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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, 1995
[ ] 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.)
TEXAS COMMERCE BANK
NATIONAL ASSOCIATION
CORPORATE TRUST DIVISION
712 MAIN STREET
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(713) 216-5100
(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, 1995 -- 1,863,590 Units of Beneficial Interest in Mesa
Royalty Trust.
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<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,
---------------------------- ----------------------------
1995 1994 1995 1994
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Royalty income....................... $ 1,315,134 $ 1,491,461 $ 4,860,188 $ 5,685,616
Interest income...................... 17,309 15,211 59,086 48,858
General and administrative expense... (7,602) (9,947) (50,459) (25,264)
------------- ------------- ------------- -------------
Distributable income............ $ 1,324,841 $ 1,496,725 $ 4,868,815 $ 5,709,210
============= ============= ============= =============
Distributable income per unit... $ .7109 $ .8032 $ 2.6126 $ 3.0636
============= ============= ============= =============
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
SEPTEMBER 30, DECEMBER 31,
1995 1994
------------- ------------
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 1,307,532 $ 1,244,208
Interest receivable.................. 17,309 13,859
Net overriding royalty interest in
oil and gas properties............. 42,498,034 42,498,034
Accumulated amortization............. (22,270,160) (20,515,993)
------------- ------------
$ 21,552,715 $ 23,240,108
============= ============
LIABILITIES AND TRUST CORPUS
Distributions payable................ $ 1,324,841 $ 1,258,067
Trust corpus (1,863,590 units of
beneficial interest
authorized and outstanding)........ 20,227,874 21,982,041
------------- ------------
$ 21,552,715 $ 23,240,108
============= ============
(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,
------------------------------ ------------------------------
1995 1994 1995 1994
-------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Trust corpus, beginning of
period............................. $ 20,782,905 $ 22,696,452 $ 21,982,041 $ 24,250,937
Distributable income............ 1,324,841 1,496,725 4,868,815 5,709,210
Distributions to
unitholders................... (1,324,841) (1,496,725) (4,868,815) (5,709,210)
Amortization of net overriding
royalty
interest...................... (555,031) (703,277) (1,754,167) (2,257,762)
-------------- -------------- -------------- --------------
Trust corpus, end of period.......... $ 20,227,874 $ 21,993,175 $ 20,227,874 $ 21,993,175
============== ============== ============== ==============
</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).
MarkWest Energy Partners, Ltd. and Red Willow Production Company are referred to
collectively herein as "MarkWest". 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. The Hugoton Royalty Properties are operated by Mesa Operating Co., a
subsidiary of MESA Inc., and MESA Inc.'s interest in such properties is owned by
Hugoton Capital Limited Partnership, another MESA Inc. subsidiary. The San Juan
Basin Royalty Properties located in New Mexico are operated by Conoco. The San
Juan Basin Royalty Properties located in Colorado were operated by MarkWest for
periods prior to October 26, 1994 and by Amoco for periods beginning on or after
such date. As used in this report, the term "Mesa" generally 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, MarkWest refers to the operator of the Colorado San Juan
Basin Royalty Properties prior to October 26, 1994 and Amoco refers to the
operator of the Colorado San Juan Basin Royalty Properties on or after October
26, 1994, 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 Texas
Commerce Bank 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 1994 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 administration expenses 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
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 SEPTEMBER 30,
-----------------------------------------------------------
1995 1994
---------------------------- ----------------------------
OIL, OIL,
CONDENSATE CONDENSATE
NATURAL AND NATURAL NATURAL AND NATURAL
GAS GAS LIQUIDS GAS GAS LIQUIDS
------------- ------------ ------------- ------------
<S> <C> <C> <C> <C> <C>
The Trust's proportionate share of
Gross Proceeds(1).................. $ 1,463,728 $ 534,908 $ 1,819,402 $ 568,200
Less the Trust's proportionate share
of:
Capital costs recovered(2)...... (44,542) -- (92,496) --
Operating costs................. (590,088) (40,438) (740,913) (55,005)
Interest on cost carryforward... (8,434) -- (7,727) --
------------- ------------ ------------- ------------
Royalty income....................... $ 820,664 $ 494,470 $ 978,266 $ 513,195
============= ============ ============= ============
Average sales price.................. $ 1.22 $ 10.62 $ 1.64 $ 8.95
============= ============ ============= ============
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 653,942 46,689 604,419 51,008
============= ============ ============= ============
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30,
-----------------------------------------------------------
1995 1994
---------------------------- ----------------------------
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).................. $ 5,159,952 $ 1,803,374 $ 6,716,983 $ 1,561,238
Less the Trust's proportionate share
of:
Capital costs recovered(2)...... (103,732) -- (262,326) --
Operating costs................. (1,840,601) (133,431) (2,175,975) (131,915)
Interest on cost carryforward... (25,374) -- (22,389) --
------------- ------------ ------------- ------------
Royalty income....................... $ 3,190,245 $ 1,669,943 $ 4,256,293 $ 1,429,323
============= ============ ============= ============
Average sales price.................. $ 1.35 $ 10.80 $ 1.82 $ 9.97
============= ============ ============= ============
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 2,277,232 155,034 2,324,364 144,912
============= ============ ============= ============
</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 $436,541
and $429,871 at September 30, 1995 and September 30, 1994, respectively. The
cost carryforward at September 30, 1995 and September 30, 1994 relate solely
to the San Juan Basin Colorado properties. See the San Juan Basin discussion
below for additional information regarding the Fruitland Coal drilling
program.
