================================================================================
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, 1998
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 1-7884
MESA ROYALTY TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 74-6284806
(STATE OR OTHER JURISDICTION OF, (I.R.S. EMPLOYER
INCORPORATION 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)
(713) 216-6369
(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 10, 1998 -- 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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------------- ----------------------------
1998 1997 1998 1997
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Royalty income....................... $ 1,400,356 $ 1,698,336 $ 5,203,701 $ 7,210,166
Interest income...................... 17,005 20,908 62,878 77,599
General and administrative expense... (4,698) (14,750) (31,329) (33,328)
------------- ------------- ------------- -------------
Distributable income............ $ 1,412,663 $ 1,704,494 $ 5,235,250 $ 7,254,437
============= ============= ============= =============
Distributable income per unit... $ .7580 $ .9146 $ 2.8092 $ 3.8927
============= ============= ============= =============
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
SEPTEMBER 30, DECEMBER 31,
1998 1997
------------- ------------
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 1,395,658 $ 2,071,790
Interest receivable.................. 17,005 32,350
Net overriding royalty interest in
oil and gas properties............. 42,498,034 42,498,034
Accumulated amortization............. (28,189,748) (26,985,308)
------------ ------------
$ 15,720,949 $ 17,616,866
============ ============
LIABILITIES AND TRUST CORPUS
Distributions payable................ $ 1,412,663 $ 2,104,140
Trust corpus (1,863,590 units of
beneficial interest authorized
and outstanding)................... 14,308,286 15,512,726
------------ ------------
$ 15,720,949 $ 17,616,866
============ ============
(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 NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------ ------------------------------
1998 1997 1998 1997
-------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Trust corpus, beginning of period.... $ 14,651,291 $ 16,396,486 $ 15,512,726 $ 17,414,537
Distributable income............ 1,412,663 1,704,494 5,235,250 7,254,437
Distributions to unitholders.... (1,412,663) (1,704,494) (5,235,250) (7,254,437)
Amortization of net overriding
royalty interest............. (343,005) (510,876) (1,204,440) (1,528,927)
-------------- -------------- -------------- --------------
Trust corpus, end of period.......... $ 14,308,286 $ 15,885,610 $ 14,308,286 $ 15,885,610
============== ============== ============== ==============
</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"), 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
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 are 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 (the "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 1997 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>
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
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 from the balance sheet 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
<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 including without limitation in conjunction with the
forward-looking statements included 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
Pioneer has established a "Year 2000" project (the "Project") to assess, to
the extent possible, its Year 2000 risk exposure; to take remedial actions
necessary to minimize the Year 2000 risk exposure to Pioneer and third parties
with whom it has data interchange; and, to test its systems and processes once
remedial actions have been taken. Because of the importance of occurrence dates
in the oil and gas industry, the consequences of not pursuing Year 2000
modifications could be critical to Pioneer's ability to manage and report
operating activities. Pioneer has contracted with a third party to perform the
assessment and remedial phases of its Year 2000 project.
The assessment phase of the Project is 85% complete as of September 30,
1998, and included, among other procedures, the assessment of information
technology applications and systems; the assessment of non-information
technology exposures; the initiation of inquiry and dialogue with significant
third party business partners, customers and suppliers in an effect to
understand their Year 2000 readiness and potential impact on Pioneer; and, the
formulation of contingency plans for mission-critical information technology
systems. Pioneer expects to complete the assessment phase of its Year 2000
project by the end of the first quarter of 1999 but is being delayed by limited
responses to inquiries made of third party businesses. The remedial phase of the
Project is approximately 40% complete as of September 30, 1998, subject to the
results of third party inquiry assessments and the testing phase. The
remediation of non-information technology is expected to be completed by mid-
1999. The testing phase of the Project is expected to be completed by May 1999
for information technology systems and by mid-1999 for non-information
technology.
