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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-8033
PERMIAN BASIN ROYALTY TRUST
(Exact Name of Registrant as Specified in the Permian Basin Royalty Trust
Indenture)
TEXAS 75-6280532
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
BANK OF AMERICA, N.A.
TRUST DEPARTMENT
P.O. BOX 830650
DALLAS, TEXAS 75283
(Address of Principal Executive Offices) (Zip Code)
(214) 209-2400
(Registrant's Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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UNITS OF BENEFICIAL INTEREST NEW YORK STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act:
NONE
(Title of Class)
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
At March 10, 2000, there were 46,608,796 Units of Beneficial Interest of
the Trust outstanding with an aggregate market value on that date of
$221,391,781.
DOCUMENTS INCORPORATED BY REFERENCE
"Units of Beneficial Interest" at page 1; "Trustee's Discussion and
Analysis for the Three-Year Period Ended December 31, 1999" at pages 5 through
6; "Results of the 4th Quarters of 1999 and 1998" at page 7; 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 8 et seq., in registrant's Annual Report
to security holders for fiscal year ended December 31, 1999 are incorporated
herein by reference for 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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FORWARD LOOKING INFORMATION
Certain information included in this report contains, and other materials
filed or to be filed by the Trust with the Securities and Exchange Commission
(as well as information included in oral statements or other written statements
made or to be made by the Trust) may contain or include, forward looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended, and Section 27A of the Securities Act of 1933, as amended.
Such forward looking statements may be or may concern, among other things,
capital expenditures, drilling activity, development activities, production
efforts and volumes, hydrocarbon prices and the results thereof, and regulatory
matters. Although the Trustee believes that the expectations reflected in such
forward looking statements are reasonable, such expectations are subject to
numerous risks and uncertainties and the Trustee can give no assurance that they
will prove correct. There are many factors, none of which is within the
Trustee's control, that may cause such expectations not to be realized,
including, among other things, factors such as actual oil and gas prices and the
recoverability of reserves, capital expenditures, general economic conditions,
actions and policies of petroleum-producing nations and other changes in the
domestic and international energy markets. Such forward looking statements
generally are accompanied by words such as "estimate," "expect," "anticipate,"
"goal," "should," "assume," "believe," or other words that convey the
uncertainty of future events or outcomes.
PART I
ITEM 1. BUSINESS
The Permian Basin Royalty Trust (the "Trust") is an express trust created
under the laws of the state of Texas by the "Permian Basin Royalty Trust
Indenture" (the "Trust Indenture") entered into on November 3, 1980, between
Southland Royalty Company ("Southland Royalty") and The First National Bank of
Fort Worth, as Trustee. Bank of America, N.A. (formerly known as NationsBank,
N.A., NationsBank of Texas, N.A. and NCNB Texas National Bank), a banking
association organized under the laws of the United States, as the successor of
The First National Bank of Fort Worth, is now the Trustee of the Trust. The
principal office of the Trust (sometimes referred to herein as the "Registrant")
is located at 901 Main Street, Dallas, Texas (telephone number 214/209-2400).
On October 23, 1980, the stockholders of Southland Royalty approved and
authorized that company's conveyance of net overriding royalty interests
(equivalent to net profits interests) 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 fee mineral interests in the Waddell Ranch properties in Crane
County, Texas and a 95% net overriding royalty interest carved out of that
company's major producing royalty properties in Texas. The conveyance of these
interests (the "Royalties") 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
Royalties, 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 Royalties were carved out of and now burden those properties and
interests as are more particularly described under "Item 2. PROPERTIES" herein.
The Royalties constitute the principal asset of the Trust and the
beneficial interests in the Royalties 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,
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El Paso Natural Gas Company ("El Paso") also became an indirect subsidiary 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
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. In 1996, MOI changed its name to Burlington Resources Oil & Gas Company
("BROG").
The term "net proceeds" as used in the above conveyance means the excess of
"gross proceeds" received by BROG during a particular period over "production
costs" for such period. "Gross proceeds" means the amount received by BROG (or
any subsequent owner of the interests from which the Royalties were carved) from
the sale of the production attributable to the properties and interests from
which the Royalties were carved, subject to certain adjustments. "Production
costs" means, generally, costs incurred on an accrual basis in operating the
properties and interests out of which the Royalties were 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 liabilities attributable to these
properties and interests or the minerals produced therefrom. If at any time the
Trust receives more than the amount due from the Royalties, 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.
To the extent it has the legal right to do so, BROG is responsible 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. BROG
also has the obligation to maintain books and records sufficient to determine
the amounts payable to the Trustee. BROG, however, can sell its interests in the
properties from which the Royalties were carved.
Proceeds from production in the first month are generally received by BROG
in the second month, the net proceeds attributable to the Royalties are paid by
BROG to the Trustee in the third month and distribution by the Trustee to the
Unit holders is made in the fourth month. The identity of Unit holders entitled
to a distribution will generally be determined as of the last business day of
each calendar month (the "monthly record date"). The amount of each monthly
distribution will generally be determined and announced ten days before the
monthly record date. Unit holders of record as of the monthly record date will
be entitled to receive the calculated monthly distribution amount for each month
on or before ten business days after the monthly record date. The aggregate
monthly distribution amount is the excess of (i) net revenues from the Trust
properties, plus any decrease in cash reserves previously established for
contingent liabilities and any other cash receipts of the Trust over (ii) the
expenses and payments of liabilities of the Trust plus any net increase in cash
reserves for contingent liabilities.
