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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER
30, 1999
[ ] 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 1-7884
MESA ROYALTY TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 74-6284806
(STATE OF INCORPORATION (I.R.S. EMPLOYER
OR ORGANIZATION) IDENTIFICATION NO.)
CHASE BANK OF TEXAS,
NATIONAL ASSOCIATION
CORPORATE TRUST DIVISION
712 MAIN STREET
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
1-800-852-1422
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
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 the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
As of November 12, 1999 -- 1,863,590 Units of Beneficial Interest in Mesa
Royalty Trust.
================================================================================
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MESA ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------------- ----------------------------
1999 1998 1999 1998
------------- ------------- ------------- -------------
Royalty income....................... $ 1,376,799 $ 1,400,356 $ 3,792,039 $ 5,203,701
Interest income...................... 29,346 17,005 48,383 62,878
General and administrative expense... (6,056) (4,698) (21,212) (31,329)
------------- ------------- ------------- -------------
Distributable income............ $ 1,400,089 $ 1,412,663 $ 3,819,210 $ 5,235,250
============= ============= ============= =============
Distributable income per unit... $ .7513 $ .7580 $ 2.0494 $ 2.8092
============= ============= ============= =============
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------ ------------
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 1,370,743 $ 1,002,130
Interest receivable.................. 29,346 10,836
Net overriding royalty interest in
oil and gas properties............. 42,498,034 42,498,034
Accumulated amortization............. (29,707,567) (28,608,479)
------------ ------------
$ 14,190,556 $ 14,902,521
============ ============
LIABILITIES AND TRUST CORPUS
Distributions payable................ $ 1,400,089 $ 1,012,966
Trust corpus (1,863,590 units of
beneficial interest
authorized and outstanding)........ 12,790,467 13,889,555
------------ ------------
$ 14,190,556 $ 14,902,521
============ ============
(The accompanying notes are an integral part of these financial statements.)
1
MESA ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------ ------------------------------
1999 1998 1999 1998
-------------- -------------- -------------- --------------
Trust corpus, beginning of period.... $ 13,138,253 $ 14,651,291 $ 13,889,555 $ 15,512,726
Distributable income............ 1,400,089 1,412,663 3,819,210 5,235,250
Distributions to unitholders.... (1,400,089) (1,412,663) (3,819,210) (5,235,250)
Amortization of net overriding
royalty interest............. (347,786) (343,005) (1,099,088) (1,204,440)
-------------- -------------- -------------- --------------
Trust corpus, end of period.......... $ 12,790,467 $ 14,308,286 $ 12,790,467 $ 14,308,286
============== ============== ============== ==============
(The accompanying notes are an integral part of these financial statements.)
2
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 -- TRUST ORGANIZATION
The Mesa Royalty Trust (the "Trust") was created on November 1, 1979 when
Mesa Petroleum Co. conveyed to the Trust a 90% net profits overriding royalty
interest (the "Royalty") in certain producing oil and gas properties located
in the Hugoton field of Kansas, the San Juan Basin field of New Mexico and
Colorado and the Yellow Creek field of Wyoming (collectively, the "Royalty
Properties"). Mesa Petroleum Co. was the predecessor to Mesa Limited
Partnership ("MLP"), the predecessor to MESA Inc. On April 30, 1991, MLP sold
its interests in the Royalty Properties located in the San Juan Basin field to
Conoco Inc. ("Conoco"), a wholly owned subsidiary of E. I. duPont de Nemours &
Company. Conoco sold the portion of its interests in the San Juan Basin Royalty
Properties located in Colorado to MarkWest Energy Partners, Ltd. (effective
January 1, 1993) and Red Willow Production Company (effective April 1, 1992). On
October 26, 1994, MarkWest Energy Partners, Ltd. sold substantially all of its
interest in the Colorado San Juan Basin Royalty Properties to Amoco Production
Company ("Amoco"), a subsidiary of Amoco Corp. Until August 7, 1997, MESA Inc.
