<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, 1995, 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 No.)
BANK ONE, TEXAS, NA 76113
TRUST DEPARTMENT (Zip Code)
P.O. BOX 2604
FORT WORTH, TEXAS
(Address of Principal Executive
Offices)
(817) 884-4630
(Registrant's Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -----------------------
<S> <C>
UNITS OF BENEFICIAL INTEREST NEW YORK STOCK EXCHANGE
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
NONE
(Title of Class)
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
At April 10, 1996, there were 46,608,796 Units of Beneficial Interest of the
Trust outstanding with an aggregate market value on that date of $273,826,676.
DOCUMENTS INCORPORATED BY REFERENCE
"Units of Beneficial Interest" at page 2; "Description of Properties" at page
4; "Trustee's Discussion and Analysis for the Three-Year Period Ended December
31, 1995" at pages 6 and 7; "Results of the 4th Quarters of 1995 and 1994" at
page 8; and "Statements of Assets, Liabilities and Trust Corpus," "Statements
of Distributable Income," "Statements of Changes in Trust Corpus," "Notes to
Financial Statements," and "Independent Auditors' Report" at page 10 et seq.,
in registrant's Annual Report to security holders for fiscal year ended
December 31, 1995 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
817/884-4630).
On October 23, 1980, the stockholders of Southland Royalty approved and
authorized that company's conveyance of a net overriding royalty interest
(equivalent to a net profits interest) to the Trust for the benefit of the
stockholders of Southland Royalty of record at the close of business on the
date of the conveyance consisting of a 75% net overriding royalty interest
carved out of that company's oil and gas leasehold and royalty interests in the
San Juan Basin of northwestern New Mexico. The conveyance of this interest (the
"Royalty") was made on November 3, 1980, effective as to production from and
after November 1, 1980 at 7:00 A.M.
The 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. In March 1992, El Paso completed an initial public
offering of 5,750,000 newly issued shares of El Paso common stock, thereby
decreasing BRI's ownership of El Paso to approximately eighty-five percent
(85%). On June 30, 1992, BRI distributed all of the shares of El Paso common
stock owned by BRI to BRI's stockholders of record as of June 15, 1992. See
"Pricing Information" under "Item 2. Properties" herein.
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.
The term "net proceeds" as used in the October 23, 1980 conveyance means the
excess of "gross proceeds" received by MOI during a particular period over
"production costs" for such period. "Gross proceeds" means the amount received
by MOI (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
1
<PAGE>
carved, subject to certain adjustments. "Production costs" means, generally,
costs incurred on an accrual basis by MOI in operating its properties and
interests out of which the Royalty was carved, including both capital and non-
capital costs; for example, 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 liable for any production costs or other costs or liabilities attributable
to these properties and interests or the minerals produced thereform. 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.
Certain of the properties and interests out of which the Royalty was carved
are operated by MOI with the obligation to conduct its operations in accordance
with reasonable and prudent business judgment and good oil and gas field
practices. As operator, MOI 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. MOI 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 reasonably obtainable in the
circumstances. MOI also has the obligation to maintain books and records
sufficient to determine the amounts payable to the Trustee. MOI, 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 MOI in
the second month, the net proceeds attributable to the Royalty are paid by MOI
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 interests and royalty interests in the San Juan
Basin in northwestern New Mexico. References below to "net" wells and acres are
to the interests of Southland Royalty (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 Southland Royalty or MOI.
2
<PAGE>
PRODUCING ACREAGE, WELLS AND DRILLING
MOI'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 2,906 gross (944 net)
economic wells, including dual completions. A dispute between the Trustee and
MOI as to the well count is an issue in the litigation pending in Santa Fe
County, New Mexico. See "Item 3. Legal Proceedings". 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, 1995, is
herein incorporated by reference.
The Royalty conveyed to the Trust is limited to the base of the Dakota
formation, which is currently the deepest significant producing formation under
acreage affected by the Royalty. Rights to production, if any, from deeper
formations are retained by MOI.
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. During 1993, there were 31 gross (13.9 net) wells completed
including 18 gross (8.27 net) coal seam wells.
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, 1995
were as follows:
<TABLE>
<CAPTION>
1995 1994 1993
----------------- ----------------- -----------------
OIL OIL OIL
(BBLS) GAS (MCF) (BBLS) GAS (MCF) (BBLS) GAS (MCF)
------ ---------- ------ ---------- ------ ----------
<S> <C> <C> <C> <C> <C> <C>
Production......... 29,424 13,331,758 36,769 15,459,542 51,921 23,895,506
Average Price...... $14.43 $1.25 $13.09 $1.66 $15.58 $1.70
</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. Production from the properties
from which the Royalty was carved totalled 34,387,190 Mcf during 1995.
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").
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. MOTI presently markets gas, including
gas produced from properties in which the Trust owns an interest, under short-
term arrangements to end users.
