--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
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, 2001
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD
FROM TO
COMMISSION FILE NUMBER 1-7884
------------------------
MESA ROYALTY TRUST
(Exact Name of Registrant as Specified in Its Charter)
NEW YORK 74-6284806
(State or Other Jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
JPMORGAN CHASE BANK, TRUSTEE
INSTITUTIONAL TRUST SERVICES
700 LAVACA
AUSTIN, TEXAS
(Address of Principal Executive 78701
Offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 1-512-479-2562
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 22, 2002, of $41.60 was approximately $77,525,344.
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 25, 2002, 1,863,590 Units of Beneficial Interest in Mesa Royalty
Trust.
Documents Incorporated By Reference: None.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
TABLE OF CONTENTS
PAGE
--------
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
Principal Trust Risk Factors.............................. 19
Item 2. Properties.................................................. 22
Item 3. Legal Proceedings........................................... 22
Item 4. Submission of Matters to a Vote of Security Holders......... 22
PART II
Item 5. Market for the Registrant's Common Equity and Related
Unitholder Matters.......................................... 23
Item 6. Selected Financial Data..................................... 23
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 23
Summary of Royalty Income, Production and Average Prices
(Unaudited)............................................... 25
Item 8. Financial Statements and Supplementary Data................. 26
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 35
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 35
Item 11. Executive Compensation...................................... 35
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 35
Item 13. Certain Relationships and Related Transactions.............. 36
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 36
SIGNATURES.......................................................................... 37
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. A consolidated
summary description of principal risk factors that could cause actual results to
differ is also set forth in this Form 10-K under "Business--Principal Trust Risk
Factors." 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, JPMorgan Chase Bank
(the "Trustee"), 700 Lavaca, Austin, Texas 78701. The telephone number of the
Trust is 512-479-2562. JPMorgan Chase Bank was formerly known as The Chase
Manhattan Bank and is the successor by mergers to the original name of the
Trustee, Texas Commerce Bank National Association.
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 $10,490,988 and $7,960,109 for the
years 2001 and 2000, 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
1
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 88.56% 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 25, 2002.
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
2
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 JPMorgan
Chase Bank (as the successor by mergers to Texas Commerce Bank National
Association) or the interest rate which JPMorgan Chase 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. Such tax credit will expire January 1, 2003. Each
3
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 30% 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
4
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, 2001
PRODUCING GAS
PRODUCING ACRES(1) WELLS(1)
------------------- -------------------
GROSS NET GROSS NET
-------- -------- -------- --------
Hugoton Area (Kansas)(2).................................... 99,654 99,413 466 465.5
San Juan Basin (Northwestern New Mexico and Southwestern
Colorado)................................................. 40,716 31,328 1,561 464
------- ------- ----- -----
Total..................................................... 140,370 130,741 2,027 929.5
======= ======= ===== =====
------------------------
(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 48% 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 52% 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" under Item 1 of this Form 10-K. The San Juan Basin
Royalty Properties located in Colorado account for less than 5% of the Trust's
reserves.
5
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, 2001, 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. However, those tax credits will expire on
January 1, 2003. See "--Description of the Units--Federal Income Tax Matters--
Section 29 Credit" under Item 1 of this Form 10-K.
RESERVES
A study of the proved oil and gas reserves attributable to the Hugoton
Royalty as of December 31, 2001 have been made by PNR. The following letter
relating to the "Reserves and Revenue as of December 31, 2001 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, 2001 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 7,
respectively, in the Notes to Financial Statements under Item 8 of this
Form 10-K.
6
[PIONEER LOGO]
March 19, 2002
MESA Royalty Trust
JP Morgan Chase (as Trustee)
700 Lavaca Street, 5th Floor
Austin, TX 78701-3102
Ladies and Gentlemen:
Pursuant to your request, we have prepared estimates, as of December 31, 2001
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, 2001.
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, 2001, was zero and no deficit is estimated
for the life of the properties.
7
MESA Royalty Trust
March 19, 2002
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, 2001. In our preparation of the study, data available from wells drilled on
the appraised properties through December 31, 2001 were used in estimating gross
ultimate recovery. Gross production estimated to December 31, 2001 was deducted
from gross ultimate recovery to arrive at the estimates of gross reserves as of
December 31, 2001. 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 2001.
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
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.
8
MESA Royalty Trust
March 19, 2002
Page 3
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, 2001, are as follows:
TOTAL PROVED RESERVES:
Natural Gas (Mcf)...............................13,643,072
Helium (Mcf)........................................46,405
Natural Gas Liquids (bbl)..........................709,580
PROVED DEVELOPED RESERVES
Natural Gas (Mcf)...............................13,643,072
Helium (Mcf)........................................46,405
Natural Gas Liquids (bbl)..........................709,580
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:
o Natural Gas Prices - Gas prices were held constant for the life of the
properties.
o Natural Gas Liquids and Helium Prices - Natural gas liquids and helium
prices were held constant for the life of the properties.
o 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 2001 values and were not adjusted for inflation.
