable income consisted of Royalty Income of
$41,236,424 plus interest income of $76,346 less administrative expenses of
$3,509,603. $19,822,005 of the 1996 distributable income is attributable to the
settlement of litigation involving the Trustee and BROG. For further information
regarding the litigation settlement, see Note 5 to the accompanying Financial
Statements.
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, 1997, and for the year ending December 31, 1997. Unit holders
owning Units in nominee name may obtain monthly tax information from the Trustee
upon request.
Bank One, Texas, NA, Trustee
By: /s/ LEE ANN ANDERSON
Lee Ann Anderson
Vice President
3
<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 "Trust Properties"). The Trust
Properties contain 151,900 (119,000 net) producing acres and 3,180 (960 net)
economic wells, including dual completions.
The Trust 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, 1996, the production index for the San Juan Basin properties is estimated to
be approximately 10.1 years.
During 1988, a drilling program was initiated involving development of
Fruitland Coal gas reserves. Wells drilled in the Fruitland Coal range in depth
from 2,500 to 3,500 feet on a 320acre 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 filed
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.
From 1988 through December 31, 1996, BROG has participated in the
completion of 113 gross (75.05 net) and recompletions of 110 gross (65.96 net)
coal seam wells on Trust Properties. At December 31, 1996, 167 coal seam wells
had been connected to pipeline facilities. During 1996, these coal seam wells
produced a total of approximately 16,250,517 MMBtu of gas from the Trust
Properties, which was sold at an average price of $1.02 per MMBtu. 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 qualifying coal seam formation which
are later completed into such formation, also qualifies for the tax credit. For
1996 the credit was approximately $1.03 per MMBtu. During 1995, potential
Section 29 tax credits of approximately $1.02 per Unit were generated for Trust
Unit holders from production from coal seam wells.
During 1996, BROG incurred approximately $7,223,281 of capital
expenditures for the drilling and completion of 14 gross (1.50 net) conventional
wells, recavition of 17 gross (5.63 net) coal seam wells, recompleting 4 gross
(.16 net) conventional wells as coal seam wells, recompleting 9 gross (5.93 net)
conventional wells and other maintenance activities. There was 1 gross (.05 net)
coal seam well, 3 gross (.14 net) coal seam recompletions and 17 gross (1.96
net) conventional wells in progress at December 31, 1996. During 1995, Southland
Royalty participated in the completion of 24 gross (11.41 net) conventional
wells, drilling and completion of 5 gross (2.54 net) coal seam wells,
recompleting 38 gross (8.61 net) conventional wells and other maintenance
activities and facilities costs at a cost of $6,560,276.
Due to the size of the coal seam drilling program in the San Juan Basin
during the last several years by various operators, there was more gas
deliverability than available pipeline capacity. Consequently, these properties
produced only 20.4 Bcf during 1991. 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 40.7 in 1996.
BROG has advised the Trustee that mainline capacity out of the San Juan Basin is
estimated at 3.05 Bcf per day for El Paso Natural Gas Pipeline Company and
approximately 1.51 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.
Based on existing geological and pricing information, there are
approximately 72 net conventional wells remaining to be drilled on the Trust
Properties. Proved undeveloped reserves have been assigned to these wells. BROG
has advised the Trust that its 1997 capital expense estimate for Trust working
interests is estimated to be $1.7 million. Fruitland Coal is estimated to be
approximately 16% of the total and the remainder would be conventional projects,
including 43 new drill locations. There are 13 other projects planned, half of
which would involve conventional locations. 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.
Gas production from the Trust Properties is sold in both interstate and
intrastate commerce. For a further discussion of gas pricing, gas purchasers,
gas production and regulatory matters affecting gas production see Item 2 in the
accompanying Form 10-K.
4
<PAGE>
Millenniums of intense heat and pressure on fossilized marine life and other
organic matter formed the San Juan Basin's natural gas and petroleum resources.
5
<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, 1996,
distributable income increased to $37,803,167 from $13,790,101 distributed in
1995. The increase was primarily attributable to the payment by Burlington to
the Trust in September 30, 1996, of $19,822,005 in settlement of litigation
involving Bank One, Texas, NA, as Trustee and BROG (the "Litigation"). Interest
income increased from $31,978 in 1995 to $76,346 in 1996 primarily due to
increased funds available for investment.
