Edgar Filing: MESA ROYALTY TRUST/TX

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549
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FORM 10-K

(MARK ONE)

/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 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
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MESA ROYALTY TRUST

(Exact Name of Registrant as Specified in Its Charter)

NEW YORK 74-6284806
(State or Other Jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)

THE CHASE MANHATTAN BANK,
INSTITUTIONAL TRUST SERVICES
712 MAIN STREET
HOUSTON, TEXAS
(Address of Principal Executive 77002
Offices) (Zip Code)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 1-800-852-1422

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
------------------- ----------------

Units of Beneficial Interest New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE

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 by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /X/

The aggregate market value of 1,863,590 Units of Beneficial Interest in Mesa
Royalty Trust held by non-affiliates of the registrant at the closing sales
price on March 23, 2001, of $56.00 was approximately $104,361,040.

Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.

As of March 23, 2001, 1,863,590 Units of Beneficial Interest in Mesa Royalty
Trust.

Documents Incorporated By Reference: None.

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TABLE OF CONTENTS

PAGE
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PART I
Item 1. Business.................................................... 1
Description of the Trust.................................. 1
Description of the Units.................................. 2
Description of Royalty Properties......................... 5
Contracts................................................. 16
Regulation and Prices..................................... 18
Item 2. Properties.................................................. 19
Item 3. Legal Proceedings........................................... 19
Item 4. Submission of Matters to a Vote of Security Holders......... 19

PART II
Item 5. Market for the Registrant's Common Equity and Related
Unitholder Matters.......................................... 20
Item 6. Selected Financial Data..................................... 20
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 20
Summary of Royalty Income, Production and Average Prices
(Unaudited)............................................... 22
Item 8. Financial Statements and Supplementary Data................. 23
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 31

PART III
Item 10. Directors and Executive Officers of the Registrant.......... 31
Item 11. Executive Compensation...................................... 31
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 31
Item 13. Certain Relationships and Related Transactions.............. 32

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 32
SIGNATURES.......................................................................... 33

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-K 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-K 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-K, including without limitation in conjunction
with the forward-looking statements included in this 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.

PART I

ITEM 1. BUSINESS.

DESCRIPTION OF THE TRUST

The Mesa Royalty Trust (the "Trust"), created under the laws of the State of
Texas, maintains its offices at the office of the Trustee, The Chase Manhattan
Bank (the "Trustee"), 712 Main Street, Houston, Texas 77002. The telephone
number of the Trust is 1-800-852-1422.

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"). 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. Substantially all of
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 New Mexico San Juan Basin
Royalty Properties 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.

The terms of the Mesa Royalty Trust Indenture (the "Trust Indenture")
provide, among other things, that: (1) the Trust cannot engage in any business
or investment activity or purchase any assets; (2) the Royalty can be sold in
part or in total for cash upon approval of the unitholders; (3) the Trustee can
establish cash reserves and borrow funds to pay liabilities of the Trust and can
pledge the assets of the Trust to secure payment of the borrowings; (4) in
January, April, July and October of each year the Trustee will make quarterly
distributions of cash available for distribution to the unitholders; and
(5) the Trust will terminate upon the first to occur of the following events:
(i) at such time as the Trust's royalty income for each of two successive years
is less than $250,000 per year or (ii) a vote of the unitholders in favor of
termination. Royalty income of the Trust was $7,960,109 and $5,475,497 for the
years 2000 and 1999, respectively. Upon termination of the Trust, the Trustee
will sell for cash all the assets held in the Trust estate and make a final
distribution to unitholders of any funds remaining after all Trust liabilities
have been satisfied.

Under the instrument conveying the Royalty to the Trust (the "Conveyance"),
the Trust is entitled to a percentage of the Net Proceeds, as hereinafter
defined, realized from the minerals as, if and when produced from the Royalty
Properties. See "Description of Royalty Properties." The Conveyance provides for
a monthly computation of Net Proceeds. "Net Proceeds" means the excess of Gross
Proceeds, as hereinafter defined, received by the working interest owners during
a particular period over operating and capital costs for such period. "Gross
Proceeds" means the amount received by the

working interest owners from the sale of minerals covered by the Royalty,
subject to certain adjustments. Operating costs mean, generally, costs incurred
on an accrual basis by the working interest owners in operating the Royalty
Properties, including capital and non-capital costs. If operating and capital
costs exceed Gross Proceeds for any month, the excess plus interest thereon at
120% of the prime rate of Bank of America is recovered out of future Gross
Proceeds prior to the making of further payment to the Trust. The Trust,
however, is generally not liable for any operating costs or other costs or
liabilities attributable to the Royalty Properties or minerals produced
therefrom. The Trust is not obligated to return any royalty income received in
any period. The working interest owners are required to maintain books and
records sufficient to determine the amounts payable under the Royalty.
Additionally, in the event of a controversy between a working interest owner and
any purchaser as to the correct sales price for any production, amounts received
by such working interest owner and promptly deposited by it with an escrow agent
are not considered to have been received by such working interest owner and
therefore are not subject to being payable with respect to the Royalty until the
controversy is resolved; but all amounts thereafter paid to such working
interest owner by the escrow agent will be considered amounts received from the
sale of production. Similarly, operating costs include any amounts a working
interest owner is required to pay whether as a refund, interest or penalty to
any purchaser because the amount initially received by such working interest
owner as the sales price was in excess of that permitted by the terms of any
applicable contract, statute, regulation, order, decree or other obligation.
Within 30 days following the close of each calendar quarter, the working
interest owners are required to deliver to the Trustee a statement of the
computation of Net Proceeds attributable to such quarter.

The brief discussions of the Trust Indenture and the Conveyance contained
herein are qualified in their entirety by reference to the Trust Indenture and
the Conveyance themselves, which are exhibits to this Form 10-K and are
available upon request from the Trustee.

The Royalty Properties are required to be operated by the working interest
owners in accordance with reasonable and prudent business judgment and good oil
and gas field practices. Each working interest owner has the right to abandon
any well or lease if, in its opinion, such well or lease ceases to produce or is
not capable of producing oil, gas or other minerals in commercial quantities.
Each working interest owner markets the production on terms deemed by it to be
the best reasonably obtainable in the circumstances. See "Contracts". The
Trustee has no power or authority to exercise any control over the operation of
the Royalty Properties or the marketing of production therefrom.

In 1985 the Trust Indenture was amended at a special meeting of unitholders.
The effect of the amendment was an overall reduction of approximately 89% in the
size of the Trust, distributable income and related Trust reserves, effective
April 1, 1985. See Note 2 in the Notes to Financial Statements under Item 8 of
this Form 10-K.

The Trust has no employees. Administrative functions of the Trust are
performed by the Trustee.

DESCRIPTION OF THE UNITS

Each unit is evidenced by a transferable certificate issued by the Trustee.
Each unit ranks equally for purposes of distributions and has one vote on any
matter submitted to unitholders. A total of 1,863,590 units were outstanding at
March 23, 2001.

DISTRIBUTIONS

The Trustee determines for each month the amount of cash available for
distribution for such month. Such amount (the "Monthly Distribution Amount")
consists of the cash received from the Royalty during such month less the
obligations of the Trust paid during such month, adjusted for changes made by
the Trustee during such month in any cash reserves established for the payment
of contingent or future obligations of the Trust. The Monthly Distribution
Amount for each month is

payable to unitholders of record on the monthly record date (the "Monthly Record
Date") which is the close of business on the last business day of such month or
such other date as the Trustee determines is required to comply with legal or
stock exchange requirements. However, to reduce the administrative expenses of
the Trust, under the Trust Indenture the Trustee does not distribute cash
monthly, but rather, during January, April, July and October of each year
distributes to each person who was a unitholder of record on one or more of the
immediately preceding three Monthly Record Dates, the Monthly Distribution
Amount for the month or months that he was a unitholder of record, together with
interest earned on such Monthly Distribution Amount from the Monthly Record Date
to the payment date. Under the terms of the Trust Indenture, interest is earned
at a rate of 1 1/2% below the prime rate charged by The Chase Manhattan Bank or
the interest rate which The Chase Manhattan Bank pays in the normal course of
business on amounts placed with it, whichever is greater.

LIABILITY OF UNITHOLDERS

As regards the unitholders, the Trustee is fully liable if the Trustee
incurs any liability without ensuring that such liability will be satisfiable
only out of the Trust assets (regardless of whether the assets are adequate to
satisfy the liability) and in no event out of amounts distributed to, or other
assets owned by, unitholders. However, under Texas law, it is unclear whether a
unitholder would be jointly and severally liable for any liability of the Trust
in the event that all of the following conditions were to occur: (1) the
satisfaction of such liability was not by contract limited to the assets of the
Trust, (2) the assets of the Trust were insufficient to discharge such liability
and (3) the assets of the Trustee were insufficient to discharge such liability.
Although each unitholder should weigh this potential exposure in deciding
whether to retain or transfer his units, the Trustee is of the opinion that
because of the passive nature of the Trust assets, the restrictions on the power
of the Trustee to incur liabilities and the required financial net worth of any
trustee, the imposition of any liability on a unitholder is extremely unlikely.

FEDERAL INCOME TAX MATTERS

In a technical advice memorandum dated February 26, 1982, the National
Office of the Internal Revenue Service ("IRS") advised the Dallas District
Director that the Trust is classifiable as a grantor trust and not as an
association taxable as a corporation.

INCOME AND DEPLETION

Royalty income, net of depletion and severance taxes, is treated as
portfolio income, and subject to certain exceptions and transitional rules,
royalty income cannot be offset by losses from passive businesses. Additionally,
interest income is portfolio income. Administrative expense is an investment
expense.