9
MESA Royalty Trust
March 19, 2002
Page 4
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 .............................. 66,345,805
Future Lease Operating Expenses ($) .................. 4,799,166
Future Net Production Taxes ($) ...................... 1,638,422
Future Net Ad Valorem Taxes ($) ...................... 3,963,887
Future Net Overhead Expense ($) ...................... 11,457,508
Future Capital Expenditures ($) ...................... 99,490
Future Net Cashflow ($) .............................. 44,387,297
Present Worth at 10 Percent ($)1 ..................... 19,513,586
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- 1
0(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
10
CONOCO INC.
LETTER REPORT
Dated
MARCH 22, 2002
on
RESERVES and REVENUE
as of
DECEMBER 31, 2001
from
CERTAIN PROPERTIES
owned by
MESA ROYALTY TRUST
11
[CONOCO LETTERHEAD]
RANDALL L. DARR P. O. Box 2197
Leader - Reservoir Management Houston, Texas 77252
Reservoir Technology Center (281) 293-1404
Exploration Production Technology
March 22, 2002
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, 2001
SAN JUAN BASIN PROPERTIES, NEW MEXICO
Gentlemen:
Pursuant to your request, estimates have been prepared as of December 31, 2001
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, 2001. 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.
12
2001 Mesa Royalty Trust Reserves
March 22, 2002
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 that require major capital expenditures for new wells and/or
facilities. Estimates of the MRT net reserves and production as of December 31,
2001 are tabulated below. The MRT net reserves and production reported for the
previous year are included for comparison.
===============================================================================================================================
MRT NET PROVED RESERVES
SAN JUAN BASIN CONVENTIONAL FRUITLAND COAL TOTAL
DEVELOPED + UNDEVELOPED RESERVOIRS RESERVOIRS ALL RESERVOIRS
-------------------------------------------------------------------------------------------------------------------------------
12/31/00 12/31/01 12/31/00 12/31/01 12/31/00 12/31/01
-------------------------------------------------------------------------------------------------------------------------------
Natural Gas, MMscf 19,697 13,700 1,941 448 21,638 14,148
-------------------------------------------------------------------------------------------------------------------------------
Condensate, Mbbl 90 56 0 0 90 56
-------------------------------------------------------------------------------------------------------------------------------
Natural Gas Liquids, Mbbl 1,266 882 0 0 1,266 882
===============================================================================================================================
===============================================================================================================================
MRT NET PROVED RESERVES CONVENTIONAL FRUITLAND COAL TOTAL
SAN JUAN BASIN
DEVELOPED ONLY RESERVOIRS RESERVOIRS ALL RESERVOIRS
-------------------------------------------------------------------------------------------------------------------------------
12/31/00 12/31/01 12/31/00 12/31/01 12/31/00 12/31/01
-------------------------------------------------------------------------------------------------------------------------------
Natural Gas, MMscf 18,689 13,113 1,941 448 20,630 13,561
-------------------------------------------------------------------------------------------------------------------------------
Condensate, Mbbl 85 56 0 0 85 56
-------------------------------------------------------------------------------------------------------------------------------
Natural Gas Liquids, Mbbl 1,201 844 0 0 1,201 844
===============================================================================================================================
Both MRT Proved Developed and Proved Undeveloped reserves decreased in 2001 due
to impairments in price. Many of the Proved Undeveloped Reserves will be
accessed in 2002 through an active development and re-completion program. The
reserves values reflect natural gas shrinkage of 12.875 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 2001 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 2001
product prices are substantially lower than the December 2000 prices.
===============================================================================
PRODUCT PRICES DECEMBER 2000 DECEMBER 2001
--------------------------------------------------------------------------------
Conventional Nat. Gas, $/Mscf 9.23 2.23
--------------------------------------------------------------------------------
Coal Natural Gas, $/Mscf 7.90 1.89
--------------------------------------------------------------------------------
Condensate, $/Bbl 28.62 15.67
--------------------------------------------------------------------------------
Natural Gas Liquids, $/Bbl 16.39 6.69
===============================================================================
13
2001 Mesa Royalty Trust Reserves
March 22, 2002
Revenue and cash flow values in this report are based on product prices for San
Juan Basin effective on December 31, 2001. The gas price excludes a
transportation expense of $0.28 per Mcf for conventional gas and $0.65 per Mcf
for Fruitland Coal gas. The price also excludes combined production and ad
valorem tax rates of 10.5 percent and 9.2 percent of revenue for conventional
and Fruitland Coal gas, respectively. These taxes compare with the 2000 rates of
10.6 percent for conventional gas and 9.2 percent for Fruitland Coal. The taxes
and transportation expenses are also excluded from the annual per well operating
costs tabulated below. Fruitland Coal operating costs on a per well basis were
higher in 2001 than in 2000 due to an extensive effort by partners to maximize
production volumes within the tax credit window.