3
<PAGE>
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 judgement that PNM had no prior liability for gas
purchased at prices below the contract prices and (ii) a permanent injunction
prohibiting future claims against PNM for gas purchases at prices below the
contract prices. PNM claimed the pricing provisions were the result of a
conspiracy in violation of antitrust laws. Southland Royalty counter-claimed
against PNM alleging breach of both the pricing provisions and the minimum take
requirements of the gas purchase contracts. In June 1988, Southland Royalty
filed a separate breach of contract suit in a State District Court in Harris
County, Texas on these same claims against PNM alleging damages in excess of
$40 million.
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 or 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 purchase contracts, Southland Royalty would
receive 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
provided for certain "take-or-pay obligations" if specified quantities of gas
(66 2/3% 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 must 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 6 of Notes to Financial Statements of the Trust's Annual Report to
security holders for the year ended December 31, 1995 for further discussion of
this settlement and its impact upon the Trust.
4
<PAGE>
The gas gathering contract provides 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 would receive 80% of the plant products derived from processing the
gas. The processing company would 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 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 3,241,550 Mcf, respectively, at average
prices of $2.25 and $1.98 per Mcf 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 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 have 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
5
<PAGE>
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 will be necessary to deliver volumes of
gas behind the Lybrook processing plant to mainline delivery points.
Southland Royalty has further informed the Trust that on September 13, 1994,
MOTI, one of the first purchasers of MOI producing affiliates' gas, entered
into a gas sales agreement with Gas Company for the next five winter periods
beginning November 1, 1995 and ending March 31, 2000. MOTI will be purchasing
the gas supplied for this sale from MOI producing affiliates and other third
party sellers. Sales will be based on a monthly published index. Valid delivery
points under the agreement will be the tailgate of the Lybrook Plant, the
tailgate of the Kutz Plant, the Blanco Hub, or Rio Puerco.
It is the understanding of the Trustee that Gas Company is now known as PNM
Gas Services.
OIL AND GAS RESERVES
The following are definitions adopted by the Securities and Exchange
Commission ("SEC") and the Financial Accounting Standards Board which are
applicable to terms used within this Item:
"Proved reserves" are those estimated quantities of crude oil, natural
gas and natural gas liquids, which, upon analysis of geological and
engineering data, appear with reasonable certainty to be recoverable in the
future from known oil and gas reservoirs under existing economic and
operating conditions.
"Proved developed reserves" are those proved reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.
"Proved undeveloped reserves" are those proved reserves which are
expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required.
"Estimated future net revenues" are computed by applying current prices
of oil and gas (with consideration of price changes only to the extent
provided by contractual arrangements and allowed by federal regulation) to
estimated future production of proved oil and gas reserves as of the date
of the latest balance sheet presented, less estimated future expenditures
(based on current costs) to be incurred in developing and producing the
proved reserves, and assuming continuation of existing economic conditions.
"Estimated future net revenues" are sometimes referred to herein as
"estimated future net cash flows".
"Present value of estimated future net revenues" is computed using the
estimated future net revenues and a discount rate of 10%.
6
<PAGE>
The independent petroleum engineers' reports as to the proved oil and gas
reserves as of December 31, 1993, 1994 and 1995 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1992 to
December 31, 1995 (in thousands):
<TABLE>
<CAPTION>
NATURAL
OIL GAS
(BBLS) (MCF)
------ -------
<S> <C> <C>
Reserves as of December 31,1992........................... 780 254,512
Revisions of previous estimates........................... (16) 14,995
Extensions, discoveries and other additions............... -0- 2,490
Production................................................ (52) (23,896)
---- -------
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
==== =======
</TABLE>
Estimated quantities of proved developed reserves of crude oil and natural
gas as of December 31, 1995, 1994 and 1993 were as follows (in thousands):
<TABLE>
<CAPTION>
CRUDE NATURAL
OIL GAS
(BBLS) (MCF)
------ -------
<S> <C> <C>
1995....................................................... 418 159,650
1994....................................................... 612 186,915
1993....................................................... 712 230,736
</TABLE>
The Financial Accounting Standards Board requires supplemental disclosures
for oil and gas producers based on a standardized measure of discounted future
net cash flows relating to proved oil and gas reserve quantities. Under this
disclosure, future cash inflows are estimated by applying year-end prices of
oil and gas relating to the enterprise's proved reserves to the year-end
quantities of those reserves. Future price changes are only considered to the
extent provided by contractual arrangements in existence at year-end. The
standardized measure of discounted future net cash flows is achieved by using a
discount rate of 10% a year to reflect the timing of future net cash flows
relating to proved oil and gas reserves.
Estimates of proved oil and gas reserves are by their very 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 1995, 1994 and 1993 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>
1995 1994 1993
-------- --------- --------
<S> <C> <C> <C>
Balance, January 1........................ $157,627 $ 274,215 $263,525
Revisions of prior-year estimates, change
in prices and other...................... (51,819) (120,730) 19,066
Extensions, discoveries and other
additions................................ 522 -0- 2,847
Accretion of discount..................... 15,763 27,422 26,353
Royalty income............................ (15,156) (23,280) (37,576)
-------- --------- --------
Balance, December 31...................... $106,937 $ 157,627 $274,215
======== ========= ========
</TABLE>
7
<PAGE>
Reserve quantities and revenues shown in the tables above for the Royalty
were estimated from projections of reserves and revenues attributable to the
combined MOI 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. Royalty income related to the settlement with PNM is not
included in the royalty income for 1992 because it does not relate to
production for that year and is not included in estimated future net cash
flows. Because the reserve quantities attributable to the Royalty are estimated
using an allocation of the reserves, any changes in prices or costs will result
in changes in the estimated reserve quantities allocated to the Royalty.