5
<PAGE>
THREE MONTHS ENDED SEPTEMBER 30, 1995 AND 1994
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, 1995 was $1,324,841, representing $.7109 per unit, compared to
$1,496,725, representing $.8032 per unit, in the third quarter of 1994. Based on
1,863,590 units outstanding for the quarters ended September 30, 1995 and 1994,
respectively, the per unit distributions were as follows:
1995 1994
---------- ----------
July................................. $ .2689 $ .2483
August............................... .2733 .2965
September............................ .1687 .2584
---------- ----------
$ .7109 $ .8032
========== ==========
HUGOTON FIELD
Through May 31, 1995, Mesa's principal natural gas purchaser in the Hugoton
field was Western Resources, Inc., previously the Kansas Power and Light Company
("WRI"). Mesa sold gas from the Hugoton field to WRI pursuant to a contract
entered into effective January 1, 1990 (the "WRI Contract") which terminated on
May 31, 1995.
The WRI Contract provided for WRI to purchase from 12.7 to 19.5 billion
cubic feet of gas per year (approximately 1.3 to 2.0 billion cubic feet of gas
per year net to the Trust subject to the effect of operating expenses and
capital costs) at market prices for a total of at least 92.4 billion cubic feet
of gas (approximately 10 billion cubic feet of gas net to the Trust subject to
the effect of operating expenses and capital costs) during the term of the
agreement as amended. Under the WRI Contract, WRI paid market clearing prices as
determined monthly based on a price index published by a third party. The WRI
Contract also contained take-or-pay provisions requiring WRI to purchase and
receive, or pay for if not taken, 85% of the nominated contract quantities
during each seasonal period. The WRI Contract provided WRI with certain make-up
rights during the one-year period following termination of the WRI Contract.
With respect to gas that was the subject of make-up rights, WRI was required to
pay the higher of (i) a market clearing price determined by reference to prices
in effect when the make-up obligation was incurred or (ii) a market clearing
price determined by reference to prices in effect when the make-up gas was
taken. Upon termination of the WRI Contract on May 31, 1995, WRI incurred a
take-or-pay deficiency of approximately 2.0 billion cubic feet of gas. Mesa has
advised the Trust that WRI made up the entire amount of such deficiency during
June 1995. The Trust received its proportionate share of the take-or-pay money
received from WRI by Mesa in August 1995.
Mesa has advised the Trust that since June 1, 1995 natural gas previously
subject to the WRI Contract has been sold under short-term contracts at market
clearing prices to multiple purchasers, including WRI, and that Mesa expects to
continue to market production from the Hugoton field under short-term contracts
and multi-month contracts during the winter heating season. Mesa expects to
complete a five month contract with WRI effective as of November 1. The contract
would provide for WRI to purchase up to 25 MMcf per day of gas at market
clearing prices determined monthly based on third party published index prices,
plus five cents per MMbtu. Overall market prices
6
received for natural gas from the Hugoton Royalty Properties were lower in the
third quarter of 1995 compared to the third quarter of 1994.
In June 1994, Mesa 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 Mesa at the inlet of Mesa's Satanta Plant. Mesa has agreed to pay
WRI a fee of $0.06 per Mcf escalating 4% annually beginning June 1, 1996.
Royalty income attributable to the Hugoton Royalty decreased to $1,025,956
in the third quarter of 1995 as compared to $1,107,383 in the third quarter of
1994 primarily due to lower prices offset by increased natural gas production.
Net production attributable to the Hugoton Royalty was 457,623 Mcf of natural
gas and 39,669 barrels of natural gas liquids in the third quarter of 1995 as
compared to 432,012 Mcf of natural gas and 43,171 barrels of natural gas liquids
in the third quarter of 1994. The increase in natural gas production was
primarily attributable to higher field allowables for the 1995 period. The
average price received in the third quarter of 1995 for natural gas sold from
the Hugoton field was $1.33 per Mcf, compared to $1.59 Mcf during the same
period in 1994.