operated the Hugoton Royalty Properties through Mesa Operating Co. ("Mesa"), a
subsidiary of MESA Inc. On August 7, 1997, MESA Inc. merged with and into
Pioneer Natural Resources Company ("Pioneer"), formerly a wholly owned
subsidiary of MESA Inc., and Parker & Parsley Petroleum Company merged with and
into Pioneer Natural Resources USA, Inc. (successor to Mesa Operating Co.), a
wholly owned subsidiary of Pioneer ("PNR") (collectively, the mergers are
referred to herein as the "Merger"). Subsequent to the Merger, the Hugoton
Royalty Properties have been operated by PNR. The San Juan Basin Royalty
Properties located in New Mexico are operated by Conoco. The San Juan Basin
Royalty Properties located in Colorado are operated by Amoco. As used in this
report, PNR refers to the operator of the Hugoton Royalty Properties, Conoco
refers to the operator of the San Juan Basin Royalty Properties, other than the
portion of such properties located in Colorado, and Amoco refers to the operator
of the Colorado San Juan Basin Royalty Properties unless otherwise indicated.
The terms "working interest owner" and "working interest owners" generally
refer to the operators of the Royalty Properties as described above, unless the
context in which such terms are used indicates otherwise.
NOTE 2 -- BASIS OF PRESENTATION
The accompanying unaudited financial information has been prepared by Chase
Bank of Texas, National Association ("Trustee") in accordance with the
instructions to Form 10-Q, and the Trustee believes such information includes
all the disclosures necessary to make the information presented not misleading.
The information furnished reflects all adjustments which are, in the opinion of
the Trustee, necessary for a fair presentation of the results for the interim
periods presented. The financial information should be read in conjunction with
the financial statements and notes thereto included in the Trust's 1998 Annual
Report on Form 10-K.
The Mesa Royalty Trust Indenture was amended in 1985, the effect of which
was an overall reduction of approximately 88.56% in the size of the Trust;
therefore, the Trust is now entitled each month to receive 90% of 11.44% of the
net proceeds for the preceding month. Generally, net proceeds means the excess
of the amounts received by the working interest owners from sales of oil and gas
from the Royalty Properties over operating and capital costs incurred.
3
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income recorded for a month is the amount computed and
paid by the working interest owners to the Trustee for such month rather
than either the value of a portion of the oil and gas produced by the
working interest owners for such month or the amount subsequently
determined to be the Trust's proportionate share of the net proceeds for
such month;
(b) Interest income, interest receivable, and distributions payable
to unitholders include interest to be earned on short-term investments from
the financial statement's date through the next distribution date;
(c) Trust general and administrative expenses, net of reimbursements,
are recorded in the month they accrue;
(d) Amortization of the net overriding royalty interests, which is
calculated on a unit-of-production basis, is charged directly to trust
corpus since such amount does not affect distributable income; and
(e) Distributions payable are determined on a monthly basis and are
payable to unitholders of record as of the last business day of each month
or such other day as the Trustee determines is required to comply with
legal or stock exchange requirements. However, cash distributions are made
quarterly in January, April, July and October, and include interest earned
from the monthly record dates to the date of distribution.
This basis for reporting Royalty income is thought to be the most
meaningful because distributions to the unitholders for a month are based on net
cash receipts for such month. However, these statements differ from financial
statements prepared in accordance with generally accepted accounting principles
in several respects. Under such principles, Royalty income for a month would be
based on net proceeds for such month without regard to when calculated or
received and interest income would include interest earned during the period
covered by the financial statements and would exclude interest from the period
end to the date of distribution.
4
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-Q includes "forward-looking statements" within the meaning
of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-Q, including without
limitation the statements under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" are forward-looking statements.
Although the Working Interest Owners have advised the Trust that they believe
that the expectations reflected in the forward-looking statements contained
herein are reasonable, no assurance can be given that such expectations will
prove to have been correct. Important factors that could cause actual results to
differ materially from expectations ("Cautionary Statements") are disclosed in
this Form 10-Q and in the Trust's Form 10-K, including without limitation in
conjunction with the forward-looking statements included in this Form 10-Q. All
subsequent written and oral forward-looking statements attributable to the Trust
or persons acting on its behalf are expressly qualified in their entirety by the
Cautionary Statements.