Therefore, the reserve quantities estimated will vary if different future price
and cost assumptions occur. The future net cash flows were determined without
regard to future federal income tax credits available to production from coal
seam wells.
December average prices of $1.36 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.
An average price of $2.14 per Mcf and $10.94 per barrel were used at December
31, 1993, in determining estimated future net revenues.
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, 1995, 1994 and 1993 (in thousands except amounts per Unit):
<TABLE>
<CAPTION>
1995 1994 1993
------------------ ------------------ ------------------
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............ $184,055 $106,937 $287,401 $157,627 $500,013 $274,215
======== ======== ======== ======== ======== ========
Proved Developed........ $175,824 $104,378 $265,477 $149,241 $464,132 $261,536
======== ======== ======== ======== ======== ========
Total Proved Per Unit... $3.95 $2.29 $6.17 $3.38 $10.73 $5.88
======== ======== ======== ======== ======== ========
</TABLE>
Proved reserve quantities are estimates based on information available at the
time of preparation and such estimates are subject to change as additional
information becomes available. The reserves actually recovered and the timing
of production of those reserves may be substantially different from the above
estimates. Moreover, the present values shown above should not be considered as
the market values of such oil and gas reserves or the costs that would be
incurred to acquire equivalent reserves. A market value determination would
include many additional factors.
REGULATION
Many aspects of the production, pricing and marketing of crude oil and
natural gas are regulated by federal and state agencies. The Federal Energy
Regulatory Commission ("FERC") is primarily responsible for federal regulation
of natural gas.
Natural Gas Regulation
The interstate transportation and sale for resale of natural gas is subject
to federal governmental regulation, including regulation of tariffs charged and
various other matters, by FERC. The Natural Gas Wellhead Decontrol Act of 1989
terminated federal price controls on wellhead sales of domestic natural gas on
January 1, 1993.
8
<PAGE>
In 1992, FERC issued Orders Nos. 636 and 636-A, 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.
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. This tax credit for 1995 was
approximately $1.01 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 taxpayer's regular
tax liability, subject, however, to the limitations described in the preceding
sentence. There is no provision for the carryback or carryforward of the
Section 29 credit in any other circumstances.
Other Regulation
The petroleum 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
For information concerning legal proceedings, Notes 5 and 6 of the Notes To
Financial Statements at pages 12 through 15 of the Trust's Annual Report to
security holders for the year ended December 31, 1995 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, 1995.
9
<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, 1995, is
herein incorporated by reference.
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Royalty income.......... $15,156,292 $23,280,188 $37,576,121 $32,494,453 $21,639,360
Distributable income.... 13,790,101 22,632,493 36,760,797 31,705,994 21,142,738
Distributable income per
Unit................... 0.295867 0.485584 0.788710 0.680257 0.453621
Distributions per Unit.. 0.295867 0.485584 0.788710 0.680257 0.453621
Total assets, December
31..................... 70,554,982 75,531,405 82,701,203 90,372,116 94,236,689
</TABLE>
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
1995 and 1994" at pages 6, 7 and 8 of the Trust's Annual Report to security
holders for the year ended December 31, 1995, are herein incorporated by
reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Financial Statements of the Trust and the notes thereto at page 10 et
seq., of the Trust's Annual Report to security holders for the year ended
December 31, 1995, are herein incorporated by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There have been no changes in accountants and no disagreements with
accountants on any matter of accounting principles or practices or financial
statement disclosures during the twenty-four months ended December 31, 1995.
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, 1995, the Trustee received total
remuneration as follows:
<TABLE>
<CAPTION>
NAME OF INDIVIDUAL
OR NUMBER OF CASH
PERSONS IN GROUP CAPACITIES IN WHICH SERVED COMPENSATION
------------------ ----------------------------- ------------
<S> <C> <C>
Bank One, Texas, NA............ Trustee and Transfer Agent(1) $127,974(2)
</TABLE>
- --------
(1) Effective October 1995, Harris Trust & Savings Bank became the transfer
agent of the Trust.
(2) 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
10
<PAGE>
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.
The Trustee may also charge a transfer agency fee if acting in that
capacity. Of the amount stated in the table above, $106,328 was in payment
of the Trustee's administrative fee. The balance of $21,646 was in payment
of the Trustee's transfer agency fee.
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, 1995, information with respect to each person known
to own beneficially more than 5% of the outstanding Units of the Trust:
<TABLE>
<CAPTION>
AMOUNT AND
NATURE OF PERCENT
BENEFICIAL OF
NAME AND ADDRESS OWNERSHIP 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).................. 3,809,400 Units 8.2%
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 January 5, 1996, filed with the Securities
and Exchange Commission by The Fund American Enterprises Holdings, Inc.
