================================================================================
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, 2000
[ ] 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.)
THE CHASE MANHATTAN BANK
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 8, 2000 -- 1,863,590 Units of Beneficial Interest in Mesa
Royalty Trust.
================================================================================
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MESA ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
Royalty income....................... $1,423,595 $1,206,359 $3,044,984 $2,415,240
Interest income...................... 17,941 6,488 40,065 19,037
General and administrative expense... (9,860) (5,621) (14,623) (15,156)
---------- ---------- ---------- ----------
Distributable income............ $1,431,676 $1,207,226 $3,070,426 $2,419,121
========== ========== ========== ==========
Distributable income per unit... $ .7682 $ .6478 $ 1.6476 $ 1.2981
========== ========== ========== ==========
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
JUNE 30, DECEMBER 31,
2000 1999
------------ ------------
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 1,413,735 $ 1,678,624
Interest receivable.................. 17,941 6,528
Net overriding royalty interest in
oil and gas properties............. 42,498,034 42,498,034
Accumulated amortization............. (30,383,915) (29,824,772)
------------ ------------
$ 13,545,795 $ 14,358,414
============ ============
LIABILITIES AND TRUST CORPUS
Distributions payable................ $ 1,431,676 $ 1,685,152
Trust corpus (1,863,590 units of
beneficial interest authorized and
outstanding)....................... 12,114,119 12,673,262
------------ ------------
$ 13,545,795 $ 14,358,414
============ ============
(The accompanying notes are an integral part of these financial statements.)
1
MESA ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- --------------------------
2000 1999 2000 1999
----------- ----------- ----------- -----------
Trust corpus, beginning of period.... $12,390,828 $13,525,089 $12,673,262 $13,889,555
Distributable income............ 1,431,676 1,207,226 3,070,426 2,419,121
Distributions to unitholders.... (1,431,676) (1,207,226) (3,070,426) (2,419,121)
Amortization of net overriding
royalty interest............. (276,709) (386,836) (559,143) (751,302)
----------- ----------- ----------- -----------
Trust corpus, end of period.......... $12,114,119 $13,138,253 $12,114,119 $13,138,253
=========== =========== =========== ===========
(The accompanying notes are an integral part of these financial statements.)
2
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 -- TRUST ORGANIZATION
The Mesa Royalty Trust (the "Trust") was created on November 1, 1979 when
Mesa Petroleum Co. conveyed to the Trust a 90% net profits overriding royalty
interest (the "Royalty") in certain producing oil and gas properties located in
the Hugoton field of Kansas, the San Juan Basin field of New Mexico and Colorado
and the Yellow Creek field of Wyoming (collectively, the "Royalty Properties").
Mesa Petroleum Co. was the predecessor to Mesa Limited Partnership ("MLP"), the
predecessor to MESA Inc. On April 30, 1991, MLP sold its interests in the
Royalty Properties located in the San Juan Basin field to Conoco Inc.
("Conoco"). 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 BP Amoco. Until August 7, 1997,
MESA Inc. operated the Hugoton Royalty Properties through Mesa Operating Co., a
wholly owned subsidiary of MESA Inc. On August 7, 1997, MESA Inc. merged with
and into Pioneer Natural Resources Company ("Pioneer"), formerly a wholly owned
subsidiary of MESA Inc., and Parker & Parsley Petroleum Company merged with and
into Pioneer Natural Resources USA, Inc. (successor to Mesa Operating Co.), a
wholly owned subsidiary of Pioneer ("PNR") (collectively, the mergers are
referred to herein as the "Merger"). Subsequent to the Merger, the Hugoton
Royalty Properties have been operated by PNR. The San Juan Basin Royalty
Properties located in New Mexico are operated by Conoco. The San Juan Basin
Royalty Properties located in Colorado are operated by Amoco. As used in this
report, PNR refers to the operator of the Hugoton Royalty Properties, Conoco
refers to the operator of the San Juan Basin Royalty Properties, other than the
portion of such properties located in Colorado, and Amoco refers to the operator
of the Colorado San Juan Basin Royalty Properties unless otherwise indicated.