The Trustee announced on September 4, 1996, the settlement of the
Litigation. The Litigation, which was filed in the state district court of Santa
Fe County, New Mexico, 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 Trust Properties. BROG
denied and continues to deny the allegations made against it in the Litigation,
but the parties agreed to settle the Litigation as outlined below.
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
Trust Properties. Agreement was also reached regarding marketing arrangements
for the sale of Trust gas, oil and natural gas liquids products going forward as
follows:
1. BROG's preexisting contract with a third-party purchaser as pertains to base
load gas volumes in the firm amount of 45,000 MMBtu per day will remain
effective for a period of one year from July 1, 1996. Negotiations for the sale
of these volumes after June 30, 1997, will be entered into prior to the
expiration of the primary term of that contract;
2. The remaining volumes of Trust gas will be marketed by an independent
marketer, El Paso Energy Marketing Company ("El Paso"), a subsidiary of El Paso
Energy Corporation, beginning October 1, 1996, under an arrangement which
provides for a sharing of amounts, if any, earned in excess of established gas
price thresholds. El Paso's compensation for its marketing services consists
solely of its proportionate part of any amount for which the gas sold in
excess of the thresholds. BROG's contract with El Paso is for a two-year term
beginning October 1, 1996, subject to renewal by agreement of the parties;
3. 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
4. The marketer of the Trust gas will have 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 may utilize
BROG's contractual rights for delivery on the El Paso Natural Gas Company
pipeline to pipelines in West Texas for up to 13,333 MMBtu per day of gas
produced from the Trust Properties for a period of one year commencing October
1, 1996.
Confidentiality agreements with purchasers of the gas produced from the
Trust 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 of the
marketer to compete effectively in the marketplace for the sale of gas produced
from the Trust Properties.
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. Gas and oil sales attributable to the Royalty for the past five years,
excluding portions attributable to the litigation settlement proceeds (See Note
6 to accompanying Financial Statements), are summarized in the following table:
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Gas - Mcf 17,927,785 13,331,758 15,459,542 23,895,506 13,984,645
Average Price (per Mcf) $1.30 $1.25 $1.66 $1.70 $1.57
Oil - Bbls 36,792 29,424 36,769 51,921 41,087
Average Price (per Bbl) $19.64 $14.43 $13.09 $15.58 $17.65
</TABLE>
6
<PAGE>
Due to the increase in the average price of gas in the first quarter of
1993, the average price for the year increased. Gas prices plummeted in 1995.
Since the oil and gas sales attributable to the Royalty are based on an
allocation formula that is dependent on such factors as price and cost, the
production amounts do not provide a meaningful comparison.
Total gas and oil production from the properties from which the Royalty
was carved for the five years ended December 31, 1996, were as follows:
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Gas - 40,738,422 34,222,189 34,222,189 40,736,391 26,642,265
Mcf per day 111,307 94,211 93,759 111,607 72,993
Oil - Bbls 83,552 75,014 84,648 88,466 79,600
Bbls per day 228 206 232 242 218
</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
properties from which the Royalty was carved 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.
Royalty Income for the five years ended December 31, 1996, was determined
as shown in the following table:
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
GROSS PROCEEDS FROM THE SOUTHLAND
ROYALTY PROPERTIES FROM WHICH THE
TRUST'S OVERRIDING ROYALTY WAS CARVED:
Gas $51,865,730 $41,483,305 $54,375,586 $69,266,623 $41,961,599
Oil 1,638,753 1,084,262 1,140,738 1,384,468 1,409,179
Other -0- 2,952 -0- -0- -0-
1990 Litigation Settlement -0- -0- -0- -0- 16,118,174
----------- ----------- ----------- ---------- -----------
Total 53,504,483 42,570,159 55,498,324 70,651,091 59,488,952
----------- ----------- ----------- ---------- -----------
LESS PRODUCTION COSTS:
Capital Costs 7,223,281 6,560,277 9,409,462 3,988,136 2,530,833
Severance Tax - Gas 5,654,831 4,694,750 5,864,834 6,543,615 3,696,172
Severance Tax - Oil 176,379 115,474 117,028 153,072 155,663
Severance Tax - Other 59,089 117 -0- -0- -0-
Severance Tax - Litigation -0- -0- -0- -0- 356,944
Lease Operating Expenses 11,838,345 10,991,152 9,066,750 9,864,773 9,423,403
----------- ----------- ----------- ---------- -----------
Total 24,951,925 22,361,770 24,458,074 20,549,596 16,163,015
----------- ----------- ----------- ---------- -----------
Net Profits 28,552,558 20,208,389 31,040,250 50,101,495 43,325,937
Royalty Percentage 75% 75% 75% 75% 75%
Royalty Income $21,414,419 $15,156,292 $23,280,188 $37,576,121 $32,494,453
=========== =========== =========== =========== ===========
</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 properties from which the
Royalty was carved for the year ended December 31, 1996, amounted to $7,223,281
versus $6,560,277 for 1995. The increase was primarily attributable to increased
drilling activity. The litigation settlement and the related severance taxes
for 1992 pertain to The Public Service Company of New Mexico litigation which
was settled during 1990. 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. See Note 5 to the accompanying Financial
Statements. Monthly operating costs in 1996 averaged approximately $955,000,
which is higher than the $876,000 average in 1995.