INFORMATION SYSTEMS FOR THE YEAR 2000
The inability of some computer programs and embedded computer chips to
distinguish between the year 1900 and the year 2000 (the "Year 2000 problem")
poses a serious threat of business disruption to any organization that utilizes
computer technology and computer chip technology in their business systems or
equipment. In proactive response to the Year 2000 problem, PNR established a
"Year 2000" project to assess, to the extent possible, PNR's internal Year
2000 problem; to take remedial actions necessary to minimize the Year 2000 risk
exposure to PNR and significant third parties with whom it has data interchange;
and, to test its systems and processes once remedial actions have been taken.
PNR has contracted with IBM Global Services to perform the assessment and
remedial phases of its Year 2000 project.
As of September 30, 1999, the assessment phase of PNR's Year 2000 project
is complete and has included, among other procedures, (1) the identification of
necessary remediation, upgrade and/or replacement of existing information
technology applications and systems; (2) the assessment of non-information
technology exposures, such as telecommunications systems, security systems,
elevators and process control equipment; (3) the initiation of inquiry and
dialogue with significant third party business partners, customers and suppliers
in an effort to understand and assess their Year 2000 problems, readiness and
potential impact on PNR and its Year 2000 problem; (4) the implementation of
processes designed to reduce the risk of reintroduction of Year 2000 problems
into PNR's systems and business processes; and, (5) the formulation of
contingency plans for mission-critical information technology systems.
As of September 30, 1999, PNR estimates that the remedial phase is
approximately 98% complete, on a worldwide basis, subject to the continuing
evaluations of the responses from third party inquiries and the testing phase.
The remedial phase has included the upgrade and/or replacement of certain
application and hardware systems. The remediation of non-information technology
was completed in October 1999. PNR's Year 2000 remedial actions have not delayed
other information technology projects or upgrades. The testing phase of PNR's
Year 2000 project is expected to be completed by the end of November 1999. None
of PNR's costs related to the Year 2000 are passed through to the Trust.
A failure to remedy a critical Year 2000 problem could have a materially
adverse effect on PNR's results of operations and financial condition. The most
likely worst case scenario which may be
5
encountered as a result of a Year 2000 problem could include information and
non-information system failures, the receipt or transmission of erroneous data,
lost data or a combination of similar problems of a magnitude to PNR that cannot
be accurately assessed at this time.
In the assessment phase of PNR's Year 2000 project, contingency plans were
designed to mitigate the exposures to mission critical information technology
systems, such as oil and gas sales receipts; vendor and royalty cash
distributions; debt compliance; accounting; and, employee compensation. Such
contingency plans anticipate the extensive utilization of third-party data
processing services, personal computer applications and the substitution of
courier and mail services in place of electronic data interchange. Given the
uncertainties regarding the scope of the Year 2000 problem and the compliance of
significant third parties, there can be no assurance that contingency plans will
have anticipated all Year 2000 scenarios.
Conoco has completed the inventory and assessment phases and has entered
the remediation and testing phases of its plan to become Year 2000-capable.
Approximately 98 percent of the work required to fix issues identified by the
Year 2000 Program has been completed as of September 30, 1999. All mission
critical work for Conoco's operations is complete. However, Conoco cannot
reasonably estimate the potential impact on its financial condition and
operations if key third parties, including governments, do not become Year
2000-capable on a timely basis. Conoco is working through various trade
associations as well as communicating directly with its significant suppliers
and customers to determine their Year 2000 capability. In addition, Conoco has
begun contingency planning to handle potential disruptions in electrical,
telecommunications, transportation and distribution services. There can be no
guarantee that these efforts will prevent the failure of third parties to become
Year 2000-capable and from having a material adverse affect on Conoco's
financial condition or operations or the Royalty Properties operated by Conoco.
None of Conoco's costs related to the Year 2000 are passed through to the Trust.
The Trustee has developed and is implementing a program to prepare its
systems and applications for the Year 2000, including those used to render
services to the Trust. In that connection, the Trustee intends to have such
systems and applications capable of processing, on and after January 1, 2000,
date and date-related data consistent with the functionality of such systems and
applications, without a material adverse effect upon its performance of services
as Trustee. Third parties that the Trust conducts business with could be prone
to Year 2000 problems that could not be assessed or detected by the Trust. The
Trust is contacting the major third parties to determine whether they will be
able to resolve, in a timely manner, any Year 2000 problems directly affecting
the Trust and to inform them of the Trust's internal assessment of its Year 2000
review.