==================================================================================================================
OPERATING COSTS NET ACTIVE OPERATING COSTS
COMPLETIONS ($/WELL/YEAR)
------------------------------------------------------------------------------------------------------------------
12/31/00 12/31/01 12/31/00 12/31/01
------------------------------------------------------------------------------------------------------------------
Conventional Gas 430 429 18,900 18,300
------------------------------------------------------------------------------------------------------------------
Fruitland Coal Gas 35 35 56,200 71,800
==================================================================================================================
A summary of estimated future revenue, taxes, costs, cash flow, and present
worth attributable to CONOCO'S net reserves as of December 31, 2001 is shown in
the table below. The 2000 numbers are included for comparison. All costs are
yearend 2001 estimates and are not adjusted for inflation. Cash flow and present
worth are reported on a before federal income tax (BFIT) basis.
=================================================================================================================================
CONOCO NET INTEREST CONVENTIONAL FRUITLAND COAL TOTAL
SAN JUAN BASIN RESERVOIRS RESERVOIRS ALL RESERVOIRS
------------------------------------------------------------------------------------
12/31/00 12/31/01 12/31/00 12/31/01 12/31/00 12/31/01
---------------------------------------------------------------------------------------------------------------------------------
Future Revenue, M$ 2,574,266 686,443 209,579 42,985 2,783,845 729,428
---------------------------------------------------------------------------------------------------------------------------------
Production & Ad Valorem Taxes, M$ 273,644 72,171 19,218 3,944 292,862 76,115
---------------------------------------------------------------------------------------------------------------------------------
Operating & Transportation Costs, M$ 284,455 229,102 40,843 30,097 325,298 259,199
---------------------------------------------------------------------------------------------------------------------------------
Abandonment Costs, M$ 2,506 2,395 171 175 2,677 2,570
---------------------------------------------------------------------------------------------------------------------------------
Capital Costs, M$ 20,776 20,779 405 568 21,181 21,347
---------------------------------------------------------------------------------------------------------------------------------
Future BFIT Cash Flow, M$ 1,992,885 361,996 148,942 8,201 2,141,827 370,197
---------------------------------------------------------------------------------------------------------------------------------
Deficit Balance, M$ 0 0 0 0 0 0
---------------------------------------------------------------------------------------------------------------------------------
Future BFIT Cash Flow Subject to
---------------------------------------------------------------------------------------------------------------------------------
MRT Interest, M$ 1,992,885 361,996 148,942 8,201 2,141,827 370,197
---------------------------------------------------------------------------------------------------------------------------------
Present Worth @ 10%, M$ 791,063 147,770 106,012 6,326 897,075 154,096
=================================================================================================================================
Conoco's future revenues are significantly lower due to the reduced product
prices.
Operating and transportation costs are lower for both the conventional gas and
Fruitland Coal gas due to reduced transportation costs.
Capital costs are associated with projects required to maintain existing
production of developed reserves and to produce undeveloped proved reserves. The
relatively
14
2001 Mesa Royalty Trust Reserves
March 22, 2002
unchanged capital costs for the conventional and Fruitland coal reservoirs
reflect a consistent inventory of proved undeveloped reserves.
A summary of estimated future cash flow and present worth attributable to the
MRT interest as of December 31, 2001 is tabulated below, along with what was
reported last year for comparison.
===============================================================================================================================
MRT INTEREST (10.29282%) CONVENTIONAL FRUITLAND TOTAL
SAN JUAN BASIN RESERVOIRS COAL RESERVOIRS ALL RESERVOIRS
---------------------------------------------------------------------------------------
12/31/00 12/31/01 12/31/00 12/31/01 12/31/00 12/31/01
-------------------------------------------------------------------------------------------------------------------------------
Future BFIT Cash Flow, M$ 205,124 37,260 15,330 844 220,454 38,104
-------------------------------------------------------------------------------------------------------------------------------
Present Worth @ 10%, M$ 81,423 15,210 10,912 651 92,335 15,861
===============================================================================================================================
Compared to last year, future cash flow and present worth are lower for the
conventional gas and the Fruitland Coal gas, reflecting the decrease 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,
/s/ RANDALL DARR
Randall Darr
15
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 $2.58 per Mcf for Hugoton properties and $2.22 per
Mcf for San Juan Basin properties as of December 31, 2001) were held constant
over the estimated life of the Royalty Properties. These 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 2001
was $4.59 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.
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 67% of the Royalty
income of the Trust during 2001.
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.
16
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, 2001. PNR has extended the
contract to June 1, 2002. 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, 2001 through March 31, 2002, was 149 billion cubic feet of gas,
compared with 160.7 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 33% of the Royalty income of the Trust
during 2001. 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 was 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 2000 and in early 2001, 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,
increased to $3.69 per Mcf in 2000, then increased again to $4.12 per Mcf in
2001, 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
17
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,
18
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.
PRINCIPAL TRUST RISK FACTORS
Although risk factors are described elsewhere in this Form 10-K together
with specific Cautionary Statements, the following is a summary of the principal
risks associated with an investment in units in the Trust.
NATURAL GAS PRICES FLUCTUATE DUE TO A NUMBER OF FACTORS, AND LOWER PRICES WILL
REDUCE NET PROCEEDS AVAILABLE TO THE TRUST AND DISTRIBUTIONS TO TRUST
UNITHOLDERS.