Generally, prior to the Revenue Reconciliation Act of 1990, the transferee
of an oil and gas property could not claim percentage depletion with respect to
production from the property if it was "proved" at the time of the transfer.
This rule is not applicable in the case of transfers of properties after
October 11, 1990. Thus, eligible unitholders that acquired units after that date
are entitled to claim an allowance for percentage depletion with respect to
royalty income attributable to these units to the extent that this allowance
exceeds cost depletion as computed for the relevant period.

SECTION 29 CREDIT

The Trust receives royalty payments attributable to coal seam gas production
from the Fruitland Coal Formation properties. 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.

BACKUP WITHHOLDING

Distributions from the Trust are generally subject to backup withholding at
a rate of 31% of these distributions. Backup withholding will not normally apply
to distributions to a unitholder, however, unless a unitholder fails to properly
provide to the Trust his taxpayer identification number or the IRS notifies the
Trust that the taxpayer identification number provided by a unitholder is
incorrect.

SALE OF UNITS

Generally, except for recapture items, the sale, exchange or other
disposition of a unit will result in capital gain or loss measured by the
difference between the basis in the unit and the amount realized. Effective for
property placed in service after December 31, 1986, the amount of gain, if any,
realized upon the disposition of oil and gas property is treated as ordinary
income to the extent of the intangible drilling and development costs incurred
with respect to the property and depletion claimed with respect to such property
to the extent it reduced the taxpayer's basis in the property. Under this
provision, depletion attributable to a unit acquired after 1986 will be subject
to recapture as ordinary income upon disposition of the unit or upon disposition
of the oil and gas property to which the depletion is attributable. The balance
of any gain or any loss will be capital gain or loss if the unit was held by the
unitholder as a capital asset, either long-term or short-term depending on the
holding period of the unit. This capital gain or loss will be long-term if a
unitholder's holding period exceeded one year as of the date of sale or
exchange. A long-term capital gains rate of 20% applies to most capital assets
sold with a holding period of more than one year. Capital gain or loss will be
short-term if the unit has not been held for more than one year at the time of
disposition.

NON-U.S. UNITHOLDERS

In general, a unitholder who is a nonresident alien individual or which is a
foreign corporation, each a "non-U.S. unitholder" for purposes of this
discussion, will be subject to tax on the gross income produced by the Royalty
at a rate equal to 30% or lower treaty rate, if applicable. This tax will be
withheld by the Trustee and remitted directly to the United States Treasury. A
non-U.S. unitholder may elect to treat the income from the Royalty as
effectively connected with the conduct of a United States trade or business
under provisions of the Internal Revenue Code of 1986, as amended or pursuant to
any similar provisions of applicable treaties. Upon making this election a
non-U.S. unitholder is entitled to claim all deductions with respect to that
income, but he must file a United States federal income tax return to claim
these deductions. This election once made is irrevocable unless an applicable
treaty allows the election to be made annually.

The Internal Revenue Code and the Treasury Regulations thereunder treat the
publicly traded Trust as if it were a United States real property holding
corporation. Accordingly, non-U.S. unitholders owning greater than five percent
of the outstanding units are subject to United States federal income tax on the
gain on the disposition of their units. Non-U.S. unitholders owning less than
five percent of the outstanding units are not subject to United States federal
income tax on the gain on the disposition of their units.

Federal income taxation of a non-U.S. unitholder is a highly complex matter
which may be affected by many other considerations. Therefore, each non-U.S.
unitholder should consult with his own tax adviser as to the advisability of his
ownership of units.

TAX-EXEMPT ORGANIZATIONS

Investments in publicly traded partnerships are treated the same as
investments in other partnerships for purposes of the rules governing unrelated
business taxable income. The Royalty and interest income should not be unrelated
business taxable income so long as, generally, a unitholder did not incur debt
to acquire a unit or otherwise incur or maintain a debt that would not have been

incurred or maintained if the unit had not been acquired. Legislative proposals
have been made from time to time which, if adopted, would result in the
treatment of Royalty income as unrelated business income. Tax-exempt unitholders
should consult their own advisors with respect to the treatment of royalty
income.

DESCRIPTION OF ROYALTY PROPERTIES

PRODUCING ACREAGE AND WELLS AS OF DECEMBER 31, 2000

PRODUCING GAS
PRODUCING ACRES(1) WELLS(1)(2)
------------------- -------------------
GROSS NET OIL GAS
-------- -------- -------- --------

Hugoton Area (Kansas)....................................... 103,364 103,114 466 465.5
San Juan Basin (Northwestern New Mexico and Southwestern
Colorado)................................................. 40,716 31,328 1,561 465.3
------- ------- ----- -----
Total..................................................... 144,080 134,442 2,027 930.8
======= ======= ===== =====

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(1) The Trust does not have a working interest in the producing acres and
producing gas wells. The gross and net amounts in the table above represent
gross and net amounts attributable to the working interest owners and are
the basis for the Gross Proceeds amounts discussed under "Description of the
Trust".

(2) One or more completions in the same bore hole are counted as one well. Where
multiple well bores are in a single production unit, the unit is counted as
one well.

HUGOTON

The principal property interest conveyed to the Trust accounts for
approximately 46% of the Trust's reserves and was carved out of PNR's working
interest in 104,437 net producing acres in the Hugoton field. The life of the
field is expected to extend beyond the year 2020.

The gas produced from the Hugoton properties is available for sale on the
spot market. See "Contracts". Since the Hugoton field gas is sold in the
intrastate and interstate markets, it is subject to state and federal laws and
regulations. The Kansas Corporation Commission (the "KCC") is the state
regulatory agency responsible for setting field market demand (gas allowables),
prorating production between wells and other related matters. Hugoton field gas
is also subject to the rules and regulations of the Federal Energy Regulatory
Commission (the "FERC"). See "Regulation and Prices".

SAN JUAN BASIN

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 54% of the Trust's reserves. Substantially all of the natural gas
produced from the San Juan Basin is currently being sold on the spot market. PNR
completed the sale of its underlying interest in the San Juan Basin Royalty
Properties to Conoco on April 30, 1991. Conoco subsequently sold its underlying
interest in the Colorado portion of the San Juan Basin Royalty Properties to
MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow
Production Company (effective April 1, 1992). On October 26, 1994, MarkWest
Energy Partners, Ltd. sold substantially all of its interest in the Colorado San
Juan Basin Royalty Properties to Amoco. See "Description of the Trust". The San
Juan Basin Royalty Properties located in Colorado account for less than 5% of
the Trust's reserves.

SAN JUAN BASIN FRUITLAND COAL DRILLING

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, as of December 31, 2000, the working interest owner had
drilled on Trust properties 50 (29.3 net) Fruitland Coal wells, all of which are
operated by the working interest owner. Of the wells drilled in the unit, 49
(34.8 net) are currently producing at a combined rate of 35 (16.1 net) MMcf per
day.

The gas that is currently being produced from these wells is being sold on
the spot market, although the working interest owner 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. 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. 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 portion of the San Juan Basin Royalty
resumed. 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 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 Code. See "Description of the Units--Federal Income Tax
Matters--Section 29 Credit."

RESERVES

A study of the proved oil and gas reserves attributable to the Hugoton
Royalty as of December 31, 2000 have been made by PNR. The following letter
relating to the "Reserves and Revenue as of December 31, 2000 From Certain
Properties Owned by Mesa Royalty Trust" (the "Hugoton Reserve Report")
summarizes such reserve study. References to the reserves of the Trust and the
future net revenue and present worth attributable to the Trust interest in the
Hugoton Reserve Report refer to the Trust's interest in the Hugoton Royalty
Properties. The Hugoton Reserve Report reflects estimated reserve quantities and
future net revenue in a manner which is based upon a month of production without
regard to time of receipt by the Trust and which differs from the manner in
which the Trust recognizes and accounts for its royalty income.

A study of the proved oil and gas reserves attributable to the New Mexico
portion of the San Juan Basin Royalty as of December 31, 2000 has been made by
Conoco, the working interest owner of such properties. The Conoco Reserve Report
(together with the PNR Reserve Report, the "Reserve Reports") beginning on page
11 regarding such properties reflects estimated reserve quantities.

Proved oil and gas reserves attributable to the Colorado portion of the San
Juan Basin Royalty have been omitted from the Trust's reserve disclosures
included in this Form 10-K, as they represent less than 5% of the Trust's total
reserves and future net revenues.

For further information regarding the Net Overriding Royalty Interest, the
Basis of Accounting for the Trust, and Reserves, see Notes 2, 3 and 6,
respectively, in the Notes to Financial Statements under Item 8 of this
Form 10-K.

[LOGO]

Tuesday, February 20, 2001

MESA Royalty Trust
Chase Bank of Texas, N.A. (as Trustee)
Chase Tower, Suite 1150
600 Travis Street
Houston TX 77002

Ladies and Gentlemen:

Pursuant to your request, we have prepared estimates, as of December 31, 2000 of
the extent and value of the proved natural gas liquids, natural gas and helium
reserves of certain properties owned by the Mesa Royalty Trust, hereinafter
referred to as the "Trust." The interest appraised consists of a 10.29282%
(percent) net profits overriding royalty interest in certain properties
administered by Pioneer Natural Resources USA, Inc., hereinafter referred to as
"Pioneer." These properties are located in the Kansas Hugoton and Panoma-Council
Grove fields in Kansas. Pioneer is 100 percent owned by Pioneer Natural
Resources Company, the successor to Mesa Limited Partnership.

The reserve estimates are based on a detailed study of the Trust's properties.
The method or combination of methods used in the study of each reservoir was
tempered by experience in the area, consideration of the state of development of
the reservoir, and the quality and completeness of basic data.

Reserves in this report are expressed as gross reserves and net reserves. Gross
reserves are defined as the total estimated petroleum hydrocarbons remaining to
be produced from the properties subsequent to December 31, 2000. Net reserves
are defined as that portion of the gross reserves attributable to the Trust
interest after deducting royalties and other interests owned by others.