Cash 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, at 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 income to the Trust attributable to the Royalties is not subject in
material respects to seasonal factors nor in any manner related to or dependent
upon patents, licenses, franchises or concessions. The Trust conducts no
research activities. The Trust has no employees since all administrative
functions are performed by the Trustee.
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BROG has advised the Trustee that it believes that comparable revenues
could be obtained in the event of a change in purchasers of production.
ITEM 2. PROPERTIES
The net overriding royalties conveyed to the Trust include: (1) a 75% net
overriding royalty carved out of Southland Royalty's fee mineral interests in
the Waddell Ranch in Crane County, Texas (the "Waddell Ranch properties"); and
(2) a 95% net overriding royalty carved out of Southland Royalty's major
producing royalty interests in Texas (the "Texas Royalty properties"). The net
overriding royalty for the Texas Royalty properties is subject to the provisions
of the lease agreements under which such royalties were created. References
below to "net" wells and acres are to the interests of Southland Royalty (from
which the Royalties were carved) in the "gross" wells and acres.
The following information in Item 2 is based upon data and information
furnished to the Trustee by Southland Royalty or BROG.
PRODUCING ACREAGE, WELLS AND DRILLING
Waddell Ranch Properties. The Waddell Ranch properties consist of 78,175
gross (34,205 net) producing acres. A majority of the proved reserves are
attributable to six fields: Dune, Sand Hills (Judkins), Sand Hills (McKnight),
Sand Hills (Tubb), University-Waddell (Devonian) and Waddell. At December 31,
1999, the Waddell Ranch properties contained 791 gross (327 net) productive oil
wells, 168 gross (70 net) productive gas wells and 350 gross (139 net) injection
wells.
BROG is operator of record of the Waddell Ranch properties. All field,
technical and accounting operations have been contracted by an agreement between
the working interest owners and Coastal Management Corporation ("CMC") but
remain under the direction of BROG.
The Waddell Ranch properties are mature producing properties, and all of
the major oil fields are currently being waterflooded. Proved reserves and
estimated future net revenues attributable to the properties are included in the
reserve reports summarized below. BROG does not own the full working interest in
any of the tracts constituting the Waddell Ranch properties and, therefore,
implementation of any development programs will require approvals of other
working interest holders as well as BROG. In addition, implementation of any
development programs will be dependent upon oil and gas prices currently being
received and anticipated to be received in the future. During 1999 there were 6
gross (2.625 net) wells drilled on the Waddell Ranch properties. At December 31,
1999 there were 3 gross (1.375 net) wells in progress on the Waddell Ranch
properties. During 1998 there were 52 gross (22.75 net) wells drilled on the
Waddell Ranch properties. At December 31, 1998 there were 3 gross (1.375 net)
wells in progress on the Waddell Ranch properties. During 1997 there were 23
gross (9.25 net) wells drilled on the Waddell Ranch properties. At December 31,
1997 there were 19 gross (7.875 net) wells in progress on the Waddell Ranch
properties.
BROG has advised the Trustee that the total amount of capital expenditures
for 1999 with regard to the Waddell Ranch properties totalled $1,052,769.
Capital expenditures include the cost of remedial and maintenance activities.
This amount spent is approximately $5,013,231 less than the budgeted amount
projected by BROG for 1999. BROG has advised the Trustee that the capital
expenditures budget for 2000 totals approximately $14,404,000, of which
approximately $5,076,000 is attributable to the 2000 drilling program, and
$9,364,000 to workovers and recompletions. Accordingly, there is a substantial
increase in capital expenditures for 2000 as compared with the 1999 capital
expenditures.
Texas Royalty Properties. The Texas Royalty properties consist of royalty
interests in mature producing oil fields, such as Yates, Wasson, Sand Hills,
East Texas, Kelly-Snyder, Panhandle Regular, N. Cowden, Todd, Keystone, Kermit,
McElroy, Howard-Glasscock, Seminole and others. The Texas Royalty properties
contain approximately 303,000 gross (approximately 51,000 net) producing acres.
Detailed information concerning the number of wells on royalty properties is not
generally available to the owners of royalty interests. Consequently, an
accurate count of the number of wells located on the Texas Royalty properties
cannot readily be obtained.
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In February 1997, BROG sold its interests in the Texas Royalty properties
that are subject to the Net Overriding Royalty Conveyance to the Trust dated
effective November 1, 1980 ("Texas Royalty Conveyance") to Riverhill Energy
Corporation ("Riverhill Energy"), which was then a wholly-owned subsidiary of
Riverhill Capital Corporation ("Riverhill Capital") and an affiliate of CMC. At
the time of such sale, Riverhill Capital was a privately owned Texas corporation
with offices in Bryan and Midland, Texas. The Trustee was informed by BROG that,
as required by the Texas Royalty Conveyance, Riverhill Energy succeeded to all
of the requirements upon and the responsibilities of BROG under the Texas
Royalty Conveyance with regard to the Texas Royalty properties. BROG and
Riverhill Energy further advised the Trustee that all accounting operations
pertaining to the Texas Royalty properties were being performed by CMC under the
direction of Riverhill Energy. BROG indicated to the Trustee that BROG will work
together with CMC and Riverhill Energy in an effort to assure that various
administrative functions and reporting requirements assumed by Riverhill Energy
are met. The Trustee has been advised that independent auditors representing
Riverhill Energy and CMC are Arthur Andersen LLP.