7
<PAGE>
Coal seams lying relatively near the surface of the earth yield much of the
natural gas produced in the San Juan Basin.
8
<PAGE>
RESULTS OF THE 4TH QUARTERS OF 1996 AND 1995
Distributable income for the three months ended December 31, 1996, totaled
$8,143,076 ($.174711 per Unit) as compared to $1,182,038 ($.025361 per Unit) for
the quarter ended December 31, 1995. The amount distributed in the fourth
quarter of 1996 was higher than that of 1995 primarily because of the higher
average price of gas sold.
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, 1996 and 1995 were as follows:
<TABLE>
<CAPTION>
1996 1995
- ----------------------------------------------------------
<S> <C> <C>
PROPERTIES FROM WHICH
THE ROYALTY WAS CARVED
Gas Mcf 10,535,177 8,929,852
Average Price (per Mcf) $1.64 $.98
Oil - Bbls 19,460 17,681
Average Price (per Bbl) $21.06 $14.72
ATTRIBUTABLE TO THE ROYALTY
Gas - Mcf 5,478,137 1,864,559
Oil - Bbls 10,260 17,681
</TABLE>
The average price of gas increased in the fourth quarter of 1996 primarily
due to increases in spot prices. The average price of oil increased compared to
the prior year because of increases in the posted prices. Gas production
increased primarily due to increased coal seam production and demand from gas
purchasers. During the fourth quarter of 1996, coal seam production from the
properties from which the Royalty was carved averaged 1,728,000 Mcf per month
compared to 1,173,000 Mcf per month during the fourth quarter of 1995.
Capital costs for the fourth quarter of 1996 totaled $1,996,490 compared
to $2,413,744 during the same period of 1995. The decrease was due to a decrease
in drilling activity in the fourth quarter of 1996. Lease operating costs for
the fourth quarter of 1996 averaged $926,000 per month in the fourth quarter
compared to $1,025,000 per month in the fourth quarter of 1995.
9
<PAGE>
SAN JUAN BASIN ROYALTY TRUST
<TABLE>
<CAPTION>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
DECEMBER 31, 1996 AND 1995
1996 1995
- ---------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
Cash and Short-term Investments $ 3,127,828 $ 421,446
Net Overriding Royalty Interest in Producing Oil and
Gas Properties - Net (Notes 2 and 3) 62,808,148 70,133,536
------------ ------------
$ 65,935,976 $ 70,554,982
============ ============
LIABILITIES AND TRUST CORPUS
Distribution Payable to Unit Holders $ 3,127,828 $ 421,446
Contingencies (Note 5) - -
Trust Corpus - 46,608,796 Units of Beneficial
Interest Authorized and Outstanding 62,808,148 70,133,536
------------ ------------
$ 65,935,976 $ 70,554,982
============ ============
</TABLE>
<TABLE>
<CAPTION>
STATEMENTS OF DISTRIBUTABLE INCOME
FOR THE THREE YEARS ENDED
DECEMBER 31, 1996
1996 1995 1994
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Royalty Income (Notes 2, 3 and 5) $ 41,236,424 $ 15,156,292 $ 23,280,188
Interest Income 76,346 31,978 38,129
------------ ------------ ------------
41,312,770 15,188,270 23,318,317
Expenditures- General and Administrative 3,509,603 1,398,169 685,824
------------ ------------ ------------
Distributable Income $ 37,803,167 $ 13,790,101 $ 22,632,493
------------ ------------ ------------
Distributable Income per Unit (46,608,796 Units) $ .811072 $ .295867 $ .485584
============ ============ ============
STATEMENTS OF CHANGES IN TRUST CORPUS
FOR THE THREE YEARS ENDED
DECEMBER 31, 1996
1996 1995 1994
- ---------------------------------------------------------------------------------------------------
Trust Corpus, Beginning of Period $ 70,133,536 $ 74,942,040 $ 79,898,032
Amortization of Net Overriding Royalty
Interest (Notes 2 and 3) (7,325,388) (4,808,504) (4,955,992)
Distributable Income 37,803,167 13,790,101 22,632,493
Distributions Declared (37,803,167) (13,790,101) (22,632,493)
------------ ------------ ------------
Trust Corpus, End of Period $ 62,808,148 $ 70,133,536 $ 74,942,040
============ ============ ============
</TABLE>
The accompanying Notes to Financial Statements are an integral part of this
statement.