Values shown herein are expressed in terms of future net revenue, future net
cashflow and present worth. Future net revenue is that revenue which will accrue
to the appraised interests from the production and sale of the estimated net
reserves. Future net cashflow is calculated by deducting estimated production
taxes, ad valorem taxes, lease operating expenses, and capital costs from the
future net revenue. Future income tax expenses were not taken into account in
the preparation of these estimates. Present worth is defined as future net
revenue discounted at a specified arbitrary discount rate compounded monthly
over the expected period of realization. In this report, present worth values
are reported using a discount rate of 10% (percent).

Reserve and revenue values shown in this report were estimated from projections
of reserves and revenue attributable to the combined Pioneer and Trust interests
(Combined Interest) in these properties. To calculate the net profits, the
future net revenue for the aggregate of the Combined Interest in the subject
properties was reduced by an overhead charge and by the deficit balance as
described below if any. In addition, because the net profits interest does not
participate in plant and gathering expenses, a portion of the net revenue
attributable to the plant interests was excluded from this calculation; the
excluded portion is 35 percent of the plant revenue less 100 percent of the
plant and gathering expenses. When the adjusted net revenue resulting from this
calculation was greater than zero, it was multiplied by the factor of 10.29282%
(percent) to arrive at the future net revenue of the Trust. If the adjusted
revenue for the period was negative, the trust revenue was set to zero and
interest was charged on the deficit balance. The beginning deficit balance as of
December 31, 2000, was zero and no deficit is estimated for the life of the
properties.

MESA Royalty Trust
Tuesday, February 20, 2001
Page 2

While estimates of reserves attributable to the Trust are shown in order to
comply with requirements of the SEC, this is no precise method of allocating
estimates of physical quantities of reserves between the working interest owners
and the Trust. The net profits overriding royalty interest is not a working
interest and the Trust does not own and is not entitled to receive any specific
volume of reserves from the Trust. Reserve quantities in the previously
mentioned reserve studies have been allocated based on the method referenced in
the Reserve Reports. The quantities of reserves attributable to the Trust will
be affected by future changes in various economic factors utilized in estimating
future gross and net revenues from the Trust Properties. Therefore, the
estimates of reserves set forth in the Reserve Reports are to a large extent
hypothetical and differ in significant respects from estimates of reserves
attributable to a working interest.

Estimates of reserves and future net revenue should be regarded only as
estimates that may change as further production history and additional
information becomes available. Not only are such reserve and revenue estimates
based on that information which is currently available, but such estimates are
also subject to the uncertainties inherent in the application of judgmental
factors in interpreting such information.

The development status shown herein represents the status applicable on December
31, 2000. In our preparation of the study, data available from wells drilled on
the appraised properties through December 31, 2000 were used in estimating gross
ultimate recovery. Gross production estimated to December 31, 2000 was deducted
from gross ultimate recovery to arrive at the estimates of gross reserves as of
December 31, 2000. In these fields, this required that the production rates be
estimated for up to three months, since production data for certain properties
were available only through September 2000.

Petroleum reserves included in this report are classified as proved and are
judged to be economically producible in future years from known reservoirs under
existing economic and operating conditions and assuming continuation of current
regulatory practices using conventional production methods and equipment. In the
analysis, reserves were estimated only to the limit of economic rates of
production under existing economic and operating conditions using prices and
costs as of the date the estimate is made. This included consideration of
changes in existing prices provided only by contractual arrangements but not
including escalations based upon future conditions. The petroleum reserves are
classified as follows:

Proved - Reserves that have been proved to a high degree of certainty by
analysis of the producing history of a reservoir and/or by volumetric analysis
of adequate geological and engineering data. Commercial productivity has been
established by actual production, successful testing, or in certain cases by
favorable core analyses and electrical-log interpretation when the producing
characteristics of the formation are known from nearby fields. Volumetrically,
the structure, areal extent, volume, and characteristics of the reservoir are
well defined by a reasonable interpretation of adequate subsurface well control
and by known continuity of hydrocarbon-saturated material above known fluid
contacts, if any, or above the lowest known structural occurrence of
hydrocarbons.

Developed - Reserves that are recoverable from existing wells with current
operating methods and expenses. Developed reserves include both producing and
non-producing reserves. Estimates of producing reserves assume recovery by
existing wells producing from present completion intervals with normal operating
methods and expenses. Developed non-producing reserves are in reservoirs behind
the casing or at minor depths below the producing zone and are considered proved

MESA Royalty Trust
Tuesday, February 20, 2001
Page 3

by production from other wells in the field, by successful drill-stem tests, or
by core analysis from the particular zones. Non-producing reserves require only
moderate expense to be brought into production.

Undeveloped - Reserves that are recoverable from additional wells yet to be
drilled. Undeveloped reserves are those considered proved for production by
reasonable geological interpretation of adequate subsurface control in
reservoirs that are producing or proved by other wells but are not recoverable
from existing wells. This classification of reserves requires drilling of
additional wells, major deepening of existing wells, or installation of enhanced
recovery or other facilities.

Helium reserves were classified using the same standards as those described in
the foregoing definitions of petroleum reserves. Since it is mixed in and
produced with the natural gas reserves, the term gas as used herein applies to
both gases, where appropriate, and the term natural gas is used to refer to
hydrocarbon gas.

Estimates of the net proved reserves attributable to the Trust, as of December
31, 2000, are as follows:

TOTAL PROVED RESERVES:
Natural Gas (Mcf)....................................... 19,156,486
Helium (Mcf)............................................ 64,145
Natural Gas Liquids (bbl)............................... 999,910

PROVED DEVELOPED RESERVES
Natural Gas (Mcf)....................................... 19,156,486
Helium (Mcf)............................................ 64,145
Natural Gas Liquids (bbl)............................... 999,910

Proved natural gas liquid reserves and helium reserves are included herein for
the Satanta plant, which was completed and placed on stream in the Hugoton field
in Kansas during late 1993.

Future oil and gas producing rates estimated for this report are based on
production rates considering the most recent figures available or, in certain
cases, are based on estimates. The rates used for future production are within
the capacity of the well or reservoir to produce.

Pioneer is continuing to upgrade the well gathering system, which improves
deliverability of the wells. This increase in deliverability and the associated
costs have been incorporated in the estimates included herein.

Gas volumes shown herein are expressed at standard conditions of 60 degrees
Fahrenheit and at 14.65 pounds per square inch absolute. Gross volumes are
reported as wet gas and the net volumes are reported as processed hydrocarbon
sales; however, neither the gross or net volumes were reduced for plant fuel
usage. The value of this fuel is deducted as part of the plant operating costs.

Revenue values in this report were estimated using current prices and costs.
Future prices were estimated using guidelines established by the Securities and
Exchange Commission and the Financial Accounting Standards Board.

The assumptions used for estimating future prices and costs are as follows:

- Natural Gas Prices - Gas prices were held constant for the life of the
properties.

MESA Royalty Trust
Tuesday, February 20, 2001
Page 4

- Natural Gas Liquids and Helium Prices - Natural gas liquids and helium
prices were held constant for the life of the properties.

- Operating and Capital Costs - Estimates of operating costs based on
current costs were used for the life of the properties with no increase in
the future based on inflation. Future capital expenditures were estimated
using 2000 values and were not adjusted for inflation.

The estimated future net revenue, future net cashflow and present worth
discounted at 10% (percent) attributable to the Trust Interest for the life of
the Trust is as follows.

TRUST INTEREST:

Future Net Revenue ($)(1)................................... 247,436,234
Future Lease Operating Expenses ($)......................... 5,269,367
Future Net Production Taxes ($)............................. 6,211,400
Future Net Ad Valorem Taxes ($)............................. 14,783,255
Future Net Overhead Expense ($)............................. 11,837,182
Future Capital Expenditures ($)............................. 751,702
Future Net Cashflow ($)..................................... 208,583,328
Present Worth at 10 Percent ($)(1).......................... 84,416,102

1. Future income tax expenses were not taken into account in the preparation of
these estimates. Approximately 2 percent of the present worth is estimated
to come from helium sales.

In our opinion, the information relating to the estimated proved reserves,
estimated future net revenue from proved reserves, and present worth of
estimated future net revenue from proved reserves of natural gas liquids, and
gas contained in this report has been prepared in accordance with Paragraphs
10-13, 15 and 30(a)-(b) of Statement of Financial Accounting Standards No. 69
(November 1982) of the Financial Accounting Standards Board and Rules
4-10(a)(1)-(13) of Regulation S-X and Rule 302(b) of Regulation S-K of the
Securities and Exchange Commission; provided, however, (I) future income tax
expenses have not been taken into account in estimating the future net revenue
and present worth values set forth herein and (II) minor amounts of revenue from
helium produced with the natural gas are included herein.

To the extent the above enumerated rules, regulations, and statements require
determinations of an accounting or legal nature or information beyond the scope
of this report, we are necessarily unable to express an opinion as to whether
the above-described information is in accordance therewith or sufficient
therefore.

Submitted,

/s/ JOHN PETERS

John Peters

CONOCO INC.
LETTER REPORT
DATED
MARCH 8, 2001
ON
RESERVES AND REVENUE
AS OF
DECEMBER 31, 2000
FROM
CERTAIN PROPERTIES
OWNED BY
MESA ROYALTY TRUST

RANDALL L. DARR
Leader - Reservoir Management P.O. Box 2197
Reservoir Technology Center Houston, Texas 77252
Exploration Production Technology (281) 293-1404

March 8, 2001

Mesa Royalty Trust
Chase Bank of Texas, N.A.
Suite 1150
600 Travis Street
Houston, Texas 77002

Re: MESA ROYALTY TRUST RESERVES AS OF DECEMBER 31, 2000
SAN JUAN BASIN PROPERTIES, NEW MEXICO

Gentlemen:

Pursuant to your request, estimates have been prepared as of December 31,
2000 of the extent and value of proved natural gas, condensate, and natural gas
liquid reserves of certain properties owned by the Mesa Royalty Trust,
hereinafter referred to as "MRT". The MRT interest appraised consists of a
10.29282 percent net royalty interest in certain San Juan Basin properties
administered by Conoco.