The Trustee has been advised that in the first quarter of 1998 Schlumberger
Technology Corporation ("Schlumberger"), acquired all of the shares of stock of
Riverhill Capital. Prior to such acquisition by Schlumberger, CMC and Riverhill
Energy were wholly-owned subsidiaries of Riverhill Capital. The Trustee has
further been advised that in connection with Schlumberger's acquisition of
Riverhill Capital, the shareholders of Riverhill Capital acquired ownership of
all of the shares of stock of Riverhill Energy. Thus, the ownership in the Texas
Royalty properties referenced above remained in Riverhill Energy, the stock
ownership of which was acquired by the former shareholders of Riverhill Capital.
Accounting operations pertaining to the Texas Royalty properties are being
performed by CMC under the direction of Riverhill Energy. CMC also currently
conducts all field, technical and accounting operations on behalf of BROG with
regard to the Waddell Ranch properties.
OIL AND GAS PRODUCTION
The Trust recognizes production during the month in which the related
distribution is received. Production of oil and gas attributable to the
Royalties and the properties from which the Royalties were carved and the
related average sales prices attributable to the properties from which the
Royalties were carved for the three years ended December 31, 1999, excluding
portions attributable to the adjustments discussed below, were as follows:
WADDELL TEXAS
RANCH ROYALTY
PROPERTIES PROPERTIES TOTAL
--------------------------------- --------------------------- ---------------------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
--------- --------- --------- ------- ------- ------- --------- --------- ---------
ROYALTIES:
Production
Oil (barrels)........... 601,148 87,187 426,127 308,204 369,823 391,665 909,352 457,010 817,792
Gas (Mcf)............... 2,754,393 666,864 1,875,965 709,815 766,085 840,790 3,464,208 1,432,949 2,716,755
PROPERTIES FROM WHICH THE
ROYALTIES WERE CARVED:
Production
Oil (barrels)........... 1,309,396 1,475,258 1,387,056 365,502 434,444 438,963 1,674,898 1,909,702 1,826,019
Gas (Mcf)............... 6,066,149 6,458,411 6,409,242 841,018 915,025 945,920 6,907,167 7,373,436 7,355,162
Average Price
Oil/barrel.............. $14.26 $12.76 $19.54 $14.40 $12.44 $19.20 $14.29 $12.69 $19.46
Gas/Mcf................. $ 2.11 $ 2.13 $ 2.67 $ 2.09 $ 2.06 $ 2.45 $ 2.11 $ 2.12 $ 2.64
Since the oil and gas sales attributable to the Royalties are based on an
allocation formula that is dependent on such factors as price and cost
(including capital expenditures), the production amounts do not provide a
meaningful comparison.
In calculating Trust royalty income for the months of June through December
1998, costs exceeded revenues in the Waddell Ranch properties by $1,218,732.
Pursuant to the Waddell Ranch Net Overriding Royalty Conveyance dated effective
November 1, 1980 ("Waddell Ranch Conveyance"), excess costs plus accrued
interest must be recovered from future net proceeds relating to the underlying
Waddell Ranch
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properties before the properties can again contribute to Trust royalty income.
As a result of this, no royalty income was received for those months. Production
attributable to the Trust is calculated based on net royalty income. As there
was no royalty income, no production was reported for the Waddell Ranch
properties at the Trust level for those months. Production at the Trust level
for the Waddell Ranch properties was not recorded again until February 1999 when
the cumulative excess amounts had been recovered.
In September 1998, the Trust received $1,041,340 from BROG which
represented the Trust's portion of amounts that had been previously held in
suspense by BROG relating to the Texas Royalty properties. The Trustee was
advised that these amounts relate to revenues received by BROG prior to the
conveyance of its interest in the Texas Royalty properties to Riverhill Energy
in February 1997. In October 1998, Riverhill Energy advised the Trustee that an
overpayment of $521,183 with regard to the suspended funds had been made to the
Trust. Pursuant to the Texas Royalty Conveyance, Riverhill Energy offset the
overpayment against royalty income attributable to the Texas Royalty properties
for the months of October and November 1998. The suspense amounts are not
reflected in Trust production or used in calculating average prices in 1998 or
prior years.
The Trustee was notified in the third quarter of 1996 of the settlement of
a class action lawsuit pending in the 270th District Court of Harris County,
Texas (the "Court") styled Caroline Altheide and Langdon Harrison vs. Meridian
Oil Inc., Meridian Oil Holding Inc., Meridian Oil Trading Inc., Meridian Oil
Production Inc., Southland Royalty Company, El Paso Production Company, Meridian
Oil Hydrocarbons Inc., Meridian Oil Gathering Inc., Meridian Oil Services Inc.
and Edward Parker ("Class Action"), in which the Trust was a class member. The
judgment approving the settlement of the Class Action was the subject of an
appeal. The Trustee was advised that such appeal was dismissed and in October
1998, the Trust's portion of such settlement proceeds, in the amount of $766,051
was received by the Trustee. The proceeds were subsequently distributed with the
regular monthly Trust distribution on November 16, 1998, to the Trust's Unit
holders of record on October 31, 1998. The settlement proceeds are not reflected
in Trust production in 1998 or prior years.