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, NA ("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 is 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, 1996 and 1995 aggregated $70,467,380
and $63,141,992, 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
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.
11
<PAGE>
[_] SAN JUAN
BASIN
[_] GAS
FIELDS
[_] OIL
FIELDS
[_] LEASEHOLD
ACREAGE
[_] MINERAL
ACREAGE
12
<PAGE>
4. FEDERAL INCOME TAXES
For Federal income tax purposes, the Trust constitutes a taxed 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 concerning 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 qualifying coal seam formation
which are later completed into such formation, also qualifies for the tax
credit. This tax credit was approximately $1.03 per MMBtu for the year 1996 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. COMMITMENTS AND CONTINGENCIES
On June 4, 1992, the Trustee filed suit against MOI and Southland in the state
district court in Rio Arriba County, New Mexico, Cause No. RA 92-1211(C). MOI
and Southland were the operators of the Trust 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").
In a decision filed August 8, 1994, the Supreme Court of New Mexico ruled
that venue was not proper in Rio Arriba County and remanded the case for
dismissal without prejudice to its refiling. In its ruling, the Supreme Court of
New Mexico also ruled that venue was proper in Santa Fe County, New Mexico. Such
decision did not relate to merits of the Trust's claims. The Trustee refiled the
lawsuit in Santa Fe County, New Mexico on August 31, 1994, in Cause No.
SF 94-1982(C).
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 "Trust Properties").
The claims asserted on behalf of the Trust in the Santa Fe County, New
Mexico, lawsuit included breach of contract, breach of the covenant of good
faith and fair dealing, breach of express good faith duty, constructive fraud,
unjust enrichment, prima facie tort, intentional interference with contract and
conspiracy. The relief sought included compensatory and punitive damages, an
accounting and a permanent injunction relating to the operation of the Trust
Properties.
In response to the Trustee's lawsuit, Southland filed suit on August 7,
1992 against the Trustee in Probate Court in Tarrant County, Texas, Cause No.
92-1927-2. Non-binding mediation, which had been ongoing with regard to the
lawsuit filed in Santa Fe County, New Mexico, was not successful in resolving
the claims asserted by the Trust.
On September 4, 1996, the Trustee announced the settlement of the
litigation (the "Litigation"). The Litigation was dismissed on September 12,
1996.
BROG has 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
13
<PAGE>
reductions favorable to the Trust in the ongoing charges for coal seam gas
gathering and treating on BROG's Val Verde system. Additionally, the Trustee and
BROG established a formal protocol that will provide the Trustee and its
representatives improved access to BROG's books and records applicable to the
Trust Properties.
Agreement was also reached regarding marketing arrangements for the sale
of Trust gas, oil and natural gas liquids products going forward as follows:
1) BROG's pre-existing contract with a third-party purchaser as pertains
to baseload gas volumes in the firm amount of 45,000 MMBtu per day will remain
effective for a period of one year from July 1, 1996. Negotiations for the sale
of these volumes after June 30, 1997, will be entered into prior to the
expiration of the primary term of that contract;
2) 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, under an arrangement which
provides for a sharing of amounts, if any, earned in excess of established gas
price thresholds. El Paso's compensation for its marketing services consists
solely of its proportionate part of any amounts for which the gas is sold in
excess of the thresholds. BROG's contract with El Paso is for a two year term
beginning October 1, 1996, subject to renewal by agreement of the parties;
3) 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
4) 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 may 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 Trust Properties for a period of one year
commencing October 1, 1996.
Confidentiality agreements with purchasers of gas produced from the Trust
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 Trust
Properties.
The $19,822,005 (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 Trust 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 wellhead 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 properties from which the Royalty was carved.