The Trust's quarterly distributions are highly dependent upon the prices
realized from the sale of natural gas. Natural gas prices can fluctuate widely
on a month-to-month basis in response to a variety of factors that are beyond
the control of the Trust and the working interest owners. Factors that
contribute to price fluctuation include, among others:
- political conditions in the Middle East;
- worldwide economic conditions;
- weather conditions;
- the supply and price of foreign natural gas;
- the level of consumer demand;
- the price and availability of alternative fuels;
- the proximity to, and capacity of, transportation facilities; and
- the effect of worldwide energy conservation measures.
Moreover, government regulations, such as regulation of natural gas
transportation and price controls, can affect product prices in the long term.
Lower natural gas prices may reduce the amount of natural gas that is
economic to produce and reduce net profits available to the Trust. The
volatility of energy prices reduces the predictability of future cash
distributions to unitholders. Substantially all of the natural gas and natural
gas liquids produced from the Royalty Properties is being sold under short-term
or multi-month contracts at market clearing prices or on the spot market.
19
INCREASED PRODUCTION AND DEVELOPMENT COSTS FOR THE ROYALTY WILL RESULT IN
DECREASED TRUST DISTRIBUTIONS.
Production and development costs attributable to the Royalty are deducted in
the calculation of the Trust's share of net proceeds. Accordingly, higher or
lower production and development costs, without concurrent increases in
revenues, directly decrease or increase the amount received by the Trust for the
Royalty.
If development and production costs of the Royalty exceed the proceeds of
production from the Royalty Properties, the Trust will not receive net proceeds
for those properties until future proceeds from production exceed the total of
the excess costs plus accrued interest during the deficit period. Development
activities may not generate sufficient additional revenue to repay the costs.
TRUST RESERVE ESTIMATES DEPEND ON MANY ASSUMPTIONS THAT MAY PROVE TO BE
INACCURATE, WHICH COULD CAUSE BOTH ESTIMATES RESERVES AND ESTIMATED FUTURE
REVENUES TO BE TOO HIGH.
The value of the units of beneficial interest of the Trust depends upon,
among other things, the amount of reserves attributable to the Royalty and the
estimated future value of the reserves. Estimating reserves is inherently
uncertain. Ultimately, actual production, revenues and expenditures for the
underlying properties will vary from estimates and those variations could be
material. Petroleum engineers consider many factors and make assumptions in
estimating reserves. Those factors and assumptions include:
- historical production from the area compared with production rates from
similar producing areas;
- the assumed effect of governmental regulation; and
- assumptions about future commodity prices, production and development
costs, severance and excise taxes, and capital expenditures.
Changes in these assumptions can materially change reserve estimates.
The reserve quantities attributable to the Royalty and revenues are based on
estimates of reserves and revenues for the underlying properties. The method of
allocating a portion of those reserves to the Trust is complicated because the
Trust holds an interest in the Royalty and does not own a specific percentage of
the natural gas reserves.
OPERATING RISKS FOR THE WORKING INTEREST OWNERS' INTERESTS IN THE ROYALTY
PROPERTIES CAN ADVERSELY AFFECT TRUST DISTRIBUTIONS.
The occurrence of drilling, production or transportation accidents at any of
the Royalty Properties will reduce Trust distributions by the amount of
uninsured costs. These accidents may result in personal injuries, property
damage, damage to productive formations or equipment and environmental damages.
Any uninsured costs would be deducted as a production cost in calculating net
proceeds payable to the Trust.
Most of the gas produced in the San Juan Basin is transported on one of only
two major pipelines in the area, and transportation of this gas is generally
controlled by a small number of distribution companies. Accordingly, any
disruptions to transportation lines or increases in transportation costs for
production from these properties could also affect the Trust.
NONE OF THE TRUSTEE, THE TRUST NOR ITS UNITHOLDERS CONTROL THE OPERATION OR
DEVELOPMENT OF THE ROYALTY PROPERTIES AND HAVE LITTLE INFLUENCE OVER OPERATION
OR DEVELOPMENT.
Neither the Trustee nor the unitholders can influence or control the
operation or future development of the underlying properties. The Royalty
Properties are owned by independent working
20
interest owners. The working interest owners manage the underlying properties
and handle receipt and payment of funds relating to the Royalty Properties and
payments to the Trust for the Royalty.
The current working interest owners are under no obligation to continue
operating the properties. Neither the Trustee nor the unitholders have the right
to replace an operator.
THE OWNER OF ANY ROYALTY PROPERTY MAY ABANDON ANY PROPERTY, TERMINATING THE
RELATED ROYALTY.
The working interest owners may at any time transfer all or part of the
Royalty Property to another unrelated third party. Unitholders are not entitled
to vote on any transfer, and the Trust will not receive any proceeds of any such
transfer. Following any transfer, the Royalty Properties will continue to be
subject to the Royalty, but the net proceeds from the transferred property would
be calculated separately and paid by the transferee. The transferee would be
responsible for all of the obligations relating to calculating, reporting and
paying to the Trust the Royalty on the transferred portion of the Royalty
Properties, and the current owner of the Royalty Properties would have no
continuing obligation to the Trust for those properties.