PRICING INFORMATION
Reference is made to "Regulation" for information as to federal regulation
of prices of natural gas. The following paragraphs provide information regarding
sales of oil and gas from the Waddell Ranch properties. As a royalty owner,
Southland Royalty is not furnished detailed information regarding sales of oil
and gas from the Texas Royalty properties.
Oil. The Trustee has been advised by BROG that for the period August 1,
1993 through June 30, 2000, the oil from the Waddell Ranch properties is being
sold under a competitive bid to independent third parties.
Gas. The gas produced from the Waddell Ranch properties is processed
through a natural gas processing plant and sold at the tailgate of the plant.
Plant products are marketed by Burlington Resources Hydrocarbons Inc., an
indirect subsidiary of BRI. The processor of the gas (Warren Petroleum Company,
L.P.) receives 15% of the liquids and residue gas as a fee for gathering,
compression, treating and processing the gas.
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.
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"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 factor of 10%.
The independent petroleum engineers' reports as to the proved oil and gas
reserves attributable to the Royalties conveyed to the Trust were obtained from
Cawley, Gillespie & Associates, Inc. The following table presents a
reconciliation of proved reserve quantities from December 31, 1996 through
December 31, 1999 (in thousands):
WADDELL RANCH TEXAS ROYALTY
PROPERTIES PROPERTIES TOTAL
------------------ ----------------- -------------------
OIL GAS OIL GAS OIL GAS
(BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF)
------- -------- ------- ------- -------- --------
December 31, 1996.................................... 7,303 34,511 4,672 4,790 11,975 39,301
Extensions, discoveries and other additions.......... 48 52 -0- -0- 48 52
Revisions of previous estimates...................... (1,902) (8,512) 161 680 (1,741) (7,832)
Production........................................... (426) (1,876) (392) (841) (818) (2,717)
------ ------ ----- ----- ------ ------
December 31, 1997.................................... 5,023 24,175 4,441 4,629 9,464 28,804
Extensions, discoveries and other additions.......... 10 4 -0- -0- 10 4
Revisions of previous estimates...................... (2,231) (6,123) (285) 100 (2,516) (6,023)
Production........................................... (87) (667) (370) (766) (457) (1,433)
------ ------ ----- ----- ------ ------
December 31, 1998.................................... 2,715 17,389 3,786 3,963 6,501 21,352
Extensions, discoveries and other additions.......... 15 49 -0- -0- 15 49
Revisions of previous estimates...................... 3,357 8,320 667 2,375 4,024 10,695
Production........................................... (601) (2,754) (308) (710) (909) (3,464)
------ ------ ----- ----- ------ ------
December 31, 1999.................................... 5,486 23,004 4,145 5,628 9,631 28,632
====== ====== ===== ===== ====== ======
Estimated quantities of proved developed reserves of crude oil and natural
gas as of December 31, 1999, 1998 and 1997 were as follows (in thousands):
CRUDE OIL NATURAL GAS
(BBLS) (MCF)
--------- -----------
1999........................................................ 8,200 24,248
1998........................................................ 5,476 17,444
1997........................................................ 8,116 23,054
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 computed 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 cash flows relating to proved oil
and gas reserves.
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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.
The 1999, 1998, and 1997 change in the standardized measure of discounted
future net cash flows related to future royalty income from proved reserves
discounted at 10% is as follows (in thousands):
WADDELL RANCH PROPERTIES TEXAS ROYALTY PROPERTIES TOTAL
------------------------------ --------------------------- ------------------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
-------- -------- -------- ------- ------- ------- -------- -------- --------
January 1....................... $ 25,043 $ 63,179 $150,170 $22,031 $40,956 $52,457 $ 47,074 $104,135 $202,627
Extensions, discoveries and
other additions............... 226 81 619 -0- -0- -0- 226 81 619
Accretion of discount........... 2,504 6,318 15,017 2,203 4,096 5,246 4,707 10,414 20,263
Revisions of prior year
estimates, changes in price
and other..................... 88,598 (39,982) (89,235) 33,627 (16,796) (7,540) 122,225 (56,778) (96,775)
Royalty income.................. (14,283) (4,553) (13,392) (5,735) (6,225) (9,207) (20,018) (10,778) (22,599)
-------- -------- -------- ------- ------- ------- -------- -------- --------
December 31..................... $102,088 $ 25,043 $ 63,179 $52,126 $22,031 $40,956 $154,214 $ 47,074 $104,135
======== ======== ======== ======= ======= ======= ======== ======== ========
Oil and gas prices of $24.05 and $24.19 per barrel and $2.74 and $3.18 per
Mcf were used to determine the estimated future net revenues from the Waddell
Ranch properties and the Texas Royalty properties, respectively, at December 31,
1999. The extension, discoveries and other additions for the Waddell Ranch
properties are proved reserves related to the Waddell (Greyburg) and Running WN
(Wolfcamp) fields. The upward revisions of both reserves and discounted future
net cash flows for the Waddell Ranch properties and the Texas Royalty properties
are due to increases in the oil and gas prices from 1998 to 1999.
Oil and gas prices of $8.56 and $9.96 per barrel and $1.74 and $1.88 per
Mcf were used to determine the estimated future net revenues from the Waddell
Ranch properties and the Texas Royalty properties, respectively, at December 31,
1998. The extension, discoveries and other additions for the Waddell Ranch
properties are proved developed producing reserves related to the RM (Clearfork)
field. The downward revisions of both reserves and discounted future net cash
flows for the Waddell Ranch properties and the Texas Royalty properties were due
to decreases in oil and gas prices from 1997 to 1998.