Reserves in this report are expressed as Conoco net reserves and MRT net
reserves. Conoco net reserves are defined as Conoco's net share of estimated
petroleum hydrocarbons remaining to be produced from the properties after
December 31, 2000. MRT net reserves are defined as that portion of the Conoco
net reserves attributable to the interest owned by MRT.

Values shown herein are expressed in terms of future revenue, future cash
flow, and present worth. Future revenue is that revenue which will accrue from
production and sale of the estimated net reserves. Future cash flow is
calculated by deducting estimated production and ad valorem taxes, operating and
transportation expenses, capital costs, and abandonment costs from the future
revenue. Federal income taxes are not taken into account in the preparation of
these estimates. Present worth is defined as future cash flow discounted at a
specified discount rate compounded monthly over the expected period of
realization. A discount rate of 10 percent is used in this report.

Reserves attributable to the MRT interest are calculated by allocating to
MRT a portion of the Conoco net reserves based on future cash flow. Because
reserves volumes are estimated using future cash flow, a change in prices or
costs will result in changes of reserves. Therefore, the MRT net reserves will
vary if different price and cost assumptions are used.

Petroleum reserves included in this report are classified as proved and
judged to be economically producible in future years from known reservoirs under
existing economic and operating conditions. Total proved reserves are the sum of
developed and undeveloped reserves. Proved developed reserves are those
recoverable from existing wells with current operating methods and expenses, and
thus require little or no capital expenditure to produce. Proved undeveloped
reserves are those which require major capital expenditures for new wells and/or
facilities. Estimates of the MRT net reserves

2000 Mesa Royalty Trust Reserves
March 8, 2000
Page 2

and production as of December 31, 2000 are tabulated below along with the MRT
net reserves reported last year for comparison.

CONVENTIONAL FRUITLAND COAL TOTAL
MRT NET PROVED RESERVES RESERVOIRS RESERVOIRS ALL RESERVOIRS
SAN JUAN BASIN ------------------- ------------------- -------------------
DEVELOPED--UNDEVELOPED 12/31/99 12/31/00 12/31/99 12/31/00 12/31/99 12/31/00
-------------------------------------- -------- -------- -------- -------- -------- --------

Natural Gas, MMscf.................... 15,243 19,697 957 1,941 16,200 21,638
Condensate, Mbbl...................... 70 90 0 0 70 90
Natural Gas Liquids, Mbbl............. 1,000 1,266 0 0 1,000 1,266

CONVENTIONAL FRUITLAND COAL TOTAL
MRT NET PROVED RESERVES RESERVOIRS RESERVOIRS ALL RESERVOIRS
SAN JUAN BASIN ------------------- ------------------- -------------------
DEVELOPED ONLY 12/31/99 12/31/00 12/31/99 12/31/00 12/31/99 12/31/00
-------------------------------------- -------- -------- -------- -------- -------- --------

Natural Gas, MMscf.................... 14,463 18,689 957 1,941 15,420 20,630
Condensate, Mbbl...................... 65 85 0 0 65 85
Natural Gas Liquids, Mbbl............. 949 1,201 0 0 949 1,201

Total MRT reserves increased in 2000 due to improvements in price. Proved
Developed Behind Pipe and Proved Undeveloped reserves increased in 2000 due to
an increased development plan. Many of the Proved Undeveloped Reserves will be
accessed in 2001 through an active development and re-completion program. The
reserves value reflect natural gas shrinkage of 12.791 percent for conventional
gas reservoirs due to processing and plant fuel use, and an average net back to
producing properties of 61 percent of recovered natural gas liquids. The
Fruitland Coal reservoir has dry gas (no natural gas liquids) and therefore is
not subject to shrinkage due to liquids extraction.

Product prices and operating costs used for yearend 2000 are shown in the
table below, along with those used last year for comparison. Prices and
operating costs are held constant over the life of the properties. The
December 2000 product prices are substantially higher than the December 1999
prices.

PRODUCT PRICES DECEMBER 1999 DECEMBER 2000
-------------- ------------- -------------

Conventional Nat. Gas. $/Mscf............................... 2.33 9.23
Coal Natural Gas, $/Mscf.................................... 1.98 7.90
Condensate, $/Bbl........................................... 21.54 28.62
Natural Gas Liquids, $/Bbl.................................. 12.01 16.39

Revenue and cash flow values in this report are based on product prices for
San Juan Basin effective on December 31, 2000. The gas price excludes a
transportation expense of $0.45 per Mcf for conventional gas and $0.94 per Mcf
for Fruitland Coal gas. The price also excludes combined production and ad
valorem tax rates of 10.6 percent and 9.2 percent of revenue for conventional
and Fruitland Coal gas, respectively. These taxes compare with the 1999 rates of
10.9 percent for conventional gas and 9.5 percent for Fruitland Coal. The taxes
and transportation expenses are also excluded from the annual per well operating
costs tabulated below. Fruitland Coal operating costs on a per well basis were
higher in 2000 than in 1999 due to an extensive effort to maximise production

2000 Mesa Royalty Trust Reserves
March 8, 2000
Page 3

volumes within the tax credit window. An increase in the total number of Net
Active Conventional Completions is due to an active development program.

OPERATING COSTS
NET ACTIVE COMPLETIONS ($/WELL/YEAR)
----------------------- ---------------------
OPERATING COSTS 12/31/99 12/31/00 12/31/99 12/31/00
--------------- ---------- ---------- --------- ---------

Conventional Gas................................ 417 430 17,000 18,900
Fruitland Coal Gas.............................. 35 35 48,800 56,200

A summary of estimated future revenue, taxes, costs, cash flow, and present
worth attributable to CONOCO'S net reserves as of December 31, 2000 is shown in
the table below. The 1999 numbers are included for comparison. All costs are
yearend 2000 estimates and are not adjusted for inflation. Cash flow and present
worth are reported on a before federal income tax (BFIT) basis.

CONVENTIONAL FRUITLAND COAL
RESERVOIRS RESERVOIRS TOTAL ALL RESERVOIRS
-------------------- ------------------- --------------------
CONOCO NET INTEREST SAN JUAN BASIN 12/31/99 12/31/00 12/31/99 12/31/00 12/31/99 12/31/00
---------------------------------- -------- --------- -------- -------- -------- ---------

Future Revenue, M$................. 765,131 2,574,288 58,871 209,579 824,002 2,783,845
Production & Ad Valorem Taxes,
M$............................... 83,399 273,644 5,605 19,218 89,004 292,862
Operating & Transportation Costs,
M$............................... 185,874 284,455 33,670 40,843 219,544 325,298
Abandonment Costs, M$.............. 1,742 2,506 127 171 1,869 2,677
Capital Costs, M$.................. 17,836 20,776 1,055 405 18,891 21,181
Future BFIT Cash Flow, M$.......... 476,280 1,992,885 18,414 148,942 494,694 2,141,827
Deficit Balance, M$................ 0 0 0 0 0 0
Future BFIT Cash Flow Subject to
MRT Interest, M$................. 476,280 1,992,885 18,414 148,942 494,694 2,141,827
Present Worth @ 10%, M$............ 187,405 791,063 14,640 106,012 202,045 897,075

Conoco's future revenues are significantly higher due to the increased
product prices.

Operating costs are higher for both the conventional gas and Fruitland Coal
due to increased transportation and operating costs and the additional operating
expense associated with recovery of the new incremental reserves.

Capital costs are associated with projects required to produce undeveloped
proved reserves and maintain existing production of developed reserves. The
increase in capital for the conventional reservoirs reflects the additional
wells needed to develop the increased proved undeveloped reserves.

2000 Mesa Royalty Trust Reserves
March 8, 2000
Page 4

A summary of estimated future cash flow and present worth attributable to
the MRT interest as of December 31, 2000 is tabulated below along with what was
reported last year for comparison.

CONVENTIONAL FRUITLAND COAL TOTAL
RESERVOIRS RESERVOIRS ALL RESERVOIRS
------------------- ------------------- -------------------
MRT INTEREST (10.29282%) SAN JUAN BASIN 12/31/99 12/31/00 12/31/99 12/31/00 12/31/99 12/31/00
--------------------------------------- -------- -------- -------- -------- -------- --------

Future BFIT Cash Flow, M$............. 49,023 205,124 1,895 15,330 50,918 220,454
Present Worth @ 10%, M$............... 19,289 81,423 1,507 10,912 20,796 92,335

Compared to last year, future cash flow and present worth is higher for
conventional gas and Fruitland Coal, reflecting the increase in product prices.

The information relating to estimated proved reserves (natural gas,
condensate, natural gas liquids), estimated future revenue from proved reserves,
and present worth of cash flow contained in this report has been prepared in
accordance with regulations of the Financial Accounting Standards Board and
Securities and Exchange Commission.

Sincerely,

Randall Darr

There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting the future rates of production and timing of
development expenditures, including many factors beyond the control of the
producer. The preceding reserve data in the Reserve Reports represent estimates
only and should not be construed as being exact. Reserve assessment is a
subjective process of estimating the recovery from underground accumulations of
gas and oil that cannot be measured in an exact way, and estimates of other
persons might differ materially from those of PNR and Conoco. Accordingly,
reserve estimates are often different from the quantities of hydrocarbons that
are ultimately recovered.