The current working interest owners or any transferee may abandon any well
or property if it reasonably believes that the well or property can no longer
produce in commercially economic quantities. This could result in termination of
the Royalty relating to the abandoned well.
THE ROYALTY CAN BE SOLD AND THE TRUST CAN BE TERMINATED.
The Trust will be terminated and the Trustee must sell the Royalty if
holders of a majority of the units of beneficial interest of the Trust approve
the sale or vote to terminate the Trust, or if the Trust's royalty income for
each of two successive years is less than $250,000 per year. Following any such
termination and liquidation, the net proceeds of any sale will be distributed to
the unitholders and unitholders will receive no further distributions from the
Trust. We cannot assure you that any such sale will be on terms acceptable to
all unitholders.
TRUST ASSETS ARE DEPLETING ASSETS AND, IF THE WORKING INTEREST OWNERS OR OTHER
OPERATORS OF THE ROYALTY PROPERTIES DO NOT PERFORM ADDITIONAL DEVELOPMENT
PROJECTS, THE ASSETS MAY DEPLETE FASTER THAN EXPECTED.
The net proceeds payable to the Trust are derived from the sale of depleting
assets. Accordingly, the portion of the distributions to unitholders
attributable to depletion may be considered a return of capital. The reduction
in proved reserve quantities is a common measure of depletion. Future
maintenance and development projects on the Royalty Properties will affect the
quantity of proved reserves. The timing and size of these projects will depend
on the market prices of natural gas. If operators of the Royalty Properties do
not implement additional maintenance and development projects, the future rate
of production decline of proved reserves may be higher than the rate currently
expected by the Trust. For federal income tax purposes, depletion is reflected
as a deduction, which is dependent upon the purchase price of a unit. Please see
the section entitled "--Description of the Units--Federal Income Tax Matters"
under Item 1 of this Form 10-K.
UNITHOLDERS HAVE LIMITED VOTING RIGHTS.
Voting rights as a unitholder are more limited than those of stockholders of
most public corporations. For example, there is no requirement for annual
meetings of unitholders or for an annual or other periodic re-election of the
Trustee. Unlike corporations which are generally governed by boards of directors
elected by their equity holders, the Trust is administered by a corporate
Trustee in accordance with the Trust Indenture and other organizational
documents. The Trustee has extremely limited discretion in its administration of
the Trust.
21
UNITHOLDERS HAVE LIMITED ABILITY TO ENFORCE THE TRUST'S RIGHTS AGAINST THE
CURRENT OR FUTURE OWNERS OF THE ROYALTY PROPERTIES.
The Trust Agreement and related trust law permit the Trustees and the Trust
to sue the working interest owners to compel them to fulfill the terms of the
Conveyance of the Royalty. If the Trustee does not take appropriate action to
enforce provisions of the Conveyance, the recourse of a unitholder would likely
be limited to bringing a lawsuit against the Trustee to compel the Trustee to
take specified actions. Unitholders probably would not be able to sue the
working interest owners directly.
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 named party.
However, PNR has informed the Trust that PNR is party to a 1993 class action
lawsuit filed in the 26th Judicial District Court of Stevens County, Kansas by
two classes of royalty owners, one for each of PNR's gathering systems connected
to the PNR Satanta gas plant. The case was relatively inactive for several
years. In early 2000, the plaintiffs amended their pleadings to add claims
regarding the field compression installed by PNR in the 1990's. The lawsuit now
has two material claims. First, the plaintiffs assert that the expenses related
to the field compression are a "cost of production" for which plaintiffs cannot
be charged their proportionate share under the applicable oil and gas leases,
which include Royalty properties. Second, the plaintiffs claim they are entitled
to 100 percent of the value of the helium extracted at PNR's Satanta gas plant.
If the plaintiffs were to prevail on the above two claims in their entirety, PNR
believes it is possible that PNR's liability could reach $25 million, plus
prejudgment interest. The Trust's share of this amount would be approximately
$1.3 million, plus prejudgment interest. However, PNR believes it has valid
defenses to plaintiff's claims, has paid the plaintiffs properly under their
respective oil and gas leases, and intends to vigorously defend itself.
PNR believes the cost of the field compression is not a "cost of
production", but is rather an expense of transporting the gas to PNR's Satanta
gas plant for processing, where valuable hydrocarbon liquids and helium are
extracted from the gas. The plaintiffs benefit from such extractions and PNR
believes that charging the plaintiffs with their proportionate share of such
transportation and processing expenses is consistent with Kansas law. PNR has
also vigorously defended against plaintiffs' claims to 100 percent of the value
of the helium extracted, and believes that in accordance with applicable law, it
has properly accounted to the plaintiffs for their fractional royalty share of
the helium under the specified royalty clauses of the respective oil and gas
leases.
The factual evidence in the case was presented to the 26th Judicial District
Court without a jury in December 2001. No judgment or findings have been
entered, and PNR expects oral arguments to be set in the second quarter of 2002.
Judgment could be entered anytime after that time. PNR has stated that it
strongly denies the existence of any material underpayment to plaintiffs and
believes it presented strong evidence at trial to support its positions. PNR has
not yet determined the amount of damages, if any, that would be payable if the
lawsuit was determined adversely to PNR. However, the amount of any resulting
liability could have a material adverse effect on the Trust for the period in
which such liability is recorded and during any periods required for PNR to
recoup any additional amounts.