("FAEH") which indicated that these Units were owned by FAEH.
According to such Form 4, FAEH owns such 10,994,876 Units indirectly:
2,516,927 Units indirectly through its wholly-owned subsidiary FFOG, Inc.,
8,242,949 Units indirectly through its wholly-owned subsidiary Fund
American Enterprises, Inc. ("FAE") and 235,000 Units indirectly through
FAE's 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 2 to Schedule 13G dated February 9, 1996, 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 3,809,400 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
3,054,400 Units and sole dispositive power over 3,809,400 Units.
The Amendment 2 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.
(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, 1995 an aggregate of 24,538 Units with the sole right
to vote 8,386 of these Units and shared right to vote 16,152 of these Units.
Such Bank disclaims any beneficial interests 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, 1995
and Item 12(b) for information concerning Units owned by Bank One, Texas, NA in
various fiduciary capacities.
11
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
The following documents are filed as a part of this Report:
FINANCIAL STATEMENTS
Included in Part II of this Report by reference to the Annual Report of the
Trust for the year ended December 31, 1995:
Independent Auditors' Report
Statements of Assets, Liabilities and Trust Corpus
Statements of Distributable Income
Statements of Changes in Trust Corpus
Notes to Financial Statements
FINANCIAL STATEMENT SCHEDULES
Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required information is
given in the financial statements or notes thereto.
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 Fort 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, 1995.**
(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, 1995, one
report on Form 8-K was filed with the Securities and Exchange Commission by the
Trust. This Form 8-K relates to the lawsuit filed in New Mexico referenced in
"Item 3. Legal Proceedings" herein.
The Form 8-K dated December 1, 1995, reported that with regard to the lawsuit
filed by the Trustee of the Trust against MOI and Southland Royalty in the
state district court in Santa Fe County, New Mexico, in Cause No. SF94-1982(c),
a hearing was held on November 17, 1995 regarding the Trustee's motion for
leave to file its Second Amended Complaint. Such motion was granted by the
court. The Trustee filed the Second Amended Complaint to more fully
particularize the pleadings, the nature of the claims of liability in the case,
and the facts supporting alter ego and single business enterprise liability and
fraudulent concealment
12
<PAGE>
as it pertains to the defendants' statute of limitations defense and to assert
the following additional claims for relief: breach of express good faith duty,
constructive fraud, unjust enrichment and prima facie tort and to add claims in
the alternative of intentional interference with contract and of conspiracy. A
copy of such Second Amended Complaint was attached as an exhibit to the Form 8-
K.
It was also reported that a hearing had been held on a motion filed by MOI
and Southland Royalty seeking a continuance of the February 1996 trial setting.
Such motion was granted at a hearing held on November 28, 1995. Trial is now
scheduled to begin July 15, 1996.
No financial statements were required to be filed in connection with the
filing of this Form 8-K.
13
<PAGE>
SIGNATURE
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
Bank One, Texas, NA
Trustee of the San Juan Basin Royalty
Trust
/s/ Lee Ann Anderson
By________________________________________
(Lee Ann Anderson)
Vice President
Date: April 15, 1996
(The Trust has no directors or executive officers.)
14
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
SEQUENTIALLY
EXHIBIT NUMBERED
NUMBER EXHIBIT PAGE
------- ------- ------------
<C> <S> <C>
(4)(a) --San Juan Basin Royalty Trust Indenture dated
November 3, 1980, between Southland Royalty Company
and The Fort Worth National Bank (now Bank One,
Texas, 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 Fort 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, 1995.**
(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 active cost
of reproduction, upon written request to the Trustee, Bank One, Texas, NA,
P.O. Box 2604, Fort Worth, Texas 76113.
** Filed herewith
<PAGE>
S A N J U A N B A S I N R O Y A L T Y T R U S T
1 9 9 5 A N N U A L R E P O R T & F O R M 1 0 - K
<PAGE>
[PICTURE OF WORK GLOVES APPEARS HERE]
<PAGE>
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, 1994, to December 31, 1995, quarterly high and low sales prices and
the aggregate amount of monthly distributions per Unit paid each quarter were as
follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
1995 High Low Distribution
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
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
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1994 High Low Distribution
- --------------------------------------------------------------------------------
First Quarter $9.875 $8.125 $.151503
Second Quarter 9.000 8.000 .182759
Third Quarter 8.875 7.375 .081320
Fourth Quarter 7.875 5.875 .070002
Total for 1994 $.485584
- --------------------------------------------------------------------------------
</TABLE>
At December 31, 1995, 46,608,796 Units outstanding were held by 2,906 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 2,286 4,170,017
Fiduciaries 537 995,603
Institutions 65 1,230,268
Brokers, Dealers and Nominees 10 38,679,138
Corporations and Partnerships 7 1,533,700
Miscellaneous 1 70
Total 2,906 46,608,796
- --------------------------------------------------------------------------------
</TABLE>
2
<PAGE>
TO UNIT HOLDERS
We are pleased to present the 1995 Annual Report of the San Juan Basin
Royalty Trust. The report includes a copy of the Trust's Annual Report on Form
10-K to the Securities and Exchange Commission for the year ended December 31,
1995, 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.