To continue to maximize production and revenues from Trust
14
<PAGE>
properties, Southland again informed the Trustee that it negotiated an agreement
with Sunterra 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 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.
Southland also advised the Trust 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 Trust has further been advised by Southland that MOTI negotiated an
agreement with Gas Company providing for transportation service on Gas Company's
Albuquerque mainline. This agreement was effective on the closing date of the
sale of Gas Company's gathering and processing facilities to Williams. This
transportation agreement will be necessary to deliver volumes of gas behind the
Lybrook processing plant to mainline delivery points.
Southland further informed the Trust that on September 13, 1994, MOTI
entered into a gas sales agreement with Gas Company for the five winter periods
beginning November 1, 1995, and ending March 31, 2000. MOTI purchased the gas
supplied for this sale from MOI producing affiliates and third party sellers.
Sales were based on a monthly published index. BROG has informed the Trust that
as a result of the Litigation (as hereinafter defined), no gas produced from the
properties from which the Royalty was carved will be applied in performance of
such agreement with Gas Company. It is the understanding of the Trustee that Gas
Company is now known as PNM Gas Services.
While it is impossible to determine the exact economic value to be derived
under these agreements, Southland has advised the Trust that it considers the
terms of these agreements to be favorable, and of substantial additional value.
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, 1996 (in thousands, except unit
amounts):
<TABLE>
<CAPTION>
DISTRIBUTABLE
INCOME AND
DISTRIBUTABLE
DISTRIBUTABLE INCOME
1996 ROYALTY INCOME PER UNIT
- ---------------------------------------------------------
<S> <C> <C> <C>
First Quarter $ 4,708 $ 3,926 $.084239
Second Quarter 4,048 2,943 .063143
Third Quarter 24,135 22,791 .488979
Fourth Quarter 8,345 8,143 .174711
------- ------- --------
Total $41,236 $37,803 $.811072
======= ======= ========
1995
- ---------------------------------------------------------
First Quarter $ 4,476 $ 4,222 $.090595
Second Quarter 5,458 5,054 .108430
Third Quarter 3,542 3,332 .071482
Fourth Quarter 1,680 1,182 .025360
------- ------- --------
Total $15,156 $13,790 $.295867
======= ======= ========
</TABLE>
15
<PAGE>
INDEPENDENT AUDITOR'S REPORT
BANK ONE, TEXAS, NA 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, 1996 and
1995, and the related statements of distributable income and changes in trust
corpus for each of the three years in the period ended December 31, 1996. 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, 1996 and 1995 and the distributable income and changes
in trust corpus for each of the three years in the period ended December 31,
1996 on the basis of accounting described in Note 3.
/s/ DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Fort Worth, Texas
March 25, 1997
San Juan Basin Royalty Trust
Bank One, Texas, NA, Trustee
Post Office Box 2604
Fort Worth, Texas 76113
Auditors
Deloitte & Touche LLP
Fort Worth, Texas
Legal Counsel
Vinson & Elkins L.L.P
Dallas, Texas
Tax Counsel
Butler & Binion, L.L.P.
Houston, Texas
Transfer Agent
Harris Trust & Savings Bank
Chicago, Illinois
16
<PAGE>
EXHIBIT 23
[PASTE-UP LETTERHEAD HERE]
March 26, 1997
San Juan Basin Royalty Trust
Bank One, Texas
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, 1996 and in the
San Juan Basin Royalty Trust Annual Report for the year ended December 31,
1996 based on reserve reports dated March 25, 1997 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 OF SAN
JUAN BASIN ROYALTY TRUST AS OF DECEMBER 31, 1996, AND THE RELATED CONDENSED
STATEMENTS OF DISTRIBUTABLE INCOME AND CHANGES IN TRUST CORPUS FOR THE TWELVE-
MONTH PERIOD ENDED DECEMBER 31, 1996.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 3,127,828
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 3,127,828
<PP&E> 133,275,528
<DEPRECIATION> 70,467,380
<TOTAL-ASSETS> 65,935,976
<CURRENT-LIABILITIES> 3,127,828
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 62,808,148
<TOTAL-LIABILITY-AND-EQUITY> 65,935,976
<SALES> 0
<TOTAL-REVENUES> 41,312,770
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 3,509,603
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 37,803,167
<INCOME-TAX> 0
<INCOME-CONTINUING> 37,803,167
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 37,803,167
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
