================================================================================
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 MARCH 31, 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 May 12, 1999 -- 1,863,590 Units of Beneficial Interest in Mesa
Royalty Trust.
================================================================================
<PAGE>
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MESA ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
----------------------------
1999 1998
------------- -------------
<S> <C> <C>
Royalty income....................... $ 1,208,881 $ 2,183,079
Interest income...................... 12,549 25,480
General and administrative expense... (9,535) (19,050)
------------- -------------
Distributable income............ $ 1,211,895 $ 2,189,509
============= =============
Distributable income per unit... $ 0.6503 $ 1.1749
============= =============
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1999 1998
------------ ------------
<S> <C> <C>
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 1,199,346 $ 1,002,130
Interest receivable.................. 12,549 10,836
Net overriding royalty interest in
oil and gas properties............. 42,498,034 42,498,034
Accumulated amortization............. (28,972,945) (28,608,479)
------------ ------------
$ 14,736,984 $ 14,902,521
============ ============
LIABILITIES AND TRUST CORPUS
Distributions payable................ $ 1,211,895 $ 1,012,966
Trust corpus (1,863,590 units of
beneficial interest
authorized and outstanding)........ 13,525,089 13,889,555
------------ ------------
$ 14,736,984 $ 14,902,521
============ ============
</TABLE>
(The accompanying notes are an integral part of these financial statements.)
1
<PAGE>
MESA ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
------------------------------
1999 1998
-------------- --------------
<S> <C> <C>
Trust corpus, beginning of period.... $ 13,889,555 $ 15,512,726
Distributable income............ 1,211,895 2,189,509
Distributions to unitholders.... (1,211,895) (2,189,509)
Amortization of net overriding
royalty interest............. (364,466) (441,468)
-------------- --------------
Trust corpus, end of period.......... $ 13,525,089 $ 15,071,258
============== ==============
</TABLE>
(The accompanying notes are an integral part of these financial statements.)
2
<PAGE>
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"), which was 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., a wholly owned 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
<PAGE>
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 are accrued;
(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 from production 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
<PAGE>
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. 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 March 31, 1999, PNR estimates that the assessment phase is
approximately 99% complete on a worldwide basis 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.
PNR expects to complete the assessment phase of its Year 2000 project by
the end of the second quarter of 1999 but is being delayed by limited responses
received on inquiries made of third party businesses.
As of March 31, 1999, PNR estimates that the remedial phase is
approximately 79% complete, on a worldwide basis, subject to the continuing
results of the third party inquiry assessments 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
is expected to be completed during July 1999. PNR's Year 2000 remedial actions
have not significantly delayed other information technology projects or
upgrades. The testing phase of PNR's Year 2000 project is expected to be
completed by October 1999 and all other information technology systems and
non-information
5
<PAGE>
technology remediation by the end of the second quarter of 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 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 are
being 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 essentially completed the inventory and assessment phases and
has entered the remediation and testing phases of its plan to become Year
2000-capable. Their target for completing Year 2000 modifications is mid-1999;
however, additional refinements and testing may continue through the end of
1999. 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
<PAGE>
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 summary illustrates the net effect of the components
of the actual Royalty computation for the periods indicated.
<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31,
-----------------------------------------------------------
1999 1998
---------------------------- ----------------------------
OIL, OIL,
CONDENSATE CONDENSATE
NATURAL AND NATURAL NATURAL AND NATURAL
GAS GAS LIQUIDS GAS GAS LIQUIDS
------------- ------------ ------------- ------------
<S> <C> <C> <C> <C>
The Trust's proportionate share of
Gross Proceeds(1).................. $ 1,572,933 $ 330,924 $ 2,647,182 $ 541,581
Less the Trust's proportionate share
of:
Capital costs recovered(2)(3)... 24,697 -- (204,905) --
Operating costs................. (691,959) (27,714) (726,453) (65,348)
Interest on cost carryforward... -- -- (8,978) --
------------- ------------ ------------- ------------
Royalty income....................... $ 905,671 $ 303,210 $ 1,706,846 $ 476,233
============= ============ ============= ============
Average sales price.................. $ 1.79 $ 8.68 $ 2.41 $ 13.48
============= ============ ============= ============
<CAPTION>
(Mcf) (Bbls) (Mcf) (Bbls)
<S> <C> <C> <C> <C>
Net production volumes attributable
to the Royalty..................... 505,339 34,926 708,590 35,323
============= ============ ============= ============
</TABLE>
- ------------
(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 Mesa 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 $489,117
and $510,154 at March 31, 1999 and March 31, 1998, respectively. The cost
carryforward at March 31, 1999 and March 31, 1998 relate solely to the San
Juan Basin Colorado properties.