While estimates of reserves attributable to the Royalty are shown in order
to comply with requirements of the SEC, there is no precise method of allocating
estimates of physical quantities of reserves between the working interest owners
and the Trust, since the Royalty is not a working interest and the Trust does
not own and is not entitled to receive any specific volume of reserves from the
Royalty. Reserve quantities in the previously mentioned reserve studies have
been allocated based on the method referenced in the Reserve Reports. The
quantities of reserves attributable to the Trust will be affected by future
changes in various economic factors utilized in estimating future gross and net
revenues from the Royalty Properties. Therefore, the estimates of reserves set
forth in the Reserve Reports are to a large extent hypothetical and differ in
significant respects from estimates of reserves attributable to a working
interest.

Moreover, the discounted present values in the Reserve Reports should not be
construed as the current market value of the estimated gas and oil reserves
attributable to the Royalty Properties or the costs that would be incurred to
obtain equivalent reserves, since a market value determination would include
many additional factors. In accordance with applicable regulations of the SEC,
estimated future net revenues were based on current prices and costs, whereas
actual future prices and costs may be materially greater or less. The estimates
in the Reserve Reports use market prices as of the end of the year. These prices
(having a weighted average of $9.85 per Mcf for Hugoton properties and $9.11 per
Mcf for San Juan Basin properties as of December 31, 2000) were held constant
over the estimated life of the Royalty Properties. Such prices were influenced
by seasonal demand for natural gas and may not be the most appropriate or
representative prices to use for estimating future revenues or related reserve
data. The average price of natural gas from the Royalty Properties during 2000
was $2.97 per Mcf, representing a combination of contract prices and spot market
prices.

The future net revenues shown by the Reserve Reports have not been reduced
for costs and expenses of the Trust, which are expected to approximate $50,000
annually. The costs and expenses of the Trust may increase in future years,
depending on the amount of Royalty income, increases in accounting, engineering,
legal and other professional fees and other factors.

Standardized measure at December 31, 2000 was calculated using natural gas
prices of $9.85 per Mcf for Hugoton properties and $9.11 per Mcf for San Juan
properties. Natural gas prices have declined significantly to approximately
$5.00 per Mcf in March 2001; consequently, the discounted future net cash flows
would be significantly reduced if the standardized measure was calculated using
March 2001 prices.

INCOME, PRODUCTION AND AVERAGE PRICES

Reference is made to "Summary of Royalty Income, Production and Average
Prices" under Item 7 of this Form 10-K for information concerning income,
production and prices with respect to the Royalty.

CONTRACTS

HUGOTON FIELD

Natural gas and natural gas liquids produced by PNR from the Hugoton field
and attributable to the Royalty accounted for approximately 63% of the Royalty
income of the Trust during 2000.

PNR has advised the Trust that since June 1, 1995 natural gas produced from
the Hugoton field has generally been sold under short-term and multi-month
contracts at market clearing prices to multiple purchasers including Williams
Energy Supply ("WESCO"), Oneok Gas Marketing, Inc., Amoco Production Company and
Anadarko Energy Services, Inc. PNR has advised the Trust that it expects to
continue to market gas production from the Hugoton field under short-term and
multi-month contracts. Overall market prices received for natural gas from the
Hugoton Royalty Properties were higher in 2000 compared to 1999.

In June 1994, PNR entered into a gas transportation agreement (the "Gas
Transportation Agreement") with Western Resources, Inc. ("WRI") for a primary
term of five years commencing June 1, 1995. This contract has been continued in
effect on a year-to-year being effective June 1, 2000. PNR has extended the
contract to June 1, 2001. Pursuant to the Gas Transportation Agreement, WRI
agreed to compress and transport up to 160 MMcf per day of gas and redeliver
such gas to PNR at the inlet of PNR's Satanta Plant. PNR agreed to pay WRI a fee
of $0.06 per Mcf escalating 4% annually as of June 1, 1996. This Gas
Transportation Agreement was assigned to Midcontinent Market Center.

Allowable rates of production in the Hugoton field are set by the KCC based
on the level of market demand. The Hugoton field allowable for the period
October 1, 2000 through March 31, 2001, was 160.7 billion cubic feet of gas,
compared with 179.6 billion cubic feet of gas during the same period last year.

SAN JUAN BASIN

Natural gas produced from the San Juan Basin field and attributable to the
Royalty accounted for approximately 37% of the Royalty income of the Trust
during 2000. The majority of gas produced from the San Juan Basin is now being
sold on the spot market.

MARKET FOR NATURAL GAS

The amount of cash distributions by the Trust is dependent on, among other
things, the sales prices for natural gas produced from the Royalty Properties
and the quantities of gas sold. The natural gas industry in the United States
during the 1990's has been affected generally by a surplus in natural gas
deliverability compared to demand. Demand for gas declined during this period
due to a number of factors including the implementation of energy conservation
programs, a shift in economic activity away from energy intensive industries and
competition from alternative fuel sources such as residual fuel oil, coal and
nuclear energy. In late 1999 and 2000, demand for natural gas increased as a
result of the increase in clean burning natural gas fired power generation, the
increase in the usage of electrical power fueled by the expanding U.S. economy
and a return to seasonally cold winters. The annual average wellhead price for
natural gas peaked in 1984 at $2.66 per Mcf and declined to $1.55 in 1995.
Annual wellhead prices generally increased to $2.32 per Mcf in 1997, decreased
to $1.94 per Mcf in 1998, increased to $2.08 per Mcf in 1999 then increased
again to $3.35 per Mcf in 2000, according to Natural Gas Monthly published by
the Energy Information Administration of the Department of Energy.

Due to the seasonal nature of demand for natural gas and its effects on
sales prices and production volumes, the amounts of cash distributions by the
Trust may vary substantially on a seasonal basis. Generally, production volumes
and prices are higher during the first and fourth quarters of each calendar year
due primarily to peak demand in these periods. Because of the time lag between
the date on which the working interest owners receive payment for production
from the Royalty Properties and the date on which distributions are made to
unitholders, the seasonality that generally affects production volumes and
prices is generally reflected in distributions to unitholders in later periods.

COMPETITION

The production and sale of gas in the Hugoton field and San Juan Basin areas
is highly competitive, and the working interest owners' competitors in these
areas include the major oil and gas

companies, independent oil and gas concerns, and individual producers and
operators. There are numerous producers in the Hugoton field and the San Juan
Basin areas. The working interest owners have advised the Trust that they
believe that their competitive position in their respective areas is affected by
price, contract terms and quality of service. PNR has also advised the Trust
that it believes that its competitive position in the Hugoton field is enhanced
by virtue of its substantial holdings and ownership and control of its wells,
gathering systems and processing plant. Market conditions in the San Juan Basin
are negatively affected by the fact that most of the gas produced from such
areas is transported on one of only two major pipelines, and the transportation
of such gas is generally controlled by a small number of distribution companies.

REGULATION AND PRICES

GENERAL

The production and sale of natural gas from the Royalty Properties are
affected from time to time in varying degrees by political developments and
federal, state and local laws and regulations. In particular, oil and gas
production operations and economics are, or in the past have been, affected by
price controls, taxes, conservation, safety, environmental and other laws
relating to the petroleum industry, by changes in such laws and by constantly
changing administrative regulations.

FERC REGULATION

In recent years, the FERC has required interstate pipeline companies to
"unbundle" their services. To the extent a pipeline company or its sales
affiliate makes gas sales as a merchant in the future, it does so pursuant to
private contracts in direct competition with all other sellers, such as the
working interest owners. In recent years, the FERC also has pursued a number of
other policy initiatives which could significantly affect the marketing of
natural gas. Several of these initiatives are intended to enhance competition in
natural gas markets, although some, such as "spindowns" of gathering assets, may
have the adverse effect of increasing the cost of doing business on some in the
industry. Generally, the FERC retained its existing tests for determining the
jurisdictional status of offshore facilities, but eased the application of its
jurisdiction over facilities in water depths of 200 meters or more. On
February 9, 2000, the FERC issued Order No. 637, which permits, and in some
cases requires, interstate natural gas pipelines to make certain changes to the
nature of interstate transportation services. In Order No. 637-A, the FERC made
certain clarifying adjustments to the regulations promulgated in Order No. 637.
In Order No. 637-B, the FERC denied all further requests for rehearing. Order
Nos. 637, ET SEQ. currently are pending judicial review. In addition to the
changes implemented through Order No. 637, the FERC has stated that it will
institute a review of its regulatory model in light of the changes in the
natural gas industry. As to all of these recent FERC initiatives, the working
interest owners have advised the Trust that the on-going, or, in some instances,
preliminary evolving nature of these regulatory initiatives makes it impossible
at this time to predict their ultimate impact on the prices, markets or terms of
sale of natural gas related to the Trust.

STATE AND OTHER REGULATION

All of the jurisdictions in which the Trust has an interest in producing oil
and gas properties have statutory provisions regulating the production and sale
of crude oil and natural gas. The regulations often require permits for the
drilling of wells but extend also to the spacing of wells, the prevention of
waste of oil and gas resources, the rate of production, prevention and clean-up
of pollution and other matters. See "Contracts--Hugoton Field" for a discussion
of PNR's allowables in the Hugoton Royalty Properties.

State regulation of gathering facilities generally includes various safety,
environmental, and in some circumstances, non-discriminatory take requirements.
For example, Oklahoma and Kansas have enacted a prohibition against
discriminatory gathering rates. In addition, certain Texas regulatory officials
have expressed interest in evaluating similar rules, but to date no actions have
been taken towards regulatory gathering rates in the state.