The information above with respect to PNR and Conoco is based on
information provided by PNR and Conoco to the Trustee for use in this Form 10-Q.
6
SUMMARY OF ROYALTY INCOME AND AVERAGE PRICES
(UNAUDITED)
Royalty income is computed after deducting the Trust's proportionate share
of capital costs, operating costs and interest on any cost carryforward from the
Trust's proportionate share of "Gross Proceeds," as defined in the Royalty
conveyance. The following unaudited summary illustrates the net effect of the
components of the actual Royalty computation for the periods indicated.
THREE MONTHS ENDED SEPTEMBER 30,
--------------------------------------------------------
1999 1998
-------------------------- ---------------------------
OIL, OIL,
CONDENSATE CONDENSATE
NATURAL AND NATURAL NATURAL AND NATURAL
GAS GAS LIQUIDS GAS GAS LIQUIDS
----------- ------------ ------------ ------------
The Trust's proportionate share of
Gross Proceeds(1).................. $ 1,658,208 $411,579 $ 1,956,224 $ 343,251
Less the Trust's proportionate share
of:
Capital costs recovered(2)....... (49,665) -- (122,728) --
Operating costs.................. (563,110) (52,852) (732,879) (43,512)
Interest on cost carryforward.... (27,361) -- -- --
----------- ------------ ------------ ------------
Royalty income....................... $ 1,018,072 $358,727 $ 1,100,617 $ 299,739
=========== ============ ============ ============
Average sales price.................. $ 1.96 $ 11.54 $ 1.90 $ 9.45
=========== ============ ============ ============
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 520,540 31,099 578,842 31,718
=========== ============ ============ ============
NINE MONTHS ENDED SEPTEMBER 30,
---------------------------------------------------------
1999 1998
--------------------------- ---------------------------
OIL, OIL,
CONDENSATE CONDENSATE
NATURAL AND NATURAL NATURAL AND NATURAL
GAS GAS LIQUIDS GAS GAS LIQUIDS
------------ ------------ ------------ ------------
The Trust's proportionate share of
Gross Proceeds(1).................. $ 4,641,431 $1,092,214 $ 6,771,272 $1,323,268
Less the Trust's proportionate share
of:
Capital costs recovered(2)....... (54,546) -- (501,581) --
Operating costs.................. (1,731,061) (128,638) (2,240,826) (130,524)
Interest on cost carryforward.... (27,361) -- (17,908) --
------------ ------------ ------------ ------------
Royalty income....................... $ 2,828,463 $ 963,576 $ 4,010,957 $1,192,744
============ ============ ============ ============
Average sales price.................. $ 1.78 $ 9.60 $ 2.12 $ 11.22
============ ============ ============ ============
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 1,588,055 100,381 1,895,395 106,273
============ ============ ============ ============
- ------------
(1) Gross Proceeds from natural gas liquids attributable to the Hugoton and San
Juan Basin properties are net of a volumetric in-kind processing fee
retained by PNR and Conoco, respectively.
(2) Capital costs recovered represents capital costs incurred during the current
or prior periods to the extent that such costs have been recovered by the
working interest owners from current period Gross Proceeds. Cost
carryforward represents capital costs incurred during the current or prior
periods which will be recovered from future period Gross Proceeds. The cost
carryforward resulting from the Fruitland Coal drilling program was $479,365
and $481,350 at September 30, 1999 and September 30, 1998, respectively. The
cost carryforward at September 30, 1999 and September 30, 1998 relate solely
to the San Juan Basin Colorado properties.