Oil and gas prices of $15.79 and $16.75 per barrel and $2.28 and $3.14 per
Mcf were used to determine the estimated future net revenues from the Waddell
Ranch properties and the Texas Royalty properties at December 31, 1997. The
downward revision of the estimated oil reserves and the related decrease in the
discounted future net cash flow for the Waddell Ranch properties was primarily
due to the decrease in oil prices from 1996 to 1997. The downward revision in
the estimated gas reserves for the Waddell Ranch properties was primarily due to
the decrease in gas prices from 1996 to 1997.
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The following presents estimated future net revenue and the present value
of estimated future net revenue, for each of the years ended December 31, 1999,
1998, and 1997 (in thousands except amounts per Unit):
1999 1998 1997
--------------------- -------------------- ---------------------
ESTIMATED ESTIMATED ESTIMATED
FUTURE PRESENT FUTURE PRESENT FUTURE PRESENT
NET VALUE NET VALUE NET VALUE
REVENUE AT 10% REVENUE AT 10% REVENUE AT 10%
--------- -------- --------- ------- --------- --------
Total Proved
Waddell Ranch properties.................. $184,957 $102,088 $50,322 $25,043 $126,924 $ 63,179
Texas Royalty properties.................. 113,838 52,126 43,290 22,031 85,254 40,956
-------- -------- ------- ------- -------- --------
Total............................... $297,795 $154,214 $93,612 $47,074 $212,178 $104,135
======== ======== ======= ======= ======== ========
Total Proved Per Unit....................... $ 6.41 $ 3.31 $ 2.01 $ 1.01 $ 4.55 $ 2.23
======== ======== ======= ======= ======== ========
Proved Developed
Waddell Ranch properties.................. $140,808 $ 85,612 $35,607 $22,032 $ 94,493 $ 55,150
Texas Royalty properties.................. 113,838 52,126 43,290 22,031 85,254 40,956
-------- -------- ------- ------- -------- --------
Total............................... $254,646 $137,738 $78,896 $44,063 $179,747 $ 96,106
======== ======== ======= ======= ======== ========
Reserve quantities and revenues shown in the preceding tables for the
Royalties were estimated from projections of reserves and revenue attributable
to the combined Southland Royalty and Trust interests in the Waddell Ranch
properties and Texas Royalty properties. Reserve quantities attributable to the
Royalties were estimated by allocating to the Royalties a portion of the total
estimated net reserve quantities of the interests, based upon gross revenue less
production taxes. Because the reserve quantities attributable to the Royalties
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 Royalties. Therefore, the reserve quantities estimated will vary if
different future price and cost assumptions occur.
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 original
estimate. Moreover, the present values shown above should not be considered as
the market values of such oil and gas reserves or the costs that would be
incurred to acquire equivalent reserves. A market value determination would
include many additional factors.
REGULATION
Many aspects of the production, pricing and marketing of crude oil and
natural gas are regulated by federal and state agencies. Legislation affecting
the oil and gas industry is under constant review for amendment or expansion,
frequently increasing the regulatory burden on affected members of the industry.
Exploration and production operations are subject to various types of
regulation at the federal, state and local levels. Such regulation includes
requiring permits for the drilling of wells, maintaining bonding requirements in
order to drill or operate wells, and regulating the location of wells, the
method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled and the plugging and abandonment of
wells. Natural gas and oil operations are also subject to various conservation
laws and regulations that regulate the size of drilling and spacing units or
proration units and the density of wells which may be drilled and unitization or
pooling of oil and gas properties. In addition, state conservation laws
establish maximum allowable production from natural gas and oil wells, generally
prohibit the venting or flaring of natural gas and impose certain requirements
regarding the ratability of production. The effect of these regulations is to
limit the amounts of natural gas and oil that can be produced and to limit the
number of wells or the locations which can be drilled.
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Federal Natural Gas Regulation
The Federal Energy Regulatory Commission (the "FERC") is primarily
responsible for federal regulation of natural gas. The interstate transportation
and sale for resale of natural gas is subject to federal governmental
regulation, including regulation of transportation and storage tariffs and
various other matters, by FERC. The Natural Gas Wellhead Decontrol Act of 1989
("Decontrol Act") terminated federal price controls on wellhead sales of
domestic natural gas on January 1, 1993. Consequently, sales of natural gas may
be made at market prices, subject to applicable contract provisions. The FERC's
jurisdiction over natural gas transportation and storage was unaffected by the
Decontrol Act.
Sales of natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation remain
subject to extensive federal and state regulation. Several major regulatory
changes have been implemented by Congress and the FERC from 1985 to the present
that affect the economics of natural gas production, transportation, and sales.
In addition, the FERC continues to promulgate revisions to various aspects of
the rules and regulations affecting those segments of the natural gas industry,
most notably interstate natural gas transmission companies, that remain subject
to the FERC's jurisdiction. These initiatives may also affect the intrastate
transportation of gas under certain circumstances. The stated purpose of many of
these regulatory changes is to promote competition among the various sectors of
the natural gas industry and these initiatives generally reflect more
light-handed regulation of the natural gas industry. The ultimate impact of the
rules and regulations issued by the FERC since 1985 cannot be predicted. In
addition, many aspects of these regulatory developments have not become final
but are still pending judicial and FERC final decisions.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Trust cannot predict when or if any such
proposals might become effective, or their effect, if any, on the Trust. The
natural gas industry historically has been very heavily regulated; therefore,
there is no assurance that the less stringent regulatory approach recently
pursued by the FERC and Congress will continue.