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 October 1, 1995 through March
31, 1996, at 242 billion cubic feet of gas, compared with 247 billion cubic feet
of gas during the same period last year.
The KCC held hearings during September 1995 to consider regulatory changes
to the manner in which field wide allowables are allocated among individual
wells within the Panoma field, a producing formation which directly underlies
the Hugoton field. Specifically, the KCC considered proposals from various
producers to amend calculations of well deliverability, the allocation of
allowables based on acreage and the makeup of underages. Mesa anticipates the
KCC will issue an order that will be effective as of November 1, 1995. Under the
order, the Hugoton Royalty Properties' percentage of the field and the total
allowable assigned to the wells is expected to increase.
In the first quarter of 1995, in an effort to address significant projected
debt service deficiencies, MESA Inc. began an auction process to sell all or a
portion of its interests in the Hugoton field, including the Hugoton Royalty
Properties. MESA Inc.'s interests in the Hugoton field represent two thirds of
MESA Inc.'s total equivalent oil and gas reserves. The auction process was
concluded in the second quarter of 1995 with no acceptable bids received. On
July 6, 1995, the MESA Inc. Board of Directors approved a proposal to expand its
review of strategic alternatives to include consideration of the sale of MESA
Inc. and stock-for-stock merger. The MESA Inc. Board also determined to continue
to explore the sale of all or a portion of the Hugoton field properties and to
explore other restructuring alternatives, including possible joint ventures
involving the Hugoton properties, asset sales, equity infusions, and refinancing
transactions. The MESA Inc. Board engaged independent financial advisors to
manage these efforts and to seek indications of interest from potential buyers
of MESA Inc. or its properties and of potential merger partners, both domestic
and foreign. There can be no assurance that a sale or merger of MESA Inc. or a
sale of its properties will be completed, or if completed, what the terms
thereof will be. MESA Inc.'s projected debt service problems, as well as any
restructuring, sale, merger or other strategic alternative, could have
significant effects on the Trust, although the precise nature of such effects
cannot be predicted or quantified at this time.
No assurance can be given by the Trust regarding MESA Inc.'s financial
condition. An event of bankruptcy of MESA Inc. could result in a delay in
receipt of royalty payments by the Trust,
7
increased administrative expenses of the Trust and other effects which cannot be
predicted or quantified at this time.
SAN JUAN BASIN
Royalty income from the San Juan Basin Royalty during the third quarter of
1995 was $289,178 as compared with $384,078 in the third quarter of 1994. The
decrease in San Juan Basin royalty income between the third quarter of 1995 and
the third quarter of 1994 was a result of lower natural gas prices. No royalty
income was received from the San Juan Basin Royalty Properties located in
Colorado for the third quarter of 1995 or 1994, 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 196,319 Mcf of natural
gas and 7,020 barrels of natural gas liquids in the third quarter of 1995
compared to 172,407 Mcf of natural gas and 7,837 barrels of natural gas liquids
in the third quarter of 1994. The average price received in the third quarter of
1995 for natural gas sold from the San Juan Basin Royalty Properties was $1.08
per Mcf, compared to $1.69 per Mcf during the same period in 1994.
The Trust's interest in the San Juan Basin Royalty Properties was conveyed
from Mesa's working interest in 31,328 net producing acres in northwestern New
Mexico and southwestern Colorado and accounts for approximately 28% of the
Trust's reserves. Mesa 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 sold substantially all of its interests in the Colorado San Juan
Basin Royalty Properties to Amoco. The San Juan Basin Royalty Properties located
in Colorado account for approximately 3% of the Trust's reserves.
NINE MONTHS ENDED SEPTEMBER 30, 1995 AND 1994
Distributable income decreased to $4,868,815 for the nine months ended
September 30, 1995 as compared to $5,709,210 for the same period in 1994 due
primarily to lower natural gas prices.
HUGOTON FIELD
Royalty income attributable to the Hugoton Royalty decreased to $3,681,245
for the nine months ended September 30, 1995, from $4,078,516 for the same
period in 1994. This decrease is primarily due to lower natural gas prices. Net
production attributable to the Hugoton Royalty Properties was 1,526,006 Mcf of
natural gas and 131,788 barrels of natural gas liquids in the first nine months
of 1995 compared to 1,581,636 Mcf of natural gas and 121,380 barrels of natural
gas liquids in the first nine months of 1994. The average price received in the
first nine months of 1995 for natural gas sold from the Hugoton Royalty
Properties decreased to $1.49 per Mcf, compared to $1.84 per Mcf during the same
period in 1994.