ENVIRONMENTAL MATTERS

The working interest owners' operations are subject to numerous federal,
state and local laws and regulations controlling the discharge of materials into
the environment or otherwise relating to the protection of the environment,
including the Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA" or "Superfund"), the Solid Waste Disposal Act, the Clean Air Act,
and the Federal Water Pollution Control Act. These laws and regulations,
including their state counterparts, can impose liability upon the lessee under a
lease for the cost of cleanup of discharged materials resulting from a lessee's
operations or can subject the lessee to liability for damages to natural
resources. Violations of environmental laws, regulations, or permits can result
in civil and criminal penalties as well as potential injunctions curtailing
operations in affected areas and restrictions on the injection of liquids into
the subsurface that may contaminate groundwater. The working interest owners
have advised the Trust that they maintain insurance for costs of cleanup
operations, but they are not fully insured against all such risks. A serious
release of regulated materials could result in the U.S. Department of the
Interior requiring lessees under federal leases to suspend or cease operations
in the affected area. In addition, the recent trend toward stricter standards
and regulations in environmental legislation is likely to continue. For example,
from time to time legislation has been proposed in Congress that would
reclassify certain oil and gas production wastes as "hazardous wastes" which
would subject the handling, disposal and cleanup of these wastes to more
stringent requirements and result in increased operating costs for the Royalty
Properties, as well as the oil and gas industry in general. State initiatives to
further regulate the disposal of oil and gas wastes are also pending in certain
states, and these initiatives could have a similar impact on the Royalty
Properties.

The working interest owners have advised the Trust that they are not
involved in any administrative or judicial proceedings relating to the Royalty
Properties arising under federal, state or local environmental protection laws
and regulations or which would have a material adverse effect on the working
interest owners' financial position or results of operations.

ITEM 2. PROPERTIES.

Reference is made to Item 1 of this Form 10-K.

ITEM 3. LEGAL PROCEEDINGS.

There are no pending legal proceedings to which the Trust is a party.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

There were no matters submitted to a vote of security holders during the
fourth quarter of 2000.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER
MATTERS.

The units of beneficial interest of the Trust are traded on the New York
Stock Exchange--ticker symbol "MTR". The high and low sales prices and
distributions per unit for each quarter in the two years ended December 31,
2000, were as follows:

2000 1999
---------------------------------- ----------------------------------
QUARTER HIGH LOW DISTRIBUTION HIGH LOW DISTRIBUTION
------- -------- -------- ------------ -------- -------- ------------

First........................................ $47.75 $42.25 $0.8794 $44.88 $43.00 $.6503
Second $42.75 $40.00 $0.7682 $46.50 $43.25 $.6478
Third........................................ $40.38 $37.88 $1.2270 $49.00 $45.00 $.7513
Fourth....................................... $42.50 $40.00 $1.4345 $48.25 $47.00 $.9043

At March 23, 2000, the 1,863,590 units outstanding were held by 1,339
unitholders of record.

ITEM 6. SELECTED FINANCIAL DATA.

2000 1999 1998 1997 1996
----------- ----------- ----------- ----------- -----------

Royalty income................ $ 7,960,109 $ 5,475,497 $ 6,209,778 $ 9,287,406 $ 7,669,020
Distributable income.......... $ 8,030,448 $ 5,504,362 $ 6,248,216 $ 9,358,576 $ 7,689,372
Distributable income per
unit........................ $ 4.3091 $ 2.9536 $ 3.3528 $ 5.0218 $ 4.1261
Total assets at year end...... $14,545,212 $14,358,414 $14,902,521 $17,616,866 $18,975,935

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.

LIQUIDITY AND CAPITAL RESOURCES

As discussed under "Description of the Trust" in Item 1 of this Form 10-K,
the Trust's source of cash is the Royalty income received from its share of the
net proceeds from the Royalty Properties. Reference is made to Note 6 in the
Notes to Financial Statements under Item 8 of this Form 10-K for estimates of
future Royalty income attributable to the Royalty.

In accordance with the provisions of the Conveyance, generally all revenues
received by the Trust, net of Trust administrative expenses and the amount of
established reserves, are distributed currently to the unitholders.

FINANCIAL REVIEW

YEARS 2000 AND 1999

The Trust's Royalty income was $7,960,109 in 2000, an increase of
approximately 45%, as compared to $5,475,497 in 1999, primarily as a result of
higher natural gas and natural gas liquids prices.

Royalty income from the Hugoton Royalty Properties was $5,051,072 in 2000,
an increase of approximately 49%, as compared to $3,400,082 in 1999, primarily
as a result of higher natural gas and natural gas liquids prices in 2000.

The average price received for natural gas and natural gas liquids from the
Hugoton Royalty Properties was $3.03 per Mcf and $19.24 per barrel,
respectively, in 2000 as compared to $1.97 per Mcf and $10.24 per barrel,
respectively, in 1999. Net production attributable to the Hugoton Royalty was
1,142,851 Mcf of natural gas and 82,549 barrels of natural gas liquids in 2000
as compared with 1,250,300 Mcf of natural gas and 91,503 barrels of natural gas
liquids in 1999.

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 $2,909,037 in
2000 as compared to $2,075,415 in 1999. The increase in Royalty income was due
primarily to increased natural gas and natural gas liquids prices in 2000. No
Royalty income was received from the San Juan Basin Royalty Properties located
in the state of Colorado in 2000 or 1999, as costs associated with the Fruitland
Coal drilling program on Royalty Properties in that state have not been fully
recovered. The San Juan Basin development drilling program has no effect on
Royalty income or distributions relating to the Hugoton Royalty.

The average price received for natural gas and natural gas liquids, oil and
condensate from the San Juan Basin Royalty Properties was $2.88 per Mcf and
$21.51 per barrel, respectively, in 2000 compared with $1.81 per Mcf and $12.54
per barrel, respectively, in 1999. Net production attributable to the San Juan
Basin Royalty was 677,569 Mcf of natural gas and 44,521 barrels of natural gas
liquids, oil and condensate in 2000 as compared to 865,312 Mcf of natural gas
and 40,606 barrels of natural gas liquids, oil and condensate in 1999.

As more fully discussed in Note 6 of the Notes to Financial Statements
contained in Item 8 of this Form 10-K, production attributable to the Trust's
interest in the Royalty Properties is calculated based on Royalty income
received from the applicable net profits interest owned by the Trust.

YEARS 1999 AND 1998

The Trust's Royalty income was $5,475,497 in 1999, a decrease of
approximately 12%, as compared to $6,209,778 in 1998, primarily as a result of
lower natural gas production and natural gas prices.

Royalty income from the Hugoton Royalty Properties was $3,400,082 in 1999, a
decrease of approximately 20%, as compared to $4,235,415 in 1998, as a result of
both decreased natural gas and natural gas liquids prices and production.

The average price received for natural gas and natural gas liquids from the
Hugoton Royalty Properties was $1.97 per Mcf and $10.24 per barrel,
respectively, in 1999 as compared to $2.10 per Mcf and $10.64 per barrel,
respectively, in 1998. Net production attributable to the Hugoton Royalty was
1,250,300 Mcf of natural gas and 91,503 barrels of natural gas liquids in 1999
as compared with 1,539,202 Mcf of natural gas and 94,275 barrels of natural gas
liquids in 1998.

Royalty income from the San Juan Basin Royalty Properties located in the
state of New Mexico was $2,075,415 in 1999 as compared to $1,974,363 in 1998 due
primarily to an increase in natural gas and natural gas liquids production as
well as an increase in natural gas liquid prices. No Royalty income was received
from Amoco with respect to the San Juan Basin Royalty Properties located in the
state of Colorado in 1999 or 1998 as costs associated with the development
drilling program from Royalty Properties in that state have not been fully
recovered.

The average price received for natural gas and natural gas liquids, oil and
condensate from the San Juan Basin Royalty Properties was $ 1.81 per Mcf and
$12.54 per barrel, respectively, in 1999 compared with $1.92 per Mcf and $11.12
per barrel, respectively, in 1998. Net production attributable to the San Juan
Basin Royalty was 865,312 Mcf of natural gas and 40,606 barrels of natural gas
liquids, oil and condensate in 1999 as compared to 811,007 Mcf of natural gas
and 37,521 barrels of natural gas liquids, oil and condensate in 1998.

SUMMARY OF ROYALTY INCOME, PRODUCTION AND AVERAGE PRICES (UNAUDITED)

HUGOTON SAN JUAN BASIN TOTAL
------------------------- ---------------------------- ----------------------------
OIL, OIL,
CONDENSATE CONDENSATE
NATURAL GAS AND NATURAL AND NATURAL
NATURAL GAS LIQUIDS(2) NATURAL GAS GAS LIQUIDS(2) NATURAL GAS GAS LIQUIDS(2)
----------- ----------- ----------- -------------- ----------- --------------