Sales of crude oil, condensate and gas liquids are not currently regulated
and are made at market prices. Effective as of January 1, 1995, the FERC
implemented regulations establishing an indexing system for transportation rates
for oil that could increase the cost of transporting oil to the purchaser. The
Trust is not able to predict what effect, if any, these regulations will have on
it, but other factors being equal, the regulations may tend to increase
transportation costs or reduce wellhead prices for crude oil.
State Regulation
The various states regulate the production and sale of oil and natural gas,
including imposing requirements for obtaining drilling permits, the method of
developing new fields, the spacing and operation of wells and the prevention of
waste of oil and gas resources. The rates of production may be regulated and the
maximum daily production allowables from both oil and gas wells may be
established on a market demand or conservation basis, or both.
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. The Trustee does not believe that compliance with these
laws by the operating parties will have any material adverse effect on the Unit
holders.
ITEM 3. LEGAL PROCEEDINGS
Not Applicable.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of Unit holders, through the
solicitation of proxies or otherwise, during the fourth quarter ended December
31, 1999.
PART II
ITEM 5. MARKET FOR UNITS OF THE TRUST AND RELATED SECURITY HOLDER MATTERS
The information under "Units of Beneficial Interest" at page 1 of the
Trust's Annual Report to security holders for the year ended December 31, 1999,
is herein incorporated by reference.
ITEM 6. SELECTED FINANCIAL DATA
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------
1999 1998 1997 1996 1995
----------- ----------- ----------- ----------- -----------
Royalty income.................... $18,799,659 $10,777,901 $22,598,873 $19,930,354 $12,014,623
Distributable income.............. 18,471,842 10,414,382 22,190,115 19,488,574 11,632,463
Distributable income per Unit..... 0.396317 0.223443 0.476092 0.418131 0.249574
Distributions per Unit............ 0.396317 0.223443 0.476092 0.418131 0.249574
Total assets, December 31......... 5,305,223 3,861,776 5,220,786 5,913,931 5,252,922
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
The "Trustee's Discussion and Analysis for the Three Year Period Ended
December 31, 1999" and "Results of the 4th Quarters of 1999 and 1998" at pages 5
through 7 of the Trust's Annual Report to security holders for the year ended
December 31, 1999 is herein incorporated by reference.
Year 2000 Issue
Many existing computer programs use only two digits to identify a year in
the date field. These programs were designed and developed without considering
the impact of the change in the century. If not corrected, many computer
applications could fail or create erroneous results by the Year 2000. The Year
2000 issue affects virtually all companies and organizations. If a company or
organization did not successfully address its Year 2000 issues, it could face
material adverse consequences.
As the Trust did not directly maintain any systems, the Trust did not incur
any direct costs related to the Year 2000 issue.
The Trustee identified those vendors it believed could have an impact on
its day-to-day operations if their operations were interrupted as a result of
Year 2000 problems. The Trust made formal inquiries to these vendors requesting
information on their state of readiness for the Year 2000. Through responses
received and other literature reviewed by the Trustee with respect to its
vendors, the Trustee believes that all significant vendors addressed the Year
2000 issue and planned to be and were compliant prior to the Year 2000.
The Trustee has no reason to believe that its vendors were not Year 2000
compliant on January 1, 2000. In the event the Trustee learns that a vendor's
system was not Year 2000 compliant, the Trustee will assess the potential risk
and develop contingency plans at that time.
The Trust is a passive entity with no business operations and the
information technology systems ("IT") employed by the Trustee in connection with
its duties on behalf of the Trust are less extensive than the systems employed
by many business entities. The Trust had no formal IT budget and the Trustee did
not make any expenditures relating to the Trustee's IT systems used in
connection with the Trust during 1999.
Because the royalty interests held by the Trust are fixed, the Trustee is
dependent upon the third parties that hold operating interests with respect
thereto for the receipt of royalty income. Thus, if any such third party failed
to deliver royalty income, the Trustee would have no alternative source for such
income. The
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Trustee believes that the worst case scenario would be the failure by one or
more of the third parties who pay royalties to the Trust or who make
distributions to Unit holders for the Trust to identify and remediate Year 2000
problems on a timely basis, which could cause the Trustee to be unable to make
required distributions to Unit holders. With respect to a failure by a third
party to deliver royalty income or make distributions to Unit holders on a
timely basis, the Trustee believes that it would have no control over the
efforts of such third party to correct the problems, and significant delays in
the receipt of royalty income and distributions to Unit holders could result.
The Trustee knows of no Year 2000 problems that have adversely affected the
Trust. However, there can be no guarantee that the Trustee has been able to
identify all Year 2000 problems or can fully remediate all Year 2000 problems
identified on a timely basis. There can be no assurance that the systems of the
Trustee or third party vendors on which the Trust relies will be timely
remediated. The failure by the Trustee or any such third party to fully
remediate its Year 2000 problems on a timely basis could have a material adverse
affect on the Trustee's ability to receive revenue, account for and make timely
distribution of the Trust's distributable income.