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 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.
Effective January 1, 1996, Southland Royalty, a wholly-owned subsidiary of
Meridian Oil Inc. ("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. Production figures provided in this letter and in the Trustee's
Discussion and Analysis are based on information provided by Southland Royalty
and MOI.
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 1995 was $13,790,101 or
$.295867 per Unit. This distributable income consisted of Royalty Income of
$15,156,292 plus interest income of $31,978, less administrative expenses of
$1,398,169.
In September 1988, the Trust was advised by Southland Royalty and its
affiliate 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 June 5, 1995, the Trustee announced that non-binding mediation, which had
been ongoing with regard to the lawsuit filed against Southland Royalty and MOI
in the state district court in Santa Fe County, New Mexico, was not successful
in resolving the claims asserted by the Trust. Trial has been set for July 15,
1996.
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, 1996, and for the year ending December 31, 1996. 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.
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, 1995, the production index for the San Juan Basin properties is estimated to
be approximately 10.2 years.
During 1988, a drilling program was initiated involving development of
Fruitland Coal Seam gas reserves. Wells drilled in the Fruitland Coal Seam range
in depth from 2,500 to 3,500 feet on 320-acre spacing.
The process of removing coal seam gas is often referred to as degasification
or desorption. Millions of years ago, natural gas was generated in the process
of coal formation and adsorbed into the coal. Water later filled the natural
fracture system. When the water is removed from the natural fracture system,
reservoir pressure is lowered and the gas desorbs from the coal. The desorbed
gas then flows through the fracture system and is produced at the well bore. The
volume of formation water production typically declines with time and the gas
production may increase for a period of time before starting to decline. In
order to dispose of the formation water, surface facilities including pumping
units are required, which results in the cost of a completed well being as much
as $500,000.
From 1988 through December 31, 1995, Southland Royalty has participated in
the completion of 111 gross (74.46 net) and recompletions of 106 gross (65.80
net) coal seam wells on Trust properties. At December 31, 1995, 145 coal seam
wells had been connected to pipeline facilities. During 1995, these coal seam
wells produced a total of approximately 12,147,483 MMBtu (or 13,485,881 Mcf) of
gas from the Trust properties, which was sold at an average price of $.85 per
MMBtu.
Production from coal seam wells drilled prior to January 1, 1993, qualifies
for Federal income tax credits through 2002. For 1995 the credit was
approximately $1.01 per MMBtu. During 1995, potential Section 29 tax credits of
approximately $.103 per Unit were generated for Trust Unit holders from
production from coal seam wells.
During 1995, Southland Royalty incurred approximately $6,560,276 of capital
expenditures for the drilling and completion of 24 gross (11.41 net)
conventional wells, drilling and completion of 5 gross (2.54 net) coal seam
wells, recompleting 24 gross (11.41 net) coal seam wells, recompleting 38 gross
(8.61 net) conventional wells and other maintenance activities. There were 4
gross (1.89 net) coal seam wells and 7 gross (2.24 net) conventional wells in
progress at December 31, 1995. During 1994, Southland Royalty participated in
the completion of 13 gross (1.96 net) conventional wells, drilling and
completion of 8 gross (4.80 net) conventional wells as coal seam wells,
recompleting 44 gross (12.96 net) conventional wells and maintenance activities
and facilities costs at a cost of $9,409,000.
Due to the size of the coal seam drilling program in the San Juan Basin
during the last several years by various operators, there has been 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 26.6 Bcf for
1992 and to 34.4 Bcf for 1995. MOI has informed the Trustee that mainline
capacity out of the San Juan Basin is approximately 2.93 Bcf per day for El Paso
Natural Gas Pipeline Company and approximately .52 Bcf per day for Transwestern
Pipeline Company.
Based on existing geological and pricing information, there are
approximately 25 net conventional gas wells remaining to be drilled on the Trust
properties. Proved undeveloped reserves have been assigned to these wells. MOI
has advised the Trust that its 1996 capital projections for Trust working
interests are estimated to be in the range of the amount spent in 1995.
Fruitland Coal is estimated to be approximately 15% of the total and the
remainder would be conventional projects. 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 MOI may deem appropriate. Gas production from the Trust
properties is sold in both interstate and intrastate commerce under the Natural
Gas Policy Act of 1978 ("NGPA"). For a further discussion of gas pricing, gas
purchasers, gas production and regulatory matters affecting gas production see
"Item 2. Properties," in the accompanying Form 10-K.
4
<PAGE>
[PICTURE OF PICK AX APPEARS HERE]
<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, 1995,
distributable income was $13,790,101, which was less than the $22,632,493
distributed in 1994. The net decrease was primarily attributable to
significantly lower gas prices. Interest income decreased from $38,129 in 1994
to $31,978 in 1995 primarily due to decreased funds available for investment.