7
THREE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
The distributable income of the Trust includes the Royalty income received
from the working interest owners during such period, plus interest income earned
to the date of distribution. Trust administration expenses are deducted in the
computation of distributable income. Distributable income for the quarter ended
September 30, 1999 was $1,400,089, representing $.7513 per unit, compared to
$1,412,663, representing $.7580 per unit, for the quarter ended September 30,
1998. Based on 1,863,590 units outstanding for the quarters ended September 30,
1999 and 1998, respectively, the per unit distributions were as follows:
1999 1998
--------- ---------
July........................... $ .2317 $ .2808
August......................... .2781 .2525
September...................... .2414 .2247
--------- ---------
$ .7513 $ .7580
========= =========
HUGOTON FIELD
PNR has advised the Trust that since June 1, 1995 natural gas produced from
the Hugoton field has generally been sold under short-term contracts at market
clearing prices to multiple purchasers including Williams Energy Supply
("WESCO"), OnEok Gas Marketing Inc., Amoco Production Company, and Anadarko
Energy Services, Inc. PNR has advised the Trust that it expects to continue to
market gas production from the Hugoton field under short-term and multi-month
contracts. Overall market prices received for natural gas from the Hugoton
Royalty Properties were higher in the third quarter of 1999 compared to the
third quarter of 1998.
PNR is currently a party to a Gas Transportation Agreement with Mid
Continent Market Center ("Midcontinent") that was assigned to Midcontinent by
Western Resources, Inc. in 1998. The Gas Transportation Agreement will terminate
June 1, 2000 unless continued in effect year to year thereafter. Pursuant to the
Gas Transportation Agreement, Midcontinent agrees to compress and transport up
to 160 MMcf per day of gas and redeliver such gas to PNR at the inlet of PNR's
Satanta Plant, and PNR agrees to pay Midcontinent a fee of $0.06 per Mcf
escalated 4% annually as of June 1, 1996.
Royalty income attributable to the Hugoton Royalty decreased to $882,587 in
the third quarter of 1999, as compared to $972,768 in the third quarter of 1998
primarily due to lower natural gas and natural gas liquids production volumes.
The average price received in the third quarter of 1999 for natural gas and
natural gas liquids sold from the Hugoton field was $1.99 per Mcf and $10.76 per
barrel, respectively, compared to $1.95 per Mcf and $9.21 per barrel during the
same period in 1998. In addition, net production attributable to the Hugoton
Royalty was 322,744 Mcf of natural gas and 22,335 barrels of natural gas liquids
in the third quarter of 1999 compared to 391,347 Mcf of natural gas and 22,762
barrels of natural gas liquids in the third quarter of 1998.
Allowable rates of production in the Hugoton field are set by the Kansas
Corporation Commission (the "KCC") based on the level of market demand. The
KCC set the Hugoton field allowable for the period April 1, 1999 through
September 30, 1999, at 184.6 billion cubic feet of gas, compared with 214.6
billion cubic feet of gas during the same period last year. In addition, the KCC
has set the Hugoton field allowable for the period October 1, 1999 through March
31, 2000, at 179.6 billion cubic feet of gas.
SAN JUAN BASIN
Royalty income from the San Juan Basin Royalty Properties is calculated and
paid to the Trust on a state-by-state basis. The Royalty income from the San
Juan Basin Royalty Properties located in the state of New Mexico increased to
$494,212 during the third quarter of 1999 as compared with
8
$427,588 in the third quarter of 1998 due to higher average natural gas and
natural gas liquids prices and higher natural gas production. No Royalty income
was received from the San Juan Basin Royalty Properties located in Colorado for
the second quarter of 1999 or 1998, as costs associated with the Fruitland Coal
drilling on such properties have not been fully recovered. Net production
attributable to the San Juan Basin Royalty was 197,796 Mcf of natural gas and
8,764 barrels of natural gas liquids in the third quarter of 1999 as compared to
187,495 Mcf of natural gas and 8,956 barrels of natural gas liquids in the third
quarter of 1998. The average price received in the third quarter of 1999 for
natural gas sold from the San Juan Basin was $1.90 per Mcf, compared to $1.80
per Mcf during the same period in 1998.
The Trust's interest in the San Juan Basin was conveyed from PNR's working
interest in 31,328 net producing acres in northwestern New Mexico and
southwestern Colorado. The San Juan Basin New Mexico reserves represent
approximately 36% of the Trust's reserves. PNR completed the sale of its
underlying interest in the San Juan Basin Royalty Properties to Conoco on April
30, 1991. Conoco subsequently sold its underlying interest in the Colorado
portion of the San Juan Basin Royalty Properties to MarkWest Energy Partners,
Ltd. (effective January 1, 1993) and Red Willow Production Company (effective
April 1, 1992). On October 26, 1994, MarkWest Energy Partners, Ltd. sold
substantially all of its interest in the Colorado San Juan Basin Royalty
Properties to Amoco. The San Juan Basin Royalty Properties located in Colorado
account for less than 5% of the Trust's reserves.
NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
Distributable income decreased to $3,819,210 for the nine months ended
September 30, 1999 from $5,235,250 for the same period in 1998.
HUGOTON FIELD
Royalty income attributable to the Hugoton Royalty Properties decreased to
$2,362,109 for the nine months ended September 30, 1999 from $3,590,809 for the
same period in 1998 due to lower natural gas and natural gas liquids production
and as well as lower average prices. The average price received in the first
nine months of 1999 for natural gas sold from the Hugoton field was $1.83 per
Mcf, compared to $2.18 per Mcf during the same period in 1998.
SAN JUAN BASIN
Royalty income attributable to the New Mexico San Juan Basin Royalty
Properties decreased to $1,429,930 for the first nine months of 1999 compared to
$1,612,892 in the first nine months of 1998 as a result of decreased average
natural gas and natural gas liquids prices. The average price received in the
first nine months of 1999 for natural gas sold from the San Juan Basin was $1.71
per Mcf, compared to $2.00 per Mcf during the same period in 1998. No Royalty
income was received from San Juan Basin Royalty Properties located in Colorado
for the nine months ended September 30, 1999 and 1998, as costs associated with
Fruitland Coal drilling on such properties have not been fully recovered.
The gas that is currently being produced from the San Juan Basin Royalty
Properties is being sold primarily on the spot market.
No distributions related to the Colorado portion of the San Juan Basin
Royalty have been made since 1990, as the costs of the Fruitland Coal drilling
in Colorado have not yet been recovered. The San Juan Basin development drilling
program has no effect on Royalty income or distributions relating to the Hugoton
Royalty.
Conoco has informed the Trust that it believes the production from the
Fruitland Coal formation will generally qualify for the tax credits provided
under Section 29 of the Internal Revenue Code of 1986, as amended. Thus,
unitholders are potentially eligible to claim their share of the tax credit
attributable to this qualifying production. Each unitholder should consult his
tax advisor regarding the limitations and requirements for claiming this tax
credit.
9
PART II -- OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS
(Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference.)
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
4(a) *Mesa Royalty Trust Indenture between Mesa Petroleum Co. and Texas
Commerce Bank National Association, as Trustee, dated November 1,
1979.................................................................... 2-65217 1(a)
4(b) *Overriding Royalty Conveyance between Mesa Petroleum Co. and Texas
Commerce Bank, as Trustee, dated November 1, 1979....................... 2-65217 1(b)
4(c) *First Amendment to the Mesa Royalty Trust Indenture dated as of March
14, 1985 (Exhibit 4(c) to Form 10-K for year ended December 31, 1984 of
Mesa Royalty Trust)..................................................... 1-7884 4(c)
4(d) *Form of Assignment of Overriding Royalty Interest, effective April 1,
1985, from Texas Commerce Bank National Association, as Trustee, to MTR
Holding Co. (Exhibit 4(d) to Form 10-K for year ended December 31, 1984
of Mesa Royalty Trust).................................................. 1-7884 4(d)
4(e) *Purchase and Sale Agreement, dated March 25, 1991, by and among Mesa
Limited Partnership, Mesa Operating Limited Partnership and Conoco, as
amended on April 30, 1991 (Exhibit 4(e) to Form 10-K for year ended
December 31, 1991 of Mesa Royalty Trust)................................ 1-7884 4(e)
27 Financial Data Schedule
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust during the third quarter of 1999.
10
SIGNATURES
PURSUANT TO THE REQUIREMENTS 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.
MESA ROYALTY TRUST
CHASE BANK OF TEXAS,
By NATIONAL ASSOCIATION
---------------------------------
TRUSTEE
By /s/ PETE FOSTER
---------------------------------
Pete Foster
SENIOR VICE PRESIDENT & TRUST
OFFICER
Date: November 12, 1999
The Registrant, Mesa Royalty Trust, has no principal executive officer,
principal financial officer, board of directors or persons performing similar
functions. Accordingly, no additional signatures are available and none have
been provided.
11