(3) In the first quarter of 1999, the Trust received credits from Conoco related
to prior overcharges on capital expenditures.
7
<PAGE>
THREE MONTHS ENDED MARCH 31, 1999 AND 1998
The distributable income of the Trust for each period 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 March 31, 1999 was $1,211,895, representing $.6503
per unit, compared to $2,189,509, representing $1.1749 per unit, in the first
quarter ended March 31, 1998. Based on 1,863,590 units outstanding for the
quarters ended March 31, 1999 and 1998, respectively, the per unit distributions
were as follows:
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
January.............................. $ .1964 $ .4087
February............................. .2361 .3591
March................................ .2178 .4071
--------- ---------
$ .6503 $ 1.1749
========= =========
</TABLE>
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 and multi-month
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 lower in the first quarter of 1999 compared to
the first quarter of 1998.
In June 1994, PNR entered into a Gas Transportation Agreement ("Gas
Transportation Agreement") with Western Resources, Inc. ("WRI") for a primary
term of five years commencing June 1, 1995 and ending June 1, 2000, but which
may be continued in effect year-to-year thereafter. Pursuant to the Gas
Transportation Agreement, WRI has agreed 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. PNR agreed to pay WRI a fee of $0.06 per Mcf escalating 4% annually as of
June 1, 1996. This Gas Transportation Agreement was assigned to Midcontinent
Market Center.
Royalty income attributable to the Hugoton Royalty decreased to $707,960 in
the first quarter of 1999, from $1,500,874 in the first quarter of 1998
primarily due to lower prices received for production of natural gas and liquids
from the Hugoton Royalty Properties. The average price received in the first
quarter of 1999 for natural gas and natural gas liquids sold from the Hugoton
Royalty Properties was $1.82 per MCF and $8.53 per barrel, respectively,
compared to $2.46 per Mcf and $12.99 per barrel, respectively, in the first
quarter of 1998. Net production attributable to the Hugoton Royalty declined
from 271,234 Mcf of natural gas and 25,125 barrels of natural gas liquids in the
first quarter of 1999 to 466,692 Mcf of natural gas and 27,160 barrels of
natural gas liquids in the first 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 has set the Hugoton field allowable for the period April 1, 1999 through
September 30, 1999, at 184.6 Bcf of gas, compared with 214.6 Bcf of gas during
the same period last year.
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. Royalty income from the San Juan
Basin Royalty Properties located in the state of New Mexico was $500,921 during
the first quarter of 1999 as compared with royalty income of
8
<PAGE>
$682,205 in the first quarter of 1998. The decrease in Royalty income was due
primarily to decreased natural gas and natural gas liquids prices in the first
quarter of 1999. No royalty income was received from Amoco with respect to the
San Juan Basin Royalty Properties located in the state of Colorado for the first
quarter of 1999 or 1998, as costs associated with the Fruitland Coal drilling
program on such properties have not been fully recovered. Net production
attributable to the San Juan Basin Royalty was 234,105 Mcf of natural gas and
9,801 barrels of natural gas liquids in the first quarter of 1999, compared to
241,898 Mcf of natural gas and 8,163 barrels of natural gas liquids in the first
quarter of 1998. The average price received in the first quarter of 1999 for
natural gas sold from the San Juan Basin Royalty Properties was $1.76 per Mcf,
compared to $2.31 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. Substantially all of the natural gas
produced from the San Juan Basin is currently being sold on the spot market. 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.
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
<PAGE>
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. Chase Bank of Texas,
National Association is the successor name of Texas Commerce Bank National
Association.)
<TABLE>
<CAPTION>
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
<C> <S> <C> <C>
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
</TABLE>
(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 first quarter of 1999.
10
<PAGE>
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 FOSTE
-----------------------------------
PETE FOSTER
SENIOR VICE PRESIDENT & TRUST
OFFICER
Date: May 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
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM MESA ROYALTY
TRUST 1999 FIRST QUARTER REPORT AND FORM 10-Q AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH 1999 FIRST QUARTER REPORT AND FORM 10-Q.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> MAR-31-1999
<CASH> 1,199,346
<SECURITIES> 0
<RECEIVABLES> 12,549
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,211,895
<PP&E> 42,498,034
<DEPRECIATION> 28,972,945
<TOTAL-ASSETS> 14,736,984
<CURRENT-LIABILITIES> 1,211,895
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 13,525,089
<TOTAL-LIABILITY-AND-EQUITY> 14,736,984
<SALES> 1,208,881
<TOTAL-REVENUES> 1,221,430
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 9,535
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 1,211,895
<INCOME-TAX> 0
<INCOME-CONTINUING> 1,211,895
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1,211,895
<EPS-PRIMARY> .650
<EPS-DILUTED> .650
</TABLE>