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 litigation settlement proceeds (see Note 6 to
accompanying Financial Statements), are summarized in the following table:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Gas - Mcf 13,331,758 15,459,542 23,895,506 13,984,645 6,892,757
Average Price (per Mcf) $1.25 $1.66 $1.70 $1.57 $1.66
Oil - Bbls 29,424 36,769 51,921 41,087 21,878
Average Price (per Bbl) $14.43 $13.09 $15.58 $17.65 $20.50
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The average gas price declined in 1992 primarily as a result of lower spot
market prices in the second and third quarters of 1992. Due to the increase in
the average price of gas in the first quarter of 1993, the average price for the
year increased. Gas and oil prices declined in 1994. Gas prices plummeted in the
San Juan Basin in 1995 due to a surplus of gas supplies. 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, 1995, were as follows:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Gas - Mcf 34,387,190 34,222,189 40,736,391 26,642,265 20,390,665
Mcf per day 94,211 93,759 111,607 72,993 55,865
Oil - Bbls 75,014 84,648 88,466 79,600 74,005
Bbls per day 206 232 242 218 203
- ------------------------------------------------------------------------------------------------------------------------------------
</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 third and fourth quarters of 1993. Production from the 30-6 Unit
was more normalized in 1994 and 1995.
6
<PAGE>
Royalty Income for the five years ended December 31,
1995, was determined as shown in the following table:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Gross Proceeds from the
Southland Royalty Properties
from which the Trust's Overriding
Royalty was carved:
Gas $41,483,305 $54,357,586 $69,266,623 $41,961,599 $29,399,897
Oil 1,084,262 1,140,738 1,384,468 1,409,179 1,453,798
Other 2,592 -0- -0- -0- -0-
Litigation Settlement -0- -0- -0- 16,118,174 14,726,971
----------- ----------- ----------- ----------- -----------
Total 42,570,159 55,498,324 70,651,091 59,488,952 45,580,666
----------- ----------- ----------- ----------- -----------
Less Production Costs:
Capital Costs 6,560,277 9,409,462 3,988,136 2,530,833 3,164,737
Severance Tax - Gas 4,694,750 5,864,834 6,543,615 3,696,172 2,569,476
Severance Tax - Oil 115,474 117,028 153,072 155,663 164,280
Severance Tax - Other 117 -0- -0- -0- -0-
Severance Tax - Litigation -0- -0- -0- 356,944 370,522
Lease Operating Expenses 10,991,152 9,066,750 9,864,773 9,423,403 10,459,171
----------- ----------- ----------- ----------- -----------
Total 22,361,770 24,458,074 20,549,596 16,163,015 16,728,186
----------- ----------- ----------- ----------- -----------
Net Profits 20,208,389 31,040,250 50,101,495 43,325,937 28,852,480
Royalty Percentage 75% 75% 75% 75% 75%
Royalty Income $15,156,292 $23,280,188 $37,576,121 $32,494,453 $21,639,360
=========== =========== =========== =========== ===========
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The capital costs incurred by Southland Royalty on the properties from which
the Royalty was carved for the year ended December 31, 1995, amounted to
$6,560,277 versus $9,409,462 for 1994. The decrease was primarily attributable
to fewer recompletions. The litigation settlement and the related severance
taxes pertain to The Public Service Company of New Mexico litigation which was
settled during 1990. (See Note 6 to accompanying Financial Statements.) Monthly
operating costs in 1995 averaged approximately $876,000, which is higher than
the $755,000 average in 1994 due to a variety of factors that included braden
head repairs, recompletions and numerous wells that were shut-in during 1994 and
began flowing in 1995. Non-operated lease operating expense is subject to
significant fluctuations due to invoice timing issues. There are a large number
of non-operated properties that are burdened by the Trust.
7
<PAGE>
RESULTS OF THE 4TH QUARTERS OF 1995 AND 1994
Distributable income for the quarter ended December 31, 1995, totaled
$1,182,038 ($.025361 per Unit) as compared to $3,262,714 ($.070002 per Unit) for
the quarter ended December 31, 1994. The amount distributed in the fourth
quarter of 1995 was lower than that of 1994 primarily because of the lower
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, 1995 and 1994 were as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
1995 1994
- --------------------------------------------------------------------------------
<S> <C> <C>
Properties From Which the Royalty Was Carved
Gas - Mcf 8,929,852 8,490,235
Average Price (per Mcf) $.98 $1.27
Oil - Bbls 17,681 20,230
Average Price (per Bbl) $14.72 $14.46
Attributable to the Royalty
Gas - Mcf 1,864,559 2,811,893
Oil - Bbls 3,663 6,543
- --------------------------------------------------------------------------------
</TABLE>
[PICTURE OF MAP SHOWING THE SAN JUAN BASIN AREA, LEASEHOLD ACREAGE, MINERAL
ACERAGE, GAS FIELDS AND OIL FIELDS OF THE TRUST APPEARS HERE]
The average price of gas decreased in the fourth quarter of 1995 primarily
due to decreases in prices paid by Meridian Oil Trading, Inc. ("MOTI"), a
subsidiary of MOI that markets a substantial portion of the Trust's gas. 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 demand
from gas purchasers. During the fourth quarter of 1995, coal seam production
from the properties from which the Royalty was carved averaged 1,173,000 Mcf per
month compared to 1,213,000 Mcf per month during the fourth quarter of 1994.