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 2001.
22
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,
2002, were as follows:
2001 2000
---------------------------------- ----------------------------------
QUARTER HIGH LOW DISTRIBUTION HIGH LOW DISTRIBUTION
------- -------- -------- ------------ -------- -------- ------------
First........................................ $57.00 $40.76 $2.0757 $47.75 $42.25 $ 0.8794
Second $57.50 $45.50 $1.9034 $42.75 $40.00 $ 0.7682
Third........................................ $47.25 $39.10 $1.0623 $40.38 $37.88 $ 1.2270
Fourth....................................... $43.00 $36.75 $0.6288 $42.50 $40.00 $ 1.4345
At March 19, 2002, the 1,863,590 units outstanding were held by 1,276
unitholders of record.
ITEM 6. SELECTED FINANCIAL DATA.
2001 2000 1999 1998 1997
----------- ----------- ----------- ----------- -----------
Royalty income................ $10,490,988 $ 7,960,109 $ 5,475,497 $ 6,209,778 $ 9,287,406
Distributable income.......... $10,566,751 $ 8,030,448 $ 5,504,362 $ 6,248,216 $ 9,358,576
Distributable income per
unit........................ $ 5.6701 $ 4.3091 $ 2.9536 $ 3.3528 $ 5.0218
Total assets at year end...... $12,037,014 $14,545,212 $14,358,414 $14,902,521 $17,616,866
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 7 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 2001 AND 2000
The Trust's Royalty income was $10,490,988 in 2001, an increase of
approximately 32%, as compared to $7,960,109 in 2000, primarily as a result of
higher natural gas and natural gas liquids prices in early 2001.
Royalty income from the Hugoton Royalty Properties was $7,034,366 in 2001,
an increase of approximately 39%, as compared to $5,051,072 in 2000, primarily
as a result of higher natural gas and natural gas liquids prices in early 2001.
The average price received for natural gas and natural gas liquids from the
Hugoton Royalty Properties was $4.82 per Mcf and $21.91 per barrel,
respectively, in 2001 as compared to $3.03 per Mcf and $19.24 per barrel,
respectively, in 2000. Net production attributable to the Hugoton Royalty was
1,151,003 Mcf of natural gas and 67,847 barrels of natural gas liquids in 2001
as compared with 1,142,851 Mcf of natural gas and 82,549 barrels of natural gas
liquids in 2000.
23
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 $3,456,622 in
2001 as compared to $2,909,037 in 2000. The increase in Royalty income was due
primarily to increased natural gas and natural gas liquids prices in 2001. No
Royalty income was received from the San Juan Basin Royalty Properties located
in the state of Colorado in 2001 or 2000, 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 $4.21 per Mcf and
$22.15 per barrel, respectively, in 2001 compared with $2.88 per Mcf and $21.51
per barrel, respectively, in 2000. Net production attributable to the San Juan
Basin Royalty was 592,443 Mcf of natural gas and 43,451 barrels of natural gas
liquids, oil and condensate in 2001 as compared to 677,569 Mcf of natural gas
and 44,521 barrels of natural gas liquids, oil and condensate in 2000.
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.
24
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, 2001:
The Trust's proportionate share of--
Gross proceeds..................... $6,644,453 $1,488,517 $5,804,245 $ 1,259,488 $12,448,698 $ 2,748,005
Less the Trust's proportionate share
of--
Capital costs recovered(1)......... (68,052) -- (1,305,601) -- (1,373,653) --
Operating costs.................... (1,028,567) (1,985) (1,982,194) (297,053) (3,010,761) (299,038)
Interest on cost carryforward...... -- -- (22,263) -- (22,263) --
----------- ---------- ----------- ----------- ------------ -----------
Royalty income....................... $5,547,834 $1,486,532 $2,494,187 $ 962,435 $ 8,042,021 $ 2,448,967
=========== ========== =========== =========== ============ ===========
Average sales price.................. $ 4.82 $ 21.91 $ 4.21 $ 22.15 $ 4.59 $ 22.00
=========== ========== =========== =========== ============ ===========
Net production volumes attributable (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
to the Royalty paid................ 1,151,003 67,847 592,443 43,451 1,743,446 111,298
=========== ========== =========== =========== ============ ===========
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
=========== ========== =========== =========== ============ ===========
For a discussion of the method used to compute the net production volumes in
the table above, see Note 3 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
$255,551, $390,457 and $452,188 at December 31, 2001, 2000 and 1999,
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.