SAN JUAN BASIN
Royalty income attributable to the San Juan Basin Royalty decreased to
$1,178,943 for the first nine months of 1995 from $1,607,100 in royalty income
in the first nine months of 1994 primarily as a result of decreased natural gas
prices. Net production attributable to the San Juan Basin Royalty Properties was
751,226 Mcf of natural gas and 23,246 barrels of natural gas liquids in the
first nine months of 1995 compared to 742,728 Mcf of natural gas and 23,532
barrels of natural gas liquids in the first nine months of 1994. The average
price received in the first nine months of 1995 for natural
8
gas sold from the San Juan Basin Royalty Properties was $1.22 per Mcf, compared
to $1.80 per Mcf during the same period in 1994.
In April 1990, the working interest owner began drilling for coalbed
methane gas in the Fruitland Coal formation of the San Juan Basin. The Fruitland
Coal formation has been identified as one of the most prolific sources of U.S.
coalbed methane reserves. The Trust owns an interest in 26,700 gross acres and
25,400 net acres with Fruitland Coal potential. The working interest owner has
advised the Trust that it operates 40 (22.9 net) Fruitland Coal wells on Trust
properties. Of such wells, 37 (20.9 net) are producing at a combined gross rate
of approximately 68.2 (34.3 net) MMcf per day.
The gas that is currently being produced from the San Juan Basin Royalty
Properties is being sold primarily on the spot market. Conoco has advised the
Trust that it will also consider selling some of the gas produced from these
wells pursuant to longer term contracts at spot market prices.
Aggregate drilling and completion costs for the entire Fruitland Coal
development program were approximately $18.4 million. This amount includes
expenditures of approximately $5.0 million for pipeline connections,
compressors, salt water disposal systems, and clean-up of the areas surrounding
certain wells. The Trust's share of the total expenditures was approximately
$2.4 million. The Trust's share of the cost of drilling and completing the
Fruitland Coal wells was subject to recovery by the working interest owner on a
state-by-state basis before distributions were made from the San Juan Basin
Royalty. Accordingly, no distributions related to the San Juan Basin Royalty
were made from August 1990 through November 1992. In December 1992, after
recovery by the working interest owner of the costs of the Fruitland Coal
drilling in New Mexico, distributions from the New Mexico San Juan Basin Royalty
resumed. The San Juan Basin development drilling program had 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. The Trust
believes that such tax credits should be available to Trust unitholders.
FEDERAL INCOME TAX MATTERS
Information for computing the federal income tax consequences of owning
Trust units during 1995 will be mailed to Unitholders during the first quarter
of 1996.
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(e) *Gas Purchase Contract, dated as of January 1, 1990, between Mesa
Operating Limited Partnership, Seller and the Kansas Power & Light
Company, Buyer (Exhibit 19(a) to Form 10-Q for quarter ended June
30, 1989 of Mesa Royalty Trust).................................... 1-7884 19(a)
10(f) *Amendment No. 3 to Hugoton (MTR) Gas Purchase Contract, dated
December 19, 1991, by and between Hugoton Capital Limited
Partnership, as partial successor in interest to Mesa Operating
Limited Partnership, and the Kansas Power and Light Company
(Exhibit 10(f) to Form 10-K for year ended December 31, 1991 of
Mesa Royalty Trust)................................................ 1-7884 10(f)
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
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
TEXAS COMMERCE BANK
By _______NATIONAL ASSOCIATION______
TRUSTEE
By ______/s/__MICHAEL J. ULRICH_____
MICHAEL J. ULRICH
SENIOR VICE PRESIDENT & TRUST
OFFICER
Date: November 13, 1995
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 THE
STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS AS OF SEP-30-1995 AND THE
STATEMENT OF DISTRIBUTABLE INCOME FOR THE NINE MONTHS ENDED SEP-30-1995 AND
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> SEP-30-1995
<CASH> 1,307,532
<SECURITIES> 0
<RECEIVABLES> 17,309
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,324,841
<PP&E> 42,498,034
<DEPRECIATION> 22,270,160
<TOTAL-ASSETS> 21,552,715
<CURRENT-LIABILITIES> 1,324,841
<BONDS> 0
<COMMON> 0
0
0
<OTHER-SE> 20,227,874
<TOTAL-LIABILITY-AND-EQUITY> 21,552,715
<SALES> 0
<TOTAL-REVENUES> 4,860,188
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 50,459
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 4,868,815
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 4,868,815
<EPS-PRIMARY> 2.612
<EPS-DILUTED> 2.612
</TABLE>