The terms "working interest owner" and "working interest owners" generally refer
to the operators of the Royalty Properties as described above, unless the
context in which such terms are used indicates otherwise.
NOTE 2 -- BASIS OF PRESENTATION
The accompanying unaudited financial information has been prepared by The
Chase Manhattan Bank (the "Trustee"), the successor by merger to Chase Bank of
Texas, National Association, 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 1999 Annual Report on Form
10-K.
The Mesa Royalty Trust Indenture was amended in 1985, the effect of which
was an overall reduction of approximately 88.56% in the size of the Trust;
therefore, the Trust is now entitled each month to receive 90% of 11.44% of the
net proceeds for the preceding month. Generally, net proceeds means the excess
of the amounts received by the working interest owners from sales of oil and gas
from the Royalty Properties over operating and capital costs incurred.
3
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income recorded for a month is the amount computed and
paid by the working interest owners to the Trustee for such month rather
than either the value of a portion of the oil and gas produced by the
working interest owners for such month or the amount subsequently
determined to be the Trust's proportionate share of the net proceeds for
such month;
(b) Interest income, interest receivable, and distributions payable
to unitholders include interest to be earned on short-term investments from
the financial statement date through the next date of distribution and;
(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 distributable 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, it will differ from the basis used for
financial statements prepared in accordance with accounting principles accepted
in the United States. Under such accounting principles, Royalty income for a
month would be based on net proceeds from production for such month without
regard to when calculated or received and interest income for a month would be
calculated only through the end of such month.
4
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-Q includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-Q, including without
limitation the statements under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" are forward-looking statements.
Although the Working Interest Owners have advised the Trust that they believe
that the expectations reflected in the forward-looking statements contained
herein are reasonable, no assurance can be given that such expectations will
prove to have been correct. Important factors that could cause actual results to
differ materially from expectations ("Cautionary Statements") are disclosed in
this Form 10-Q and in the Trust's Form 10-K. 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.
5
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.
THREE MONTHS ENDED JUNE 30,
----------------------------------------------------------
2000 1999
--------------------------- ---------------------------
OIL, OIL,
CONDENSATE CONDENSATE
NATURAL AND NATURAL NATURAL AND NATURAL
GAS GAS LIQUIDS GAS GAS LIQUIDS
----------- ------------ ----------- ------------
The Trust's proportionate share of
Gross Proceeds(1).................. $ 1,768,102 679,749 $ 1,410,290 $349,711
Less the Trust's proportionate share
of:
Capital costs recovered(2)...... (323,732) -- (29,578) --
Operating costs................. (643,526) (48,317) (475,992) (48,072)
Interest on cost carryforward... (8,681) -- -- --
----------- ---------- ----------- --------
Royalty income....................... $ 792,163 631,432 $ 904,720 $301,639
=========== ========== =========== ========
Average sales price.................. $ 2.32 20.45 $ 1.62 $ 8.73
=========== ========== =========== ========
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 341,480 30,880 557,843 34,562
=========== ========== =========== ========
SIX MONTHS ENDED JUNE 30,
----------------------------------------------------------
2000 1999
--------------------------- ---------------------------
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).................. $ 3,572,915 1,295,791 $ 2,983,223 $680,635
Less the Trust's proportionate share
of:
Capital costs recovered(2)(3)... (473,707) (123,360) (4,881) --
Operating costs................. (1,208,905) -- (1,167,951) (75,786)
Interest on cost carryforward... (17,750) -- -- --
----------- ---------- ----------- --------
Royalty income....................... $ 1,872,553 1,172,431 $ 1,810,391 $604,849
=========== ========== =========== ========
Average sales price.................. $ 2.32 18.69 $ 1.70 $ 8.72
=========== ========== =========== ========
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 807,175 62,720 1,065,265 69,400
=========== ========== =========== ========
- ------------
(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 $492,762
and $506,534 at June 30, 2000 and June 30, 1999, respectively. The cost
carryforward at June 30, 2000 and June 30, 1999 relate solely to the San
Juan Basin Colorado properties.