25
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
MESA ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
YEARS ENDED DECEMBER 31,
-------------------------------------
2001 2000 1999
----------- ---------- ----------
Royalty income.......................................... $10,490,988 $7,960,109 $5,475,497
Interest income......................................... 103,129 97,383 54,911
General and administrative expenses..................... (27,366) (27,044) (26,046)
----------- ---------- ----------
Distributable income.................................... $10,566,751 $8,030,448 $5,504,362
=========== ========== ==========
Distributable income per unit........................... $ 5.6701 $ 4.3091 $ 2.9536
=========== ========== ==========
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
DECEMBER 31,
---------------------------
2001 2000
------------ ------------
ASSETS
Cash and short-term investments............................. $ 1,167,273 $ 2,658,110
Interest receivable......................................... 4,475 25,199
Net overriding royalty interests in oil and gas
properties................................................ 42,498,034 42,498,034
Less: accumulated amortization............................ (31,632,768) (30,636,131)
------------ ------------
Total assets................................................ $ 12,037,014 $ 14,545,212
============ ============
LIABILITIES AND TRUST CORPUS
Distributions payable....................................... $ 1,171,748 $ 2,683,309
Trust corpus (1,863,590 units of beneficial interest
authorized and outstanding)............................... 10,865,266 11,861,903
------------ ------------
Total liabilities and trust corpus.......................... $ 12,037,014 $ 14,545,212
============ ============
STATEMENTS OF CHANGES IN TRUST CORPUS
YEARS ENDED DECEMBER 31,
---------------------------------------
2001 2000 1999
----------- ----------- -----------
Trust corpus, beginning of year....................... $11,861,903 $12,673,262 $13,889,555
Distributable income................................ 10,566,751 8,030,448 5,504,362
Distributions to unitholders........................ (10,566,751) (8,030,448) (5,504,362)
Amortization of net overriding royalty interests.... (996,637) (811,359) (1,216,293)
----------- ----------- -----------
Trust corpus, end of year............................. $10,865,266 $11,861,903 $12,673,262
=========== =========== ===========
The accompanying notes are an integral part of these financial statements.
26
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.
JPMorgan Chase Bank is trustee for the Trust (the "Trustee"). JPMorgan Chase
Bank was formerly known as The Chase Manhattan Bank, and is the successor by
mergers to the original name of the Trustee, Texas Commerce Bank National
Association. 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.
27
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
(c) Trust general and administrative expenses, net of reimbursements,
are recorded in the month they accrue.
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.
28
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) PNR LEGAL PROCEEDINGS
PNR has informed the Trust that PNR is party to a 1993 class action lawsuit
filed in the 26th Judicial District Court of Stevens County, Kansas by two
classes of royalty owners, one for each of PNR's gathering systems connected to
the PNR Satanta gas plant. The case was relatively inactive for several years.
In early 2000, the plaintiffs amended their pleadings to add claims regarding
the field compression installed by PNR in the 1990's. The lawsuit now has two
material claims. First, the plaintiffs assert that the expenses related to the
field compression are a "cost of production" for which plaintiffs cannot be
charged their proportionate share under the applicable oil and gas leases, which
include Royalty properties. Second, the plaintiffs' claim they are entitled to
100 percent of the value of the helium extracted at PNR's Satanta gas plant. If
the plaintiffs were to prevail on the above two claims in their entirety, PNR
believes it is possible that PNR's liability could reach $25 million, plus
prejudgment interest. The Trust's share of this amount would be approximately
$1.3 million plus prejudgment interest. However, PNR believes it has valid
defenses to plaintiff's claims, has paid the plaintiffs properly under their
respective oil and gas leases, and intends to vigorously defend itself.
PNR believes the cost of the field compression is not a "cost of
production", but is rather an expense of transporting the gas to PNR's Satanta
gas plant for processing, where valuable hydrocarbon liquids and helium are
extracted from the gas. The plaintiffs benefit from such extractions and PNR
believes that charging the plaintiffs with their proportionate share of such
transportation and processing expenses is consistent with Kansas law. PNR has
also vigorously defended against plaintiffs' claims to 100 percent of the value
of the helium extracted, and believes that in accordance with applicable law, it
has properly accounted to the plaintiffs for their fractional royalty share of
the helium under the specified royalty clauses of the respective oil and gas
leases.
The factual evidence in the case was presented to the 26th Judicial District
Court without a jury in December 2001. No judgment or findings have been
entered, and PNR expects oral arguments to be set in the second quarter of 2002.
Judgment could be entered anytime after that time. PNR has stated that it
strongly denies the existence of any material underpayment to plaintiffs and
believes it presented strong evidence at trial to support its positions. PNR has
not yet determined the amount of damages, if any, that would be payable if the
lawsuit was determined adversely to PNR. However, the amount of any resulting
liability could have a material adverse effect on the Trust for the period in
which such liability is recorded and during any periods required for PNR to
recoup any additional amounts.
(7) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Estimates of the proved oil and gas reserves attributable to the Hugoton
Royalty Properties as of December 31, 2001, 2000 and 1999 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
29
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
(7) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) (CONTINUED)
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
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.
30
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
(7) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) (CONTINUED)
ESTIMATED QUANTITIES OF PROVED AND PROVED DEVELOPED RESERVES
(UNAUDITED)
OIL,
CONDENSATE
AND NATURAL
GAS LIQUIDS NATURAL GAS
----------- -----------
(BBLS) (MCF)
Proved Reserves:
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
Revisions to previous estimates......................... (597,032) (11,269,142)
Production.............................................. (111,298) (1,752,012)
--------- -----------
December 31, 2001......................................... 1,647,580 27,837,477
========= ===========
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
========= ===========
December 31, 2001......................................... 1,609,580 13,703,038
========= ===========
------------------------
- 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: 2001, 56,000 Bbls; 2000, 90,000 Bbls, and 1999,
70,000 Bbls.