Capital costs for the fourth quarter of 1995 totaled $2,413,744 compared to
$3,242,330 during the same period of 1994. The decrease was due to decreased
drilling activity. Lease operating costs for the fourth quarter of 1995 averaged
$1,025,000 per month compared to $721,000 per month in the fourth quarter of
1994. The increase relates to various recompletions, valve repairs and
compressor rental expense. Non-operated properties are subject to invoice timing
issues.
8
<PAGE>
[PICTURE OF PIPE WRENCH APPEARS HERE]
<PAGE>
SAN JUAN BASIN ROYALTY TRUST
Statements of Assets, Liabilities and Trust Corpus
December 31, 1995 and 1994
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1995 1994
- -------------------------------------------------------------------------------
<S> <C> <C>
Assets
Cash and Short-term Investments $ 421,446 $ 589,365
Net Overriding Royalty Interest in
Producing Oil and
Gas Properties - Net (Notes 2 and 3) 70,133,536 74,942,040
----------- -----------
$70,554,982 $75,531,405
=========== ===========
Liabilities and Trust Corpus
Distribution Payable to Unit Holders $ 421,446 $ 589,365
Contingencies (Note 5) -- --
Trust Corpus - 46,608,796 Units of
Beneficial Interest
Authorized and Outstanding 70,133,536 74,942,040
----------- -----------
$70,554,982 $75,531,405
=========== ===========
- -------------------------------------------------------------------------------
</TABLE>
Statements of Distributable Income
for the Three Years Ended December 31, 1995
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1995 1994 1993
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Royalty Income (Notes 2, 3 and 6) $15,156,292 $23,280,188 $37,576,121
Interest Income 31,978 38,129 45,491
----------- ----------- -----------
15,188,270 23,318,317 37,621,612
Expenditures - General and
Administrative 1,398,169 685,824 860,815
----------- ----------- -----------
Distributable Income $13,790,101 $22,632,493 $36,760,797
----------- ----------- -----------
Distributable Income per Unit
(46,608,796 units) $ .295867 $ .485584 $ .788710
=========== =========== ===========
- -------------------------------------------------------------------------------
</TABLE>
Statements of Changes in Trust Corpus for the
Three Years Ended December 31, 1995
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
1995 1994 1993
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Trust Corpus, Beginning of Period $74,942,040 $79,898,032 $88,215,333
Amortization of Net Overriding
Royalty Interest (Notes 2 and 3) (4,808,504) (4,955,992) (8,317,301)
Distributable Income 13,790,101 22,632,493 36,760,797
Distributions Declared (13,790,101) (22,632,493) (36,760,797)
----------- ----------- -----------
Trust Corpus, End of Period $70,133,536 $74,942,040 $79,898,032
=========== =========== ===========
- -------------------------------------------------------------------------------
</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%.
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, 1995 and 1994 aggregated $63,141,992
and $58,333,488, 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
11
<PAGE>
accrued in financial statements prepared in accordance with GAAP. Amortization
of the Royalty calculated on a unit-of-production basis is charged directly to
trust corpus.
4. Federal Income Taxes
For Federal income tax purposes, the Trust constitutes a fixed investment trust
which is taxed as a grantor trust. A grantor trust is not subject to tax at the
trust level. The Unit holders are considered to own the Trust's income and
principal as though no trust were in existence. The income of the Trust is
deemed to have been received or accrued by each Unit holder at the time such
income is received or accrued by the Trust rather than when distributed by the
Trust.
The Royalty constitutes an "economic interest" in oil and gas properties for
Federal income tax purposes. Unit holders must report their share of the
revenues of the Trust as ordinary income from oil and gas royalties, and are
entitled to claim depletion with respect to such income. The Royalty is treated
as a single property for depletion purposes.
The Trust has on file technical advice memoranda confirming the tax
treatment described above.
The Trust began receiving royalty income from coal seam wells beginning in
1989. Under Section 29 of the Internal Revenue Code, production from coal seam
gas wells drilled prior to January 1, 1993, qualifies for the Federal income tax
credit for producing non-conventional fuels. This tax credit was approximately
$1.02 per MMBtu for the year 1995 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 Meridian Oil Inc. ("MOI")
and Southland in the state district court in Rio Arriba County, New Mexico,
Cause No. RA 92-1211(C). 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"). MOI and Southland
are the operators of the Trust Properties.