Year ended December 31, 2000:
The Trust's proportionate share of--
Gross proceeds..................... $4,430,755 $1,588,234 $4,412,109 $1,181,184 $8,842,864 $2,769,418
Less the Trust's proportionate share
of--
Capital costs recovered(1)......... (127,513) -- (826,428) -- (953,941) --
Operating costs.................... (840,404) (1,600,283) (223,545) (2,440,687) (223,545)
Interest on cost carryforward...... -- -- (34,000) -- (34,000) --
----------- ---------- ----------- ---------- ----------- ----------
Royalty income....................... $3,462,838 $1,588,234 $1,951,398 $ 957,639 $5,414,236 $2,545,873
=========== ========== =========== ========== =========== ==========
Average sales price.................. $ 3.03 $ 19.24 $ 2.88 $ 21.51 $ 2.97 $ 20.04
=========== ========== =========== ========== =========== ==========
Net production volumes attributable (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
to the Royalty paid................ 1,142,851 82,549 677,569 44,521 1,820,420 127,070
=========== ========== =========== ========== =========== ==========
Year ended December 31, 1999:
The Trust's proportionate share of--
Gross proceeds..................... $3,382,152 $ 936,991 $3,119,929 $ 683,584 $6,502,081 $1,620,575
Less the Trust's proportionate share
of--
Capital costs recovered(1)......... (32,956) -- (83,475) -- (116,431) --
Operating costs.................... (886,105) -- (1,434,069) (174,383) (2,320,174) (174,383)
Interest on cost carryforward...... -- -- (36,171) -- (36,171) --
----------- ---------- ----------- ---------- ----------- ----------
Royalty income....................... $2,463,091 $ 936,991 $1,566,214 $ 509,201 $4,029,305 $1,446,192
=========== ========== =========== ========== =========== ==========
Average sales price.................. $ 1.97 $ 10.24 $ 1.81 $ 12.54 $ 1.90 $ 10.95
=========== ========== =========== ========== =========== ==========
Net production volumes attributable (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
to the Royalty paid................ 1,250,300 91,503 865,312 40,606 2,115,612 132,109
=========== ========== =========== ========== =========== ==========
Year ended December 31, 1998:
The Trust's proportionate share of--
Gross proceeds..................... $4,315,417 $1,003,090 $3,838,538 $ 594,315 $8,153,955 $1,597,405
Less the Trust's proportionate share
of--
Capital costs recovered(1)......... (76,949) -- (546,352) -- (623,301) --
Operating costs.................... (1,006,143) (1,699,546) (177,086) (2,705,689) (177,086)
Interest on cost carryforward...... -- -- (35,506) -- (35,506) --
----------- ---------- ----------- ---------- ----------- ----------
Royalty income....................... $3,232,325 $1,003,090 $1,557,134 $ 417,229 $4,789,459 $1,420,319
=========== ========== =========== ========== =========== ==========
Average sales price.................. $ 2.10 $ 10.64 $ 1.92 $ 11.12 $ 2.04 $ 10.78
=========== ========== =========== ========== =========== ==========
Net production volumes attributable (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
to the Royalty paid................ 1,539,202 94,275 811,007 37,521 2,350,209 131,796
=========== ========== =========== ========== =========== ==========

For a discussion of the method used to compute the net production volumes in
the table above, see Note 6 in the Notes to Financial Statements.

------------------------

(1) Capital costs recovered represents capital costs incurred during the current
or prior periods to the extent that such costs have been recovered by the
applicable 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
$390,457, $452,188 and $456,377 at December 31, 2000, 1999 and 1998,
respectively, and relate solely to the San Juan Basin Colorado properties.
See "Description of Royalty Properties--San Juan Basin Fruitland Coal
Drilling" for additional information regarding the Fruitland Coal drilling
program.

(2) Gross proceeds attributable to natural gas liquids for the Hugoton and San
Juan Basin properties are net of a volumetric in-kind processing fee
retained by PNR and Conoco, respectively.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

MESA ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME

YEARS ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
---------- ---------- ----------

Royalty income........................................... $7,960,109 $5,475,497 $6,209,778
Interest income.......................................... 97,383 54,911 73,714
General and administrative expenses...................... (27,044) (26,046) (35,276)
---------- ---------- ----------
Distributable income..................................... $8,030,448 $5,504,362 $6,248,216
========== ========== ==========
Distributable income per unit............................ $ 4.3091 $ 2.9536 $ 3.3528
========== ========== ==========

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

DECEMBER 31,
---------------------------
2000 1999
------------ ------------

ASSETS
Cash and short-term investments............................. $ 2,658,110 $ 1,678,624
Interest receivable......................................... 25,199 6,528
Net overriding royalty interests in oil and gas
properties................................................ 42,498,034 42,498,034
Less: accumulated amortization............................ (30,636,131) (29,824,772)
------------ ------------
Total assets................................................ $ 14,545,212 $ 14,358,414
============ ============
LIABILITIES AND TRUST CORPUS
Distributions payable....................................... $ 2,683,309 $ 1,685,152
Trust corpus (1,863,590 units of beneficial interest
authorized and outstanding)............................... 11,861,903 12,673,262
------------ ------------
Total liabilities and trust corpus.......................... $ 14,545,212 $ 14,358,414
============ ============

STATEMENTS OF CHANGES IN TRUST CORPUS

YEARS ENDED DECEMBER 31,
---------------------------------------
2000 1999 1998
----------- ----------- -----------

Trust corpus, beginning of year....................... $12,673,262 $13,889,555 $15,512,726
Distributable income................................ 8,030,448 5,504,362 6,248,216
Distributions to unitholders........................ (8,030,448) (5,504,362) (6,248,216)
Amortization of net overriding royalty interests.... (811,359) (1,216,293) (1,623,171)
----------- ----------- -----------
Trust corpus, end of year............................. $11,861,903 $12,673,262 $13,889,555
=========== =========== ===========

The accompanying notes are an integral part of these financial statements.

MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS

(1) TRUST ORGANIZATION AND PROVISIONS

The Mesa Royalty Trust (the "Trust") was created on November 1, 1979. On
that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership ("MLP")
which was the predecessor to MESA Inc., conveyed to the Trust a 90% net
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 (the "Royalty
Properties"). On April 30, 1991, MLP sold its interests in the Royalty
Properties located in 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 Chase Manhattan Bank (the "Trustee") successor by merger to Chase Bank
of Texas, National Association is trustee for the Trust. The terms of the Mesa
Royalty Trust Indenture (the "Trust Indenture") provide, among other things,
that:

(a) the Trust cannot engage in any business or investment activity or
purchase any assets;

(b) the Royalty can be sold in part or in total for cash upon approval
of the unitholders;

(c) the Trustee can establish cash reserves and borrow funds to pay
liabilities of the Trust and can pledge the assets of the Trust to secure
payment of the borrowings;

(d) the Trustee will make cash distributions to the unitholders in
January, April, July and October each year as discussed more fully in
Note 4;

(e) the Trust will terminate upon the first to occur of the following
events: (i) at such time as the Trust's royalty income for each of two
successive years is less than $250,000 per year or (ii) a vote by the
unitholders in favor of termination. Upon termination of the Trust, the
Trustee will sell for cash all the assets held in the Trust estate and make
a final distribution to unitholders of any funds remaining after all Trust
liabilities have been satisfied; and

(f) PNR, Conoco and Amoco (collectively the "Working Interest Owners")
will reimburse the Trust for 59.34%, 27.45% and 1.77%, respectively, for
general and administrative expenses of the Trust.

MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(2) NET OVERRIDING ROYALTY INTEREST

In accordance with the instruments conveying the Royalty, the Working
Interest Owners will calculate and pay the Trust each month an amount equal to
90% of the net proceeds for the preceding month. The 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 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 the operating and capital
costs incurred.

The initial carrying value of the Royalty represented the net book value
assigned by PNR to the Royalty Properties at the date of transfer to the Trust.
Amortization of the Royalty is computed on a unit-of-production basis and is
charged directly to trust corpus since such amount does not affect distributable
income.

(3) BASIS OF ACCOUNTING

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

This basis for reporting distributable income is considered 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 accounting principles generally accepted
in the United States because, under such principles, royalty income for a month
would be based on net proceeds from production for such month without regard to
when calculated or received and interest income for a month would be calculated
only through the end of such month.

(4) DISTRIBUTIONS TO UNITHOLDERS

Under the terms of the Trust Indenture, the Trustee must distribute to the
unitholders all cash receipts, after paying liabilities and providing for cash
reserves as determined necessary by the Trustee. The amounts distributed are
determined on a monthly basis and are payable to unitholders of record as of the
last business day of each month. 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 the distribution.

MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(5) FEDERAL INCOME TAXES

In a technical advice memorandum dated February 26, 1982, the IRS advised
the Dallas District Director that the Trust is classifiable as a grantor trust
and not as an association taxable as a corporation.

As a grantor trust, the Trust will incur no federal income tax liability.

(6) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

Estimates of the proved oil and gas reserves attributable to the Hugoton
Royalty Properties as of December 31, 2000, 1999 and 1998 are based on reports
prepared by PNR. The estimates were prepared in accordance with guidelines
established by the Securities and Exchange Commission (the "SEC"). Accordingly,
the estimates were based on existing economic and operating conditions. The
reserve volumes and revenue values for the Trust net profits interest were
estimated by allocating to the Trust a portion of the estimated combined net
reserve volumes of the Hugoton Royalty Properties based on future net revenue.
Production volumes are allocated based on royalty income. Because the net
reserve volumes attributable to the Trust net profits interest are estimated
using an allocation of reserve volumes based on estimates of future net revenue,
a change in prices or costs will result in changes in the estimated net reserve
volumes. Therefore, the estimated net reserve volumes attributable to the Trust
net profits interest will vary if different future price and cost assumptions
are used. Only costs necessary to develop and produce existing proved reserve
volumes were assumed in the allocation of reserve volumes to the Royalty.

Estimates of proved oil and gas reserves attributable to the New Mexico
portion of the San Juan Basin Royalty Properties are based on a reserve report
prepared by Conoco. These estimates were prepared in accordance with SEC
regulations and on a basis generally consistent with those used to derive the
oil and gas reserves attributable to the Hugoton Royalty Properties.

Estimates of proved oil and gas reserves attributable to the Colorado
portion of the San Juan Basin Royalty Properties have been omitted from the
Trust's reserve disclosures, as they represent less than 5% of the Trust's total
reserves and future net revenues.

Future prices for natural gas and oil, condensate and natural gas liquids
were based on prices at each year end. Operating costs, production and ad
valorem taxes and future development and abandonment costs were based on current
costs as of each year end, with no escalation.

There are numerous uncertainties inherent in estimating the quantities and
value of proved reserves and in projecting the future rates of production and
timing of expenditures. The reserve data below represent estimates only and
should not be construed as being exact. Moreover, the discounted values should
not be construed as representative of the current market value of the Royalty. A
market value determination would include many additional factors including:
(i) anticipated future oil and gas prices; (ii) the effect of federal income
taxes, if any, on the future royalties; (iii) an allowance for return on
investment; (iv) the effect of governmental legislation; (v) the value of
additional reserves, not considered proved at present, which may be recovered as
a result of further exploration and development activities; and (vi) other
business risks.