(3) In the first quarter of 1999, the Trust received credits from Conoco related
to prior overcharges on capital expenditures.
6
THREE MONTHS ENDED JUNE 30, 2000 AND 1999
The distributable income of the Trust for each period includes the Royalty
income received from the working interest owners during such period, plus
interest income earned to the date of distribution. Trust administration
expenses are deducted in the computation of distributable income. Distributable
income for the quarter ended June 30, 2000 was $1,431,676, representing $.7682
per unit, compared to $1,207,226, representing $.6478 per unit, for the quarter
ended June 30, 1999. Based on 1,863,590 units outstanding for the quarters ended
June 30, 2000 and 1999, respectively, the per unit distributions were as
follows:
2000 1999
------ ------
April................................ $.2690 $.2295
May.................................. .2670 .2278
June................................. .2322 .1905
------ ------
$.7682 $.6478
====== ======
HUGOTON FIELD
PNR has advised the Trust that since June 1, 1995 natural gas produced from
the Hugoton field has generally been sold under short-term and multi-month
contracts at market clearing prices to multiple purchasers including Williams
Energy Supply ("WESCO"), Oneok Gas Marketing Inc., Amoco, and Anadarko Energy
Services, Inc. PNR has advised the Trust that it expects to continue to market
gas production from the Hugoton field under short-term and multi-month
contracts. Overall market prices received for natural gas from the Hugoton
Royalty Properties were higher in the second quarter of 2000 compared to the
second quarter of 1999.
In June 1994, PNR entered into a Gas Transportation Agreement ("Gas
Transportation Agreement") with Western Resources, Inc. ("WRI") for a primary
term of five years commencing June 1, 1995 and ending June 1, 2000, but which
may be continued in effect year-to-year thereafter. Pursuant to the Gas
Transportation Agreement, WRI has agreed to compress and transport up to 160
MMcf per day of gas and redeliver such gas to PNR at the inlet of PNR's Satanta
Plant. PNR agreed to pay WRI a fee of $0.06 per Mcf escalating 4% annually as of
June 1, 1996. This Gas Transportation Agreement has been assigned to
Midcontinent Market Center.
Royalty income attributable to the Hugoton Royalty increased to $1,070,059
in the second quarter of 2000, as compared to $771,562 in the second quarter of
1999 primarily due to higher prices received for production of natural gas and
natural gas liquids from the Hugoton Royalty Properties. The average price
received in the second quarter of 2000 for natural gas and natural gas liquids
sold from the Hugoton Royalty Properties was $2.36 per Mcf and $19.62 per
barrel, respectively, compared to $1.69 per Mcf and $7.88 per barrel during the
same period in 1999. Net production attributable to the Hugoton Royalty was
279,072 Mcf of natural gas and 20,971 barrels of natural gas liquids in the
second quarter of 2000 compared to 346,540 Mcf of natural gas and 23,592 barrels
of natural gas liquids in the second quarter of 1999. Changes in production
attributable to the Hugoton Royalty were due to natural production decline.
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, 2000 through
September 30, 2000, at 170.5 Bcf of gas, compared with 184.6 Bcf of gas during
the same period last year.