The claims asserted on behalf of the Trust in the Santa Fe County, New
Mexico, lawsuit now include 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 includes 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. The lawsuit seeks declaratory relief that: (i) the rights and
duties of the Trustee be governed in accordance with and by the terms and
provisions of the Trust instruments which establish the Trust as well as the
Texas Trust Code, (ii) the Trustee cannot object to Southland's reports or
audits after 180 days, (iii) the interests held by the Trust are not subject to
partition, and (iv) the Trust is without standing to remove Southland as
operator of the Trust Properties. The lawsuit also seeks to remove Bank One,
Texas, NA, as Trustee.
Southland has filed a counter-claim in the Santa Fe County
12
<PAGE>
[PICTURE OF DRILL BIT APPEARS HERE]
<PAGE>
lawsuit seeking declaratory relief as follows:
A. That Southland's policy and practice of remitting payments to the Trustee
for the net overriding royalty interest ("NORI") based on the proceeds actually
received by Southland at prevailing prices in the area of production constitutes
good faith compliance with its duties and obligations under the net overriding
royalty conveyance filed of record in San Juan County, New Mexico, on November
21, 1980 ("Conveyance");
B. That the revenue or profits realized by MOTI and Meridian Oil
Hydrocarbons Inc. ("MOHI") on subsequent downstream resale or treatment of the
gas is immaterial to the calculation and payment of the NORI;
C. That Meridian Oil Gathering Inc. ("MOGI") is not compelled or required to
grant the Trustee a discounted fee or rate (different and less than that charged
by MOGI to the owners of other interests) for gathering and processing services
provided by MOGI;
D. That the Trustee has no power or authority under the Conveyance or the
San Juan Basin Royalty Trust Indenture dated November 3, 1980 ("Indenture") to
take exception to the quarterly and annual reports and audits by Southland
relating to the NORI that were not timely excepted to in writing by the Trustee
as required by Section 2.04 of the Conveyance, and that the reports and audits
are deemed to be correct as rendered;
E. That Southland is entitled to its costs, attorneys' fees and for such
other relief as the Court deems just and proper.
On June 5, 1995, the Trustee announced that 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. Trial is
currently set in the Santa Fe County, New Mexico, lawsuit for July 15, 1996.
A resolution of the Santa Fe County, New Mexico, lawsuit favorable to the
Trust could possibly have a material effect on distributable income depending on
the nature and terms of the resolution.
6. Litigation Settlement Distribution
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 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
14
<PAGE>
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 has 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 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 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 has further advised the Trust that on September 13, 1994, MOTI,
one of the first purchasers of MOI producing affiliates' gas, entered into a gas
sales agreement with Gas Company for the next five winter periods beginning
November 1, 1995, and ending March 31, 2000. MOTI will be purchasing the gas
supplied for this sale from MOI producing affiliates and other third party
sellers. Sales will be based on a monthly published index. Valid delivery points
under the agreement will be the tailgate of the Lybrook Plant, the tailgate of
the Kutz Plant, the Blanco Hub, or Rio Puerco.
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, 1995 (in thousands, except unit
amounts):
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Distributable
Income and
Royalty Distributable Distribution
1995 Income Income Per Unit
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
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
======= ======= ========
1994
- --------------------------------------------------------------------------------
First Quarter $ 7,232 $ 7,061 $.151503
Second Quarter 8,762 8,518 .182759
Third Quarter 3,924 3,790 .081320
Fourth Quarter 3,362 3,263 .070002
------- ------- --------
Total $23,280 $22,632 $.485584
======= ======= ========
- --------------------------------------------------------------------------------
</TABLE>
15
<PAGE>
INDEPENDENT AUDITORS' 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, 1995 and
1994, and the related statements of distributable income and changes in trust
corpus for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994 and the distributable income and changes
in trust corpus for each of the three years in the period ended December 31,
1995 on the basis of accounting described in Note 3.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Fort Worth, Texas
April 11, 1996
- --------------------------------------------------------------------------------
San Juan Basin Royalty Trust Legal Counsel
Bank One, Texas, NA, Trustee Shannon, Gracey, Ratliff & Miller, L.L.P.
Post Office Box 2604 Fort Worth, Texas
Fort Worth, Texas 76113
Tax Counsel
Auditors Butler & Binion, L.L.P.
Deloitte & Touche LLP Houston, Texas
Fort Worth, Texas
Transfer Agent
Harris Trust & Savings Bank
Chicago, Illinois
Design: Witherspoon & Associates
Photography: Studio 44 Photography
Oil field supplies courtesy of East Texas Oil Museum,
Kilgore College, Kilgore, Texas
16
<PAGE>
[LETTERHEAD OF CAWLEY, GILLESPIE & ASSOCIATES, INC.]
April 13, 1996
San Juan Basin Royalty Trust
P.O. Box 2604
Fort Worth, Texas 76113
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, 1995 and in the
San Juan Basin Royalty Trust Annual Report for the year ended December 31,
1995, based on reserve reports dated April 12, 1996 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, 1995, AND THE RELATED CONDENSED
STATEMENTS OF DISTRIBUTABLE INCOME AND CHANGES IN TRUST CORPUS FOR THE TWELVE
MONTH PERIOD ENDED DECEMBER 31, 1995.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 421,446
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 421,446
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0
0
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</TABLE>
