SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
[ ] 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)
<TABLE>
<S> <C>
TEXAS 74-6284806
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
CHASE BANK OF TEXAS,
NATIONAL ASSOCIATION
CORPORATE TRUST DIVISION
712 MAIN STREET
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
</TABLE>
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 216-6369
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<S> <C>
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
UNITS OF BENEFICIAL INTEREST NEW YORK STOCK EXCHANGE
</TABLE>
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 26, 1999, of $ 44.00 was approximately $ 81,997,960.00.
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 26, 1999, 1,863,590 Units of Beneficial Interest in Mesa
Royalty Trust.
Documents Incorporated By Reference: None.
================================================================================
<PAGE>
TABLE OF CONTENTS
PART I
<TABLE>
<CAPTION>
PAGE
<S> <C> <C>
Item 1. Business........................................................................................ 1
Description of the Trust........................................................................ 1
2
Description of the Units........................................................................
5
Description of Royalty Properties...............................................................
18
Contracts.......................................................................................
19
Regulation and Prices...........................................................................
Item 2. Properties...................................................................................... 20
Item 3. Legal Proceedings............................................................................... 20
Item 4. Submission of Matters to a Vote of Security Holders............................................. 20
</TABLE>
PART II
<TABLE>
<S> <C> <C>
Item 5. Market for the Registrant's Common Equity and Related Unitholder Matters........................ 21
Item 6. Selected Financial Data......................................................................... 21
Item 7. Management's Discussion and Analysis of Financial Condition and Results of 21
Operations....................................................................................
24
Summary of Royalty Income, Production and Average Prices (Unaudited)............................
Item 8. Financial Statements and Supplementary Data..................................................... 25
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial 32
Disclosure....................................................................................
</TABLE>
PART III
<TABLE>
<S> <C> <C>
Item 10. Directors and Executive Officers of the Registrant.............................................. 32
Item 11. Executive Compensation.......................................................................... 32
Item 12. Security Ownership of Certain Beneficial Owners and Management.................................. 32
Item 13. Certain Relationships and Related Transactions.................................................. 33
</TABLE>
PART IV
<TABLE>
<S> <C> <C>
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................................ 33
SIGNATURES................................................................................................. 34
</TABLE>
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-K includes "forward-looking statements" within the meaning
of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-K are forward-looking
statements. Although the Working Interest Owners have advised the Trust that
they believe that the expectations reflected in the forward-looking statements
contained herein are reasonable, no assurance can be given that such
expectations will prove to have been correct. Important factors that could cause
actual results to differ materially from expectations ("Cautionary
Statements") are disclosed in this Form 10-K, including without limitation in
conjunction with the forward-looking statements included in this Form 10-K. All
subsequent written and oral forward-looking statements attributable to the Trust
or persons acting on its behalf are expressly qualified in their entirety by the
Cautionary Statements.
<PAGE>
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, Chase Bank of
Texas, National Association (the "Trustee"), 712 Main Street, Houston, Texas
77002. The telephone number of the Trust is (713) 216-6369.
The Trust was created on November 1, 1979 when Mesa Petroleum Co. conveyed
to the Trust a 90% net profits overriding royalty interest (the "Royalty") in
certain producing oil and gas properties located in the Hugoton field of Kansas,
the San Juan Basin field of New Mexico and Colorado, and the Yellow Creek field
of Wyoming (collectively, the "Royalty Properties"). Mesa Petroleum Co. was
the predecessor to Mesa Limited Partnership ("MLP") which was the predecessor
to MESA Inc. On April 30, 1991, MLP sold its interests in the Royalty Properties
located in the San Juan Basin field to Conoco Inc. ("Conoco"), a wholly-owned
subsidiary of E. I. duPont de Nemours & Company. Conoco sold the portion of its
interests in the San Juan Basin Royalty Properties located in Colorado to
MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow
Production Company (effective April 1, 1992). On October 26, 1994, MarkWest
Energy Partners, Ltd. sold substantially all of its interest in the Colorado San
Juan Basin Royalty Properties to Amoco Production Company ("Amoco"), a
subsidiary of Amoco Corp. Until August 7, 1997, MESA Inc. operated the Hugoton
Royalty Properties through Mesa Operating Co., 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 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 $6,209,778 and $9,287,406 for the
years 1998 and 1997, 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. The brief summary set forth above is qualified in its
entirety by reference to the Trust Indenture itself, which is an exhibit to this
Form 10-K and is available upon request from the Trustee.
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
1
<PAGE>
of Gross Proceeds, as hereinafter defined, received by the working interest
owners during a particular period over operating and capital costs for such
period. "Gross Proceeds" means the amount received by the working interest
owners from the sale of minerals covered by the Royalty, subject to certain
adjustments. Operating costs means, 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 Royalty Properties are required to be operated by the working interest
owners in accordance with reasonable and prudent business judgment and good oil
and gas field practices. Each working interest owner has the right to abandon
any well or lease if, in its opinion, such well or lease ceases to produce or is
not capable of producing oil, gas or other minerals in commercial quantities.