- The Hugoton Royalty represents 43%, 42% and 46% of the estimated proved oil,
condensate and natural gas liquids reserves and 49%, 47% and 50% of the
estimated proved natural gas reserves as of December 31 of 2001, 2000 and
1999, respectively.
31
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
(7) 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,
--------------------
2001 2000
-------- ---------
(IN THOUSANDS)
The Trust's proportionate share of future gross proceeds.... $141,424 $ 533,972
Less the Trust's proportionate share of--
Future operating costs.................................... (56,372) (101,727)
Future capital costs...................................... (2,561) (3,207)
-------- ---------
Future royalty income....................................... 82,491 429,038
Discount at 10% per annum................................... (47,116) (252,287)
-------- ---------
Standardized measure of future royalty income from proved
oil and gas reserves...................................... $ 35,375 $ 176,751
======== =========
CHANGES IN THE STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM
PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM
(UNAUDITED)
DECEMBER 31,
-------------------------------
2001 2000 1999
--------- -------- --------
(IN THOUSANDS)
Standardized measure at beginning of year................... $ 176,751 $ 46,695 $30,204
--------- -------- -------
Revisions of previous estimates........................... (21,569) 27,654 5,189
Net changes in price and production costs................. (126,991) 105,692 13,757
Royalty income............................................ (10,491) (7,960) (5,475)
Accretion of discount..................................... 17,675 4,670 3,020
--------- -------- -------
Net changes in standardized measure....................... (141,376) 130,056 16,491
--------- -------- -------
Standardized measure at end of year......................... $ 35,375 $176,751 $46,695
========= ======== =======
------------------------
- The Hugoton Royalty represents approximately 55% and 48% of the standardized
measure of future royalty income for 2001 and 2000, respectively.
- Standardized measure at December 31, 2001 was calculated using natural gas
prices of $2.58 per Mcf for Hugoton properties and $2.22 per Mcf for San Juan
properties.
32
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
(8) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
SUMMARIZED QUARTERLY RESULTS
THREE MONTHS ENDED
----------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
---------- ---------- ------------ -----------
2001:
Royalty income.............................. $3,830,016 $3,527,218 $1,960,706 $1,173,048
Distributable income........................ $3,868,205 $3,547,180 $1,979,618 $1,171,748
Distributable income per unit............... $ 2.0757 $ 1.9034 $ 1.0623 $ 0.6288
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
33
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO JPMORGAN CHASE 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, 2001 and 2000, and the
related statements of distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 2001. 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.
These financial statements were prepared on the basis of accounting
described in Note 3, 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, 2001 and 2000, and its distributable income and
changes in trust corpus for each of the three years in the period ended
December 31, 2001, on the basis of accounting described in Note 3.
ARTHUR ANDERSEN LLP
Houston, Texas
March 25, 2002
34
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 Schedules 13D and 13G and Form 4.
AMOUNT AND
NATURE OF
TITLE OF CLASS OF NAME AND ADDRESS BENEFICIAL PERCENT
VOTING SECURITIES OF BENEFICIAL OWNER OWNERSHIP(1) OF CLASS
----------------- ------------------- ------------ --------
Units of Beneficial Interest....... Alpine Capital, L.P.
201 Main Street, Suite 3100
Fort Worth, Texas 76102 721,316(2) 38.7%
Units of Beneficial Interest....... Beck, Mack & Oliver LLC
330 Madison Avenue
New York, NY 10017 278,232(3) 14.92%
------------------------
(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. 20 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 September 9, 2001.
Alpine directly owns and has sole voting and dispositive power with respect
to all of such units. Such number of units does not include 17,784 units
(which constitutes approximately .95% 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 17,784 units owned by the
Foundation, may be deemed to be a beneficial owner of the 738,100 units
owned by Alpine and the 17,784 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 738,100 units owned by Alpine and the 17,784 units owned by the
Foundation.
(3) Information obtained from Schedule 13G dated February 11, 2002 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.
35
(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.......................... 26
Statements of Assets, Liabilities and Trust Corpus.......... 26
Statements of Changes in Trust Corpus....................... 26
Notes to Financial Statements............................... 27
Report of Independent Public Accountants.................... 34
(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)
99.1 Temporary Note 3T to Article 3 of Regulation S-X............
(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 2001.
36
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 JPMORGAN CHASE BANK, TRUSTEE
By /s/ MIKE ULRICH
-----------------------------------------
Mike Ulrich
SENIOR VICE PRESIDENT & TRUST OFFICER
March 25, 2002
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.
37
EXHIBIT INDEX
SEC FILE OR
EXHIBIT REGISTRATION EXHIBIT
NUMBER 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)
99.1 Temporary Note 3T to Article 3 of Regulation S-X............
------------------------
* Previously filed with the Securities and Exchange Commission and
incorporated herein by reference.