Certain of the statements made above regarding the Trustee's Year 2000
program are forward-looking statements, and there can be no assurance that the
Trustee will be able to achieve Year 2000 compliance in the manner and by the
dates indicated above.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not Applicable.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Financial Statements of the Trust and the notes thereto at page 8 et
seq. of the Trust's Annual Report to security holders for the year ended
December 31, 1999, are herein incorporated by reference.
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
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, 1999.
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 years ended December 31, 1999, 1998, and 1997, the Trustee
received total remuneration as follows:
NAME OF INDIVIDUAL CAPACITIES
OR NUMBER OF IN WHICH CASH
PERSONS IN GROUP SERVED COMPENSATION YEAR
------------------ ---------- ------------ ----
Bank of America, N.A., formerly NationsBank, N.A..... Trustee $44,735(1) 1997
$54,761(1) 1998
$40,272(1) 1999
- ---------------
(1) Under the Trust Indenture, the Trustee is entitled to an administrative fee
for its administrative services, preparation of quarterly and annual
statements with attention to tax and legal matters of: (i) 1/20 of
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1% of the first $100 million of annual gross revenue of the Trust and 1/30 of 1%
in excess of $100 million and (ii) Trustee's standard hourly rate in excess of
300 hours annually. The administrative fee is subject to reduction by a credit
for funds provision.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security Ownership of Certain Beneficial Owners. The following table
sets forth as of February 22, 2000, information with respect to each person
known to own beneficially more than 5% of the outstanding Units of the Trust:
AMOUNT AND NATURE OF PERCENT
NAME AND ADDRESS BENEFICIAL OWNERSHIP(1) OF CLASS
---------------- ----------------------- --------
Burlington Resources Oil & Gas Company(1) 27,577,741 Units 59.17%
5051 Westheimer
Suite 1400
Houston, Texas 77056-2124
McMorgan & Company(2) 5,000,000 Units 10.73%
One Bush Street
Suite 800
San Francisco, CA 94104
Alpine Capital, L.P.(3) 4,260,800 Units 9.1%
201 Main Street
Suite 3100
Fort Worth, TX 76102
- ---------------
(1) This information was provided to the Securities and Exchange Commission and
to the Trust in a Form 4 dated January 6, 1994, filed with the Securities
and Exchange Commission by Southland Royalty, a wholly-owned subsidiary of
BRI, and in Amendment 5 to Schedule 13D and Schedule 13E-3 dated December
28, 1993, filed with the Securities and Exchange Commission by Southland
Royalty and BRI. Such Units were reported to be owned directly by Southland
Royalty, now BROG.
The Form 4 filed by Southland Royalty and the Schedule 13D and Schedule
13E-3 filed by Southland Royalty and BRI 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 a Schedule 13G filed with the Securities and Exchange
Commission on July 12, 1999 on behalf of McMorgan & Company, an investment
adviser registered under the Investment Advisers Act of 1940, (McMorgan),
Thomas Allan Morton ("Morton"), and Terry Allen O'Toole ("O'Toole"). Such
Schedule 13G reports that McMorgan, Morton, and O'Toole have beneficial
ownership of such Units. It is reported in such Schedule 13G that McMorgan,
Morton, and O'Toole have sole voting and sole dispositive power with regard
to such Units. Morton and O'Toole filed in their capacities as control
persons of McMorgan and disclaimed beneficial ownership to such Units
involved in such Schedule 13G. The address of Morton and O'Toole is One Bush
Street, Suite 800, San Francisco, California 94104.
The Schedule 13G filed with the Securities and Exchange Commission on behalf
of McMorgan, Morton, and O'Toole may be reviewed for more detailed
information concerning the matters summarized herein.
(3) This information was provided to the Securities and Exchange Commission and
to the Trust in a Schedule 13D filed with the Securities and Exchange
Commission on behalf of Alpine Capital L.P., a Texas limited partnership,
("Alpine"), Robert W. Bruce III ("Bruce"), Algenpar, Inc., a Texas
corporation, ("Algenpar") and J. Taylor Crandall ("Crandall"), on August 6,
1999, as amended by a Schedule 13D/A filed on October 5, 1999, as further
amended by a Schedule 13D/A filed December 21, 1999, and as further amended
by a Schedule 13D/A filed February 25, 2000.
The Schedule 13D/A filed on February 25, 2000, was filed on behalf of The
Ann T. and Robert M. Bass Foundation, a Texas non-profit corporation, (the
"Foundation"), Ann T. Bass ("A. Bass"), and Robert M. Bass ("R. Bass"), in
addition to Alpine, Bruce, Algenpar, and Crandall and relates to a total of
4,335,200 Units, of which 4,260,800 Units were acquired by Alpine and
74,400 Units were acquired by
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the Foundation. The source of funds for the Units acquired by Alpine was
working capital of Alpine. The source of funds for the Units acquired by
the Foundation was working capital of the Foundation.
The address of Algenpar and Crandall is 201 Main Street, Suite 3100, Fort
Worth, Texas 76102. The address of Bruce is 96 Spring Street, South Salem,
New York 10590. The address of the Foundation and of R. Bass is 201 Main
Street, Suite 3100, Fort Worth, Texas 76102. The address of A. Bass is 6221
Westover Drive, Fort Worth, Texas 76107.
It is reported that Bruce and Algenpar are the two general partners of
Alpine, and Crandall is the President and sole stockholder of Algenpar. It
is further reported that, because of these relationships, Bruce, Algenpar,
and Crandall may be deemed to be beneficial owners of the Units acquired by
Alpine as set forth in the next paragraph. It is reported that Bruce is a
principal of The Bruce Management Co., Inc. which has shared investment
discretion over the Units owned by the Foundation, and that Crandall, A.