Each working interest owner markets the production on terms deemed by it to be
the best reasonably obtainable in the circumstances. See "Contracts". The
Trustee has no power or authority to exercise any control over the operation of
the Royalty Properties or the marketing of production therefrom.
In 1985 the Trust Indenture was amended at a special meeting of
unitholders. The effect of the amendment was an overall reduction of
approximately 89% in the size of the Trust, distributable income and related
Trust reserves, effective April 1, 1985. See Note 2 in the Notes to Financial
Statements under Item 8 of this Form 10-K.
The Trust has no employees. Administrative functions of the Trust are
performed by the Trustee.
DESCRIPTION OF THE UNITS
Each unit is evidenced by a transferable certificate issued by the Trustee.
Each unit ranks equally for purposes of distributions and has one vote on any
matter submitted to unitholders. A total of 1,863,590 units were outstanding at
March 26, 1999.
DISTRIBUTIONS
The Trustee determines for each month the amount of cash available for
distribution for such month. Such amount (the "Monthly Distribution Amount")
consists of the cash received from the Royalty during such month less the
obligations of the Trust paid during such month, adjusted for changes made by
the Trustee during such month in any cash reserves established for the payment
of contingent or future obligations of the Trust. The Monthly Distribution
Amount for each month is payable to unitholders of record on the monthly record
date (the "Monthly Record Date") which is the close of business on the last
business day of such month or such other date as the Trustee determines is
required to comply with legal or stock exchange requirements. However, to reduce
the administrative
2
<PAGE>
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 Chase Bank of Texas,
National Association or the interest rate which Chase Bank of Texas, National
Association 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: (a) the
satisfaction of such liability was not by contract limited to the assets of the
Trust, (b) the assets of the Trust were insufficient to discharge such liability
and (c) 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 substantial value and 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 such 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 such units to the extent that such allowance exceeds cost
depletion as computed for the relevant period.
SECTION 29 CREDIT
The Trust receives royalty payments attributable to coal seam gas
production from the Fruitland Coal Formation properties. Thus, unitholders are
potentially eligible to claim their share of the tax credit attributable to this
qualifying production. Each unitholder should consult his tax advisor regarding
the limitations and requirements for claiming this tax credit.
BACKUP WITHHOLDING
Distributions from the Trust are generally subject to backup withholding at
a rate of 31% of such distributions. Backup withholding will not normally apply
to distributions to a unitholder, however, unless such unitholder fails to
properly provide to the Trust his taxpayer identification number ("TIN") or
the IRS notifies the Trust that the TIN provided by such unitholder is
incorrect.
3
<PAGE>
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. Such gain or
loss would be capital gain or loss if such unit was held by the unitholder as a
capital asset. For units sold on or prior to May 6, 1997, such capital gain will
be long-term if such unitholder's holding period exceeded one year as of the
date of sale or exchange. The Taxpayer Relief Act of 1997 reduced the maximum
long-term capital gains rate to 20% for capital assets sold after May 6, 1997,
but the holding period necessary to qualify for the reduced rate increased to 18
months effective for sales after July 28, 1997. A special "mid-term" rate
(generally 28%) applies to capital assets sold after July 28, 1997 with a
holding period over one year but not over 18 months. 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 such unit was held by
the unitholder as a capital asset.
FOREIGN UNITHOLDERS
In general, a unitholder who is a nonresident alien individual or which is
a foreign corporation (each, a "Foreign Taxpayer") 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 Foreign Taxpayer may elect to treat
the income from the Royalty as effectively connected with the conduct of a
United States trade or business under section 871 or section 882 of the Internal
Revenue Code of 1986, as amended (the "Code") (or pursuant to any similar
provisions of applicable treaties). Upon making this election such unitholder is
entitled to claim all deductions with respect to such income, but he must file a
United States federal income tax return to claim such deductions. This election
once made is irrevocable (unless an applicable treaty allows the election to be
made annually).
Section 897 of the Code and the Treasury Regulations thereunder treat the
publicly traded Trust as if it were a United States real property holding
corporation. Accordingly, Foreign Taxpayers owning greater than 5% of the
outstanding units are subject to United States federal income tax on the gain on
the disposition of their units. Foreign unitholders owning less than 5% 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 Foreign Taxpayer is a highly complex matter
which may be affected by many other considerations. Therefore, each Foreign
Taxpayer should consult with his own tax adviser as to the advisability of his
ownership of units.
4
<PAGE>
DESCRIPTION OF ROYALTY PROPERTIES
PRODUCING ACREAGE AND WELLS AS OF DECEMBER 31, 1998
<TABLE>
<CAPTION>
PRODUCING GAS
PRODUCING ACRES(1) WELLS(1)(2)
-------------------- ----------------
GROSS NET GROSS NET
<S> <C> <C> <C> <C>
------- ------- ----- -----
Hugoton Area (Kansas)(3).......................... 103,364 103,114 466 465.5
San Juan Basin (Northwestern New Mexico and
Southwestern Colorado).......................... 40,716 31,328 371 189.7
------- ------- ----- -----
Total.................................. 144,080 134,442 837 655.2
======= ======= ===== =====
</TABLE>
- ------------
(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.