Estimates of reserve volumes attributable to the Royalty are shown in order
to comply with requirements of the SEC. There is no precise method of allocating
estimates of physical quantities of reserve volumes between the Working Interest
Owners and the Trust, since the Royalty is not a working interest and the Trust
does not own and is not entitled to receive any specific volume of reserves from

MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(6) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) (CONTINUED)
the Royalty. The quantities of reserves attributable to the Trust have been and
will be affected by changes in various economic factors utilized in estimating
net revenues from the Royalty Properties. Therefore, the estimates of reserve
volumes set forth below are to a large extent hypothetical and differ in
significant respects from estimates of reserves attributable to a working
interest.

The following schedules set forth (i) the estimated net quantities of proved
and proved developed oil, condensate and natural gas liquids and natural gas
reserves attributable to the Royalty, and (ii) the standardized measure of the
discounted future royalty income attributable to the Royalty and the nature of
changes in such standardized measure between years. These schedules are prepared
on the accrual basis, which is the basis on which the Working Interest Owners
maintain their production records and is different from the basis on which the
Royalty is computed. Certain reclassifications have been made to prior year
amounts to conform to the current year presentation.

ESTIMATED QUANTITIES OF PROVED AND PROVED DEVELOPED RESERVES
(UNAUDITED)

OIL,
CONDENSATE
AND NATURAL
GAS LIQUIDS NATURAL GAS
----------- -----------
(BBLS) (MCF)

Proved Reserves:
December 31, 1997......................................... 1,686,509 35,605,125
Revisions to previous estimates......................... 65,215 (1,841,219)
Production.............................................. (131,796) (2,350,209)
--------- ----------
December 31, 1998......................................... 1,619,928 31,413,697
Revisions to previous estimates......................... 484,393 3,314,482
Production.............................................. (132,109) (2,115,612)
--------- ----------
December 31, 1999......................................... 1,972,212 32,612,567
Revisions to previous estimates......................... 510,768 10,066,484
Production.............................................. (127,070) (1,820,420)
--------- ----------
December 31, 2000......................................... 2,355,910 40,858,631
========= ==========
Proved Developed Reserves:
December 31, 1998......................................... 1,591,928 31,019,697
========= ==========
December 31, 1999......................................... 1,916,212 31,833,567
========= ==========
December 31, 2000......................................... 2,285,910 39,850,631
========= ==========

------------------------

- The estimated quantities of proved reserves for oil, condensate and natural
gas liquids include oil and condensate reserves at December 31 of the
respective years as follows: 2000, 90,000 Bbls; 1999, 70,000 Bbls, and 1998,
57,000 Bbls.

- The Hugoton Royalty represents 42%, 46% and 46% of the estimated proved oil,
condensate and natural gas liquids reserves and 47%, 50% and 54% of the
estimated proved natural gas reserves as of December 31 of 2000, 1999 and
1998, respectively.

MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(6) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) (CONTINUED)
STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM
PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM
(UNAUDITED)

DECEMBER 31,
--------------------
2000 1999
--------- --------
(IN THOUSANDS)

The Trust's proportionate share of future gross proceeds.... $ 533,972 $163,887
Less the Trust's proportionate share of--
Future operating costs.................................... (101,727) (54,849)
Future capital costs...................................... (3,207) (2,873)
--------- --------
Future royalty income....................................... 429,038 106,165
Discount at 10% per annum................................... (252,287) (59,470)
--------- --------
Standardized measure of future royalty income from proved
oil and gas reserves...................................... $ 176,751 $ 46,695
========= ========

CHANGES IN THE STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM
PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM
(UNAUDITED)

DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)

Standardized measure at beginning of year................... $ 46,695 $30,204 $ 47,029
-------- ------- --------
Revisions of previous estimates........................... 27,654 5,189 (3,790)
Net changes in price and production costs................. 105,692 13,757 (11,528)
Royalty income............................................ (7,960) (5,475) (6,210)
Accretion of discount..................................... 4,670 3,020 4,703
-------- ------- --------
Net changes in standardized measure....................... 130,056 16,491 (16,825)
-------- ------- --------
Standardized measure at end of year......................... $176,751 $46,695 $ 30,204
======== ======= ========

------------------------

- The Hugoton Royalty represents approximately 48% and 55% of the standardized
measure of future royalty income for 2000 and 1999, respectively.

- Standardized measure at December 31, 2000 was calculated using natural gas
prices of $9.85 per Mcf for Hugoton properties and $9.11 per Mcf for San Juan
properties. Natural gas prices have declined significantly to approximately
$5.00 per Mcf in March 2001; consequently, the discounted future net cash
flows would be significantly reduced if the standardized measure was
calculated using March 2001 prices.

MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(7) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

SUMMARIZED QUARTERLY RESULTS
THREE MONTHS ENDED
----------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------- ---------- ------------ -----------

2000:
Royalty income.............................. $1,621,389 $1,423,595 $2,261,759 $2,653,366
Distributable income........................ $1,638,750 $1,431,676 $2,286,614 $2,673,408
Distributable income per unit............... $ .8794 $ .7682 $ 1.2270 $ 1.4345
1999:
Royalty income.............................. $1,208,881 $1,206,359 $1,376,799 $1,683,458
Distributable income........................ $1,211,895 $1,207,226 $1,400,089 $1,685,152
Distributable income per unit............... $ .6503 $ .6478 $ .7513 $ .9042

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO THE CHASE MANHATTAN BANK (TRUSTEE)
AND THE UNITHOLDERS OF THE MESA ROYALTY TRUST:

We have audited the accompanying statements of assets, liabilities and trust
corpus of the Mesa Royalty Trust as of December 31, 2000 and 1999, and the
related statements of distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 2000. These financial
statements are the responsibility of the Trustee. Our responsibility is to
express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

As described in Note 3, these financial statements were prepared on the
basis of accounting, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of the Mesa
Royalty Trust as of December 31, 2000 and 1999, and its distributable income and
changes in trust corpus for each of the three years in the period ended
December 31, 2000, on the basis of accounting described in Note 3.

ARTHUR ANDERSEN LLP

Houston, Texas
March 23, 2001

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

There are no directors or executive officers of the Registrant. The Trustee
is a corporate trustee which may be removed by the affirmative vote of the
majority at a meeting of the holders of units of beneficial interest of the
Trust at which a quorum is present.

ITEM 11. EXECUTIVE COMPENSATION.

Not applicable.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

(A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS.

The following information has been taken from filings with the Securities
and Exchange Commission on Forms 13D and 13G and Form 4.

AMOUNT AND
NATURE OF PERCENT
TITLE OF CLASS OF NAME AND ADDRESS BENEFICIAL OF
VOTING SECURITIES OF BENEFICIAL OWNER OWNERSHIP(1) CLASS
----------------- ------------------- ------------ --------

Units of Beneficial Interest....... Alpine Capital, L.P.
201 Main Street, Suite 3100
Fort Worth, Texas 76102 781,016(2) 41.9%
Units of Beneficial Interest....... Beck, Mack & Oliver LLC
330 Madison Avenue
New York, NY 10017 296,868(3) 15.9%

------------------------

(1) Under applicable regulations of the Securities and Exchange Commission,
securities are deemed to be "beneficially" owned by a person who directly or
indirectly holds or shares voting power or investment power with respect
thereto.

(2) Information obtained from Schedule 13D Amendment No. 15 dated February 2,
2000 of Alpine Capital, L.P. ("Alpine"), Robert W. Bruce III,
Algenpar, Inc., J. Taylor Crandall, The Anne T. Bass and Robert M. Bass
Foundation, Anne T. Bass and Robert M. Bass, and from Form 4's filed by
Alpine, Mr. Bruce, Algenpar, Inc. and Mr. Crandall dated February 9, 2000.
Alpine directly owns and has sole voting and dispositive power with respect
to all of such units. Such number of units does not include 51,284 units
(which constitutes approximately 2.8% of the 1,863,590 units outstanding)
directly owned by The Anne T. Bass and Robert M. Bass Foundation (the
"Foundation"). Mr. Bruce, by virtue of his position as a general partner of
Alpine and as a principal of The Robert Bruce Management Co. Inc., which has
shared dispositive power with respect to the 51,284 units owned by the
Foundation, may be deemed to be a beneficial owner of the 781,016 units
owned by Alpine and the 51,284 units owned by the Foundation. Mr. Crandall,
by virtue of his position as President and sole stockholder of
Algenpar, Inc., which is one of two general partners of Alpine, and as a
director of the Foundation, may also be deemed to be a beneficial owner of
the 781,016 units owned by Alpine and the 51,284 units owned by the
Foundation.

(3) Information obtained from Schedule 13G dated January 18, 2001 of Beck,
Mack & Oliver LLC ("BMO"). BMO has shared dispositive power with respect to
all of such units. All of such units are owned by the investment advisory
clients of BMO.

(B) SECURITY OWNERSHIP OF MANAGEMENT.

Not applicable.

(C) CHANGES IN CONTROL. Registrant knows of no arrangements, including the
pledge of securities of the Registrant, the operation of which may at a
subsequent date result in a change in control of the Registrant.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

Not applicable.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

(A)(1)FINANCIAL STATEMENTS

The following financial statements are set forth under Part II, Item 8 of
this Annual Report on Form 10-K on the pages indicated.

PAGE IN THIS
FORM 10-K
------------

Statements of Distributable Income.......................... 23
Statements of Assets, Liabilities and Trust Corpus.......... 23
Statements of Changes in Trust Corpus....................... 23
Notes to Financial Statements............................... 24
Report of Independent Public Accountants.................... 30

(A)(2)SCHEDULES

Schedules have been omitted because they are not required, not applicable or
the information required has been included elsewhere herein.

(A)(3)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)

(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 fourth quarter of 2000.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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

March 23, 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.