Bass, and R. Bass are directors of the Foundation. It is further reported
that, because of these relationships, Bruce, Crandall, A. Bass, and R. Bass
may be deemed to be beneficial owners of the Units acquired by the
Foundation as set forth in the next paragraph.
It is reported that as of February 22, 2000, of such 4,335,200 Units, (i)
Alpine had sole voting and dispositive power with regard to 4,260,800 of
such Units or 9.1% of the outstanding Units; (ii) the Foundation had sole
voting and dispositive power with regard to 74,400 of such Units or .2% of
the outstanding Units; (iii) Bruce and Crandall each shared voting and
dispositive power with regard to all of such 4,335,200 Units or 9.3% of the
outstanding Units; (iv) Algenpar had shared voting and dispositive power
with regard to 4,260,800 of such Units or 9.1% of the outstanding Units;
and (v) A. Bass and R. Bass each shared voting and dispositive power with
regard to 74,400 of such Units or .2% of the outstanding Units.
The Schedule 13D and its amendments filed 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 of America, N.A.
owned as of March 17, 2000, an aggregate of 249,995 Units with no right to vote
139,196 of these Units, shared right to vote 4,000 of these Units and sole right
to vote 106,799 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 of America, N.A.
(c) Change In Control. The Trustee knows of no arrangements which may
subsequently result in a change in control of the Trust.
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 years ended December 31, 1999,
1998, and 1997 and Item 12(b) for information concerning Units owned by Bank of
America, N.A. in various fiduciary capacities.
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PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
The following documents are filed as a part of this Report:
FINANCIAL STATEMENTS
Included in Part II of this Report by reference to the Annual Report of the
Trust for the year ended December 31, 1999:
Independent Auditors' Report
Statements of Assets, Liabilities and Trust Corpus
Statements of Distributable Income
Statements of Changes in Trust Corpus
Notes to Financial Statements
FINANCIAL STATEMENT SCHEDULES
Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required information is
given in the financial statements or notes thereto.
EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
(4)(a) -- Permian Basin Royalty Trust Indenture dated November 3,
1980, between Southland Royalty Company and The First
National Bank of Fort Worth (now Bank of America, N.A.),
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 (Permian Basin Royalty
Trust) from Southland Royalty Company to The First
National Bank of Fort Worth (now Bank of America, N.A.),
as Trustee, dated November 3, 1980 (without Schedules),
heretofore filed as Exhibit (4)(b) to the Trust's Annual
Report on Form 10-K to the Securities and Exchange
Commission for the fiscal year ended December 31, 1980,
is incorporated herein by reference.*
(c) -- Net Overriding Royalty Conveyance (Permian Basin Royalty
Trust -- Waddell Ranch) from Southland Royalty Company to
The First National Bank of Fort Worth (now Bank of
America, N.A.), as Trustee, dated November 3, 1980
(without Schedules), heretofore filed as Exhibit (4)(c)
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, 1999.**
(23) -- Consent of Cawley, Gillespie & Associates, Inc.,
reservoir engineer.**
(27) -- Financial Data Schedule.**
- ---------------
* A copy of this Exhibit is available to any Unit holder, at the actual cost of
reproduction, upon written request to the Trustee, Bank of America, N.A.,
P.O. Box 830650, Dallas, Texas 75283-0650.
** Filed herewith.
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REPORTS ON FORM 8-K
During the last quarter of the Trust's fiscal year ended December 31, 1999,
there were no reports on Form 8-K filed by the Trust.
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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 OF AMERICA, N.A.
TRUSTEE OF THE PERMIAN BASIN
ROYALTY TRUST
By /s/ RON E. HOOPER
-----------------------------------
Ron E. Hooper
Vice President
Date: March 27, 2000
(The Trust has no directors or executive officers.)
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INDEX TO EXHIBITS
SEQUENTIALLY
EXHIBIT NUMBERED
NUMBER EXHIBIT PAGE
------- ------- ------------
(4)(a) -- Permian Basin Royalty Trust Indenture dated November 3,
1980, between Southland Royalty Company and The First
National Bank of Fort Worth (now Bank of America, N.A.),
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 (Permian Basin Royalty
Trust) from Southland Royalty Company to The First
National Bank of Fort Worth (now Bank of America, N.A.),
as Trustee, dated November 3, 1980 (without Schedules),
heretofore filed as Exhibit (4)(b) to the Trust's Annual
Report on Form 10-K to the Securities and Exchange
Commission for the fiscal year ended December 31, 1980,
is incorporated herein by reference.*
(c) -- Net Overriding Royalty Conveyance (Permian Basin Royalty
Trust -- Waddell Ranch) from Southland Royalty Company to
The First National Bank of Fort Worth (now Bank of
America, N.A.), as Trustee, dated November 3, 1980
(without Schedules), heretofore filed as Exhibit (4)(c)
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, 1999.**
(23) -- Consent of Cawley, Gillespie & Associates, Inc.,
reservoir engineer.**
(27) -- Financial Data Schedule.**
- ---------------
* A copy of this Exhibit is available to any Unit holder, at the actual cost of
reproduction, upon written request to the Trustee, Bank of America, N.A.,
P.O. Box 830650, Dallas, Texas 75283-0650.
** Filed herewith.