================================================================================
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 JUNE 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 August 10, 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------- ----------------------------
1999 1998 1999 1998
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Royalty income....................... $ 1,206,359 $ 1,620,266 $ 2,415,240 $ 3,803,345
Interest income...................... 6,488 20,393 19,037 45,873
General and administrative expense... (5,621) (7,581) (15,156) (26,631)
------------- ------------- ------------- -------------
Distributable income............ $ 1,207,226 $ 1,633,078 $ 2,419,121 $ 3,822,587
============= ============= ============= =============
Distributable income per unit... $ .6478 $ .8763 $ 1.2981 $ 2.0512
============= ============= ============= =============
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
JUNE 30, DECEMBER 31,
1999 1998
------------ ------------
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 1,200,738 $ 1,002,130
Interest receivable.................. 6,488 10,836
Net overriding royalty interest in
oil and gas properties............. 42,498,034 42,498,034
Accumulated amortization............. (29,359,781) (28,608,479)
------------ ------------
$ 14,345,479 $ 14,902,521
============ ============
LIABILITIES AND TRUST CORPUS
Distributions payable................ $ 1,207,226 $ 1,012,966
Trust corpus (1,863,590 units of
beneficial interest
authorized and outstanding)........ 13,138,253 13,889,555
------------ ------------
$ 14,345,479 $ 14,902,521
============ ============
(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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------ ------------------------------
1999 1998 1999 1998
-------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Trust corpus, beginning of period.... $ 13,525,089 $ 15,071,258 $ 13,889,555 $ 15,512,726
Distributable income............ 1,207,226 1,633,078 2,419,121 3,822,587
Distributions to unitholders.... (1,207,226) (1,633,078) (2,419,121) (3,822,587)
Amortization of net overriding
royalty interest............. (386,836) (419,967) (751,302) (861,435)
-------------- -------------- -------------- --------------
Trust corpus, end of period.......... $ 13,138,253 $ 14,651,291 $ 13,138,253 $ 14,651,291
============== ============== ============== ==============
</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
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 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 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 June 30, 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.
The completion of the assessment phase of its Year 2000 project has been
delayed by limited responses received on inquiries made of third party business
partners, customers and suppliers.
As of June 30, 1999, PNR estimates that the remedial phase is approximately
83% 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 by October 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 the end
of November 1999. None of PNR's costs related to the Year 2000 are passed
through to the Trust.
5
<PAGE>
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 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 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
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 JUNE 30,
-------------------------------------------------------------
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).................. $ 1,410,290 $349,711 $ 2,135,934 $438,436
Less the Trust's proportionate share
of:
Capital costs recovered(2)...... (29,578) -- (154,400) --
Operating costs................. (475,992) (48,072) (769,130) (21,644)
Interest on cost carryforward... -- -- (8,930) --
-------------- ------------ -------------- ------------
Royalty income....................... $ 904,720 $301,639 $ 1,203,474 $416,792
============== ============ ============== ============
Average sales price.................. $ 1.62 $ 8.73 $ 2.02 $ 11.02
============== ============ ============== ============
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 557,843 34,562 596,505 37,805
============== ============ ============== ============
</TABLE>
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
-------------------------------------------------------------
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).................. $ 2,983,223 $680,635 $ 4,815,049 $980,017
Less the Trust's proportionate share
of:
Capital costs recovered(2)...... (4,881) -- (378,874) --
Operating costs................. (1,167,951) (75,786) (1,507,947) (86,992)
Interest on cost carryforward... -- -- (17,908) --
-------------- ------------ -------------- ------------
Royalty income....................... $ 1,810,391 $604,849 $ 2,910,320 $893,025
============== ============ ============== ============
Average sales price.................. $ 1.70 $ 8.72 $ 2.22 $ 12.04
============== ============ ============== ============
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 1,065,265 69,400 1,308,247 74,144
============== ============ ============== ============
</TABLE>
- ------------
(1) Gross Proceeds attributable to natural gas liquids for the Hugoton and San
Juan Basin Royalty 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
$506,534 and $477,841 at June 30, 1999 and June 30, 1998 which relate solely
to the San Juan Basin Colorado properties.
7
<PAGE>
THREE MONTHS ENDED JUNE 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
June 30, 1999 was $1,207,226, representing $.6478 per unit, compared to
$1,633,078, representing $.8763 per unit, for the quarter ended June 30, 1998.
Based on 1,863,590 units outstanding for the quarters ended June 30, 1999 and
1998, respectively, the per unit distributions were as follows:
1999 1998
--------- ---------
April................................ $ .2295 $ .3333
May.................................. .2278 .2870
June................................. .1905 .2560
--------- ---------
$ .6478 $ .8763
========= =========
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 lower in the second quarter of 1999 compared to the
second 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 $771,562 in
the second quarter of 1999, as compared to $1,117,167 in the second quarter of
1998 primarily due to lower average natural gas and natural gas liquids sales
prices and volumes. The average price received in the second quarter of 1999 for
natural gas and natural gas liquids sold from the Hugoton field was $1.69 per
Mcf and $7.88 per barrel, respectively, compared to $2.09 per Mcf and $10.72 per
barrel during the same period in 1998. In addition, net production attributable
to the Hugoton Royalty was 346,540 Mcf of natural gas and 23,592 barrels of
natural gas liquids in the second quarter of 1999 compared to 390,690 Mcf of
natural gas and 28,043 barrels of natural gas liquids in the second quarter of
1999. Changes in production attributable to the Hugoton Royalty were due to
normal seasonal 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, 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.
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
$434,797 during the second quarter of 1999 as compared with $503,099 in the
second quarter of 1998 due to lower average natural gas and natural gas liquids
prices. 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
8
<PAGE>
recovered. Net production attributable to the San Juan Basin Royalty was 211,303
Mcf of natural gas and 10,970 barrels of natural gas liquids in the second
quarter of 1999 as compared to 205,815 Mcf of natural gas and 9,762 barrels of
natural gas liquids in the second quarter of 1998. The average price received in
the second quarter of 1999 for natural gas sold from the San Juan Basin was
$1.51 per Mcf, compared to $1.88 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.
SIX MONTHS ENDED JUNE 30, 1998 AND 1997
Distributable income decreased to $2,419,121 for the six months ended June
30, 1999 from $3,822,587 for the same period in 1998.
HUGOTON FIELD
Royalty income attributable to the Hugoton Royalty Properties decreased to
$1,479,522 for the six months ended June 30, 1999 from $2,618,041 for the same
period in 1998 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 six months of 1999 for natural gas sold from the Hugoton field was
$1.75 per Mcf, compared to $2.29 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 $935,718 for the first six months of 1999 compared to
$1,185,304 in the first six months of 1998 primarily as a result of decreased
average natural gas and natural gas liquids prices. The average price received
in the first six months of 1999 for natural gas sold from the San Juan Basin was
$1.63 per Mcf, compared to $2.10 per Mcf during the same period in 1998. No
Royalty income was received from San Juan Basin Royalty Properties located in
Colorado for the six months ended June 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
<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
------------ -------
<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 second 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 FOSTER
PETE FOSTER
SENIOR VICE PRESIDENT
& TRUST OFFICER
Date: August 10, 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 FORM 10-Q FOR THE QUARTERLY PERIOD ENDED 6/30/99 AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 1,200,738
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0
0
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