(3) Includes 151 gross and net infill gas wells.
HUGOTON
The principal property interest conveyed to the Trust accounts for
approximately 64% 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 36% of the Trust's reserves. Substantially all of the natural gas
produced from the San Juan Basin is currently being sold on the spot market. PNR
completed the sale of its underlying interest in the San Juan Basin Royalty
Properties to Conoco on April 30, 1991. Conoco subsequently sold its underlying
interest in the Colorado portion of the San Juan Basin Royalty Properties to
MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow
Production Company (effective April 1, 1992). On October 26, 1994, MarkWest
Energy Partners, Ltd. sold substantially all of its interest in the Colorado San
Juan Basin Royalty Properties to Amoco. See "Description of the Trust". The
San Juan Basin Royalty Properties located in Colorado account for less than 5%
of the Trust's reserves.
SAN JUAN BASIN FRUITLAND COAL DRILLING
In April 1990, the working interest owner began drilling for coalbed
methane gas in the Fruitland Coal formation of the San Juan Basin. The Fruitland
Coal formation has been identified as one of the most prolific sources of U.S.
coalbed methane reserves. The Trust owns an interest in 26,700 gross acres and
25,400 net acres with Fruitland Coal potential. The working interest owner has
advised the Trust that, as of December 31, 1998, 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 such wells,
5
<PAGE>
42 (24.6 net) have been successfully completed, of which 37 (21.7 net) are
currently producing at a combined rate of 73.4 (39.8 net) MMcf per day.
The gas that is currently being produced from these wells is being sold on
the spot market, although the working interest owner has advised the Trust that
it will also consider selling some of the gas produced from these wells pursuant
to longer term contracts at spot market prices.
Aggregate drilling and completion costs for the entire Fruitland Coal
development program were approximately $18.4 million. The Trust's share of the
total expenditures was approximately $2.4 million. The Trust's share of the cost
of drilling and completing the Fruitland Coal wells was subject to recovery by
the working interest owner on a state-by-state basis before distributions were
made from the San Juan Basin Royalty. In December 1992, after recovery by the
working interest owner of the costs of the Fruitland Coal drilling in New
Mexico, distributions from the New Mexico portion of the San Juan Basin Royalty
resumed. No distributions related to the Colorado portion of the San Juan Basin
Royalty have been made since 1990, as the costs of the Fruitland Coal drilling
in Colorado have not yet been recovered. The San Juan Basin development drilling
program had no effect on Royalty income or distributions relating to the Hugoton
Royalty.
Conoco has informed the Trust that it believes the production from the
Fruitland Coal formation will generally qualify for the tax credits provided
under Section 29 of the Code. See "Description of the Units -- Federal Income
Tax Matters -- Section 29 Credit."
RESERVES
A study of the proved oil and gas reserves attributable to the Hugoton
Royalty as of December 31, 1998 have been made by PNR. The following letter
relating to the "Reserves and Revenue as of December 31, 1998 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 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, 1998 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 13 regarding such properties reflects estimated reserve quantities.
Proved oil and gas reserves attributable to the Colorado portion of the San
Juan Basin Royalty have been omitted from the Trust's reserve disclosures
included in this Form 10-K, as they represent less than 5% of the Trust's total
reserves and future net revenues.
For further information regarding the Net Overriding Royalty Interest, the
Basis of Accounting for the Trust, and Reserves, see Notes 2, 3 and 6,
respectively, in the Notes to Financial Statements under Item 8 of this Form
10-K.
6
<PAGE>
[PIONEER NATURAL RESOURCES LOGO]
SUMMARY REPORT
DATED MARCH 1999
ON
RESERVES AND REVENUE
AS OF DECEMBER 31, 1998
FROM CERTAIN PROPERTIES
OWNED BY
MESA ROYALTY TRUST
7
<PAGE>
[PIONEER NATURAL RESOURCES USA, INC. LOGO]
March 15, 1999
MESA Royalty Trust
Chase Bank of Texas, N.A. (as Trustee)
Chase Tower, Suite 1150
600 Travis Street
Houston TX 77002
Ladies and Gentlemen:
Pursuant to your request, we have prepared estimates, as of December 31, 1998,
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 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 after December 31, 1998. Net reserves are
defined as that portion of the gross reserves attributable to the interest owned
by the Trust after deducting royalties and other interests owned by others.
Values shown herein are expressed in terms of future gross revenue, future net
revenue, and present worth. Future gross revenue is that revenue which will
accrue to the appraised interests from the production and sale of the estimated
net reserves. Future net revenue is calculated by deducting estimated production
taxes, ad valorem taxes, operating expenses, and capital costs