Although Pioneer is making every effort to mitigate the risks associated
with the Year 2000 problem, there can be no assurance that the Project or
resulting contingency plans will have anticipated all Year 2000 scenarios. A
failure to remedy a critical Year 2000 problem could result in information and
non-information technology failures, the receipt or transmission of erroneous
data, lost data or a combination of similar problems of a magnitude that cannot
be accurately assessed at this time.
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. Conoco expects that the costs will not have a material financial impact on
the
5
<PAGE>
Trust. 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 from having a material adverse affect on
Conoco's financial condition or operations.
Chase Bank of Texas, National Association ("Chase" or 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, Chase 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.
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 unaudited summary illustrates the net effect of the
components of the actual Royalty computation for the periods indicated.
<TABLE>
<CAPTION>
THREE MONTHS ENDED SEPTEMBER 30,
---------------------------------------------------------
1998 1997
--------------------------- ---------------------------
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).................. $ 1,956,224 $ 343,251 $ 2,101,854 $ 556,531
Less the Trust's proportionate share
of:
Capital costs recovered(2)....... (122,728) -- (88,915) --
Operating costs.................. (732,879) (43,512) (821,280) (41,008)
Interest on cost carryforward.... -- -- (8,846) --
------------ ------------ ------------ ------------
Royalty income....................... $ 1,100,617 $ 299,739 $ 1,182,813 $ 515,523
============ ============ ============ ============
Average sales price.................. $ 1.90 $ 9.45 $ 1.91 $ 12.67
============ ============ ============ ============
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 578,842 31,718 620,316 40,688
============ ============ ============ ============
NINE MONTHS ENDED SEPTEMBER 30,
---------------------------------------------------------
1998 1997
--------------------------- ---------------------------
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).................. $ 6,771,272 $1,323,268 $ 8,134,181 $2,133,227
Less the Trust's proportionate share
of:
Capital costs recovered(2)....... (501,581) -- (229,942) --
Operating costs.................. (2,240,826) (130,524) (2,679,939) (120,821)
Interest on cost carryforward.... (17,908) -- (26,810) --
------------ ------------ ------------ ------------
Royalty income....................... $ 4,010,957 $1,192,744 $ 5,197,490 $2,012,406
============ ============ ============ ============
Average sales price.................. $ 2.12 $ 11.22 $ 2.34 $ 15.74
============ ============ ============ ============
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 1,895,395 106,273 2,222,958 127,859
============ ============ ============ ============
</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 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 $481,350
and $464,570 at September 30, 1998 and September 30, 1997, respectively. The
cost carryforward at September 30, 1998 and September 30, 1997 relate solely
to the San Juan Basin Colorado properties.
7
<PAGE>
THREE MONTHS ENDED SEPTEMBER 30, 1998 AND 1997
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, 1998 was $1,412,663, representing $.7580 per unit, compared to
$1,704,494, representing $.9146 per unit, in the third quarter of 1997. Based on
1,863,590 units outstanding for the quarters ended September 30, 1998 and 1997,
respectively, the per unit distributions were as follows:
1998 1997
--------- ---------
July................................. $ .2808 $ .3012
August............................... .2525 .3156
September............................ .2247 .2978
--------- ---------
$ .7580 $ .9146
========= =========
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 Western Resources, Inc.
("WRI"), OnEok, formerly Western Gas Marketing, Inc., Amoco Production Company
and Anadarko Energy Services, Inc. PNR 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 second quarter of 1998 compared to the second
quarter of 1997.
In June 1994, PNR entered into a Gas Transportation Agreement with WRI
("Gas Transportation Agreement") 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 has agreed to pay WRI a
fee of $0.06 per Mcf escalating 4% annually as of June 1, 1996.
Royalty income attributable to the Hugoton Royalty decreased to $972,768 in
the third quarter of 1998, as compared to $1,158,353 in the third quarter of
1997 primarily due to lower average natural gas liquids sales prices. The
average price received in the third quarter of 1998 for natural gas and natural
gas liquids sold from the Hugoton field was $1.95 per Mcf and $9.21 per barrel,
respectively, compared to $1.94 per Mcf and $12.67 per barrel during the same
period in 1997. In addition, net production attributable to the Hugoton Royalty
was 391,347 Mcf of natural gas and 22,762 barrels of natural gas liquids in the
third quarter of 1998 compared to 391,305 Mcf of natural gas and 31,509 barrels
of natural gas liquids in the third quarter of 1997. Changes in production
attributable to the Hugoton Royalty were due to normal fluctuations.