SAN JUAN BASIN
Royalty income from the San Juan Basin Royalty Properties is calculated and
paid to the Trust on a state-by-state basis. Royalty income from the San Juan
Basin Royalty Properties located in the state of New Mexico was $353,536 during
the second quarter of 2000 as compared with $434,797 in the
7
second quarter of 1999 primarily due to increased capital expenditures of
$284,548 in the second quarter of 2000 compared to $29,578 in the second quarter
of 1999. The increase in capital expenditures was offset by higher average
prices received. No Royalty income was received from Amoco with respect to the
San Juan Basin Royalty Properties located in the state of Colorado for the
second quarter of 2000 or 1999, as costs associated with the Fruitland Coal
drilling program on such properties have not been fully recovered. Net
production attributable to the San Juan Basin Royalty was 62,408 Mcf of natural
gas and 9,909 barrels of natural gas liquids in the second quarter of 2000 as
compared to 211,303 Mcf of natural gas and 10,970 barrels of natural gas liquids
in the second quarter of 1999. The lower net production attributable to the San
Juan Basin in the second quarter of 2000 is due to increased capital
expenditures. The average price received in the second quarter of 2000 for
natural gas sold from the San Juan Basin Royalty Properties was $2.14 per Mcf,
compared to $1.51 per Mcf during the same period in 1999.
Substantially all of the natural gas that is currently being produced from
the San Juan Basin Royalty Properties is currently being sold on the spot
market.
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 51% 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.
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.
SIX MONTHS ENDED JUNE 30, 2000 AND 1999
Distributable income increased to $3,070,426 for the six months ended
June 30, 2000 from $2,419,121 for the same period in 1999.
HUGOTON FIELD
Royalty income attributable to the Hugoton Royalty Properties increased to
$2,181,848 for the six months ended June 30, 2000 from $1,479,522 for the same
period in 1999 primarily due to higher natural gas and natural gas liquid
average prices received. The average price received in the first six months of
2000 for natural gas and natural gas liquids sold from the Hugoton field was
$2.38 per Mcf and $17.95 per barrel, compared to $1.75 per Mcf and $8.22 per
barrel during the same period in 1999.
SAN JUAN BASIN
Royalty income attributable to the New Mexico San Juan Basin Royalty
Properties decreased to $863,136 for the first six months of 2000 compared to
$935,718 in the first six months of 1999 primarily as a result of increased
capital expenditures. The average price received in the first six months of 2000
for natural gas sold from the San Juan Basin was $2.16 per Mcf, compared to
$1.63
8
per Mcf during the same period in 1999. No Royalty income was received from San
Juan Basin Royalty Properties located in Colorado for the six months ended June
30, 2000 and 1999, as costs associated with Fruitland Coal drilling on such
properties have not been fully recovered.
PART II -- OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS
(Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference.)
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
4(a) *Mesa Royalty Trust Indenture between Mesa Petroleum Co.
and Texas Commerce Bank National Association, as Trustee,
dated November 1, 1979.................................... 2-65217 1(a)
4(b) *Overriding Royalty Conveyance between Mesa Petroleum Co.
and Texas Commerce Bank, as Trustee, dated November 1,
1979...................................................... 2-65217 1(b)
4(c) *First Amendment to the Mesa Royalty Trust Indenture dated
as of March 14, 1985 (Exhibit 4(c) to Form 10-K for year
ended December 31, 1984 of Mesa Royalty Trust)............ 1-7884 4(c)
4(d) *Form of Assignment of Overriding Royalty Interest,
effective April 1, 1985, from Texas Commerce Bank National
Association, as Trustee, to MTR Holding Co. (Exhibit 4(d)
to Form 10-K for year ended December 31, 1984 of Mesa
Royalty Trust)............................................ 1-7884 4(d)
4(e) *Purchase and Sale Agreement, dated March 25, 1991, by and
among Mesa Limited Partnership, Mesa Operating Limited
Partnership and Conoco, as amended on April 30, 1991
(Exhibit 4(e) to Form 10-K for year ended December 31,
1991 of Mesa Royalty Trust)............................... 1-7884 4(e)
27 Financial Data Schedule
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust during the second quarter of 2000.
9
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 THE CHASE MANHATTAN BANK
-------------------------------------
TRUSTEE
By /s/ PETE FOSTER
-------------------------------------
PETE FOSTER
SENIOR VICE PRESIDENT & TRUST OFFICER
Date: August 8, 2000
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.
10