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, 1998 through
September 30, 1998, at 214.6 billion cubic feet of gas, compared with 223
billion cubic feet 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. The Royalty income from the San
Juan Basin Royalty Properties located in the state of New Mexico decreased to
$427,588 during the third quarter of 1998 as compared with $539,983 in the third
quarter of 1997 due to lower natural gas production and lower average natural
gas
8
<PAGE>
liquids prices. No Royalty income was received from the San Juan Basin Royalty
Properties located in Colorado for the third quarter of 1998 or 1997, 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
187,494 Mcf of natural gas and 8,956 barrels of natural gas liquids in the third
quarter of 1998 as compared to 229,011 Mcf of natural gas and 9,179 barrels of
natural gas liquids in the third quarter of 1997. The average price received in
the third quarter of 1998 for natural gas sold from the San Juan Basin was $1.80
per Mcf, compared to $1.85 per Mcf during the same period in 1997.
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, 1998 AND 1997
Distributable income decreased to $5,235,250 for the nine months ended
September 30, 1998 from $7,254,437 for the same period in 1997 due primarily to
lower natural gas prices.
HUGOTON FIELD
Royalty income attributable to the Hugoton Royalty Properties decreased to
$3,590,809 for the nine months ended September 30, 1998 from $4,688,341 for the
same period in 1997 primarily 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 1998 for natural gas sold from the Hugoton field was
$2.18 per Mcf, compared to $2.43 per Mcf during the same period in 1997.
SAN JUAN BASIN
Royalty income attributable to the New Mexico San Juan Basin Royalty
Properties decreased to $1,612,892 for the first nine months of 1998 compared to
$2,521,825 in the first nine months of 1997 primarily as a result of decreased
average natural gas and natural gas liquids prices. The average price received
in the first nine months of 1998 for natural gas sold from the San Juan Basin
was $2.00 per Mcf, compared to $2.21 per Mcf during the same period in 1997. No
Royalty income was received from San Juan Basin Royalty Properties located in
Colorado for the nine months ended September 30, 1998 and 1997, 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
<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.)
<TABLE>
<CAPTION>
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
<S> <C> <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)
10(h) *Gas Transportation Agreement dated as of June 14, 1994 by and between
Mesa Operating Co. and Western Resources, Inc. (Exhibit 10(h) to Form
10-Q for quarter ended March 31, 1995 of Mesa Royalty Trust)............ 1-7884 10(h)
27 Financial Data Schedule
</TABLE>
(B) REPORTS ON FORM 8-K
None.
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
By CHASE BANK OF TEXAS,
NATIONAL ASSOCIATION
TRUSTEE
By /s/ PETE FOSTER
PETE FOSTER
SENIOR VICE PRESIDENT
& TRUST OFFICER
Date: November 12, 1998
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 1998 THIRD QUARTER REPORT AND FORM 10-Q AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH 1998 THIRD QUARTER REPORT AND FORM 10-Q.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
<CASH> 1,395,658
<SECURITIES> 0
<RECEIVABLES> 17,005
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,412,663
<PP&E> 42,498,034
<DEPRECIATION> 28,189,748
<TOTAL-ASSETS> 15,720,949
<CURRENT-LIABILITIES> 1,412,663
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 14,308,286
<TOTAL-LIABILITY-AND-EQUITY> 15,720,949
<SALES> 5,203,701
<TOTAL-REVENUES> 5,266,579
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 5,235,250
<INCOME-TAX> 0
<INCOME-CONTINUING> 5,235,250
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 5,235,250
<EPS-PRIMARY> 2.81
<EPS-DILUTED> 2.81
</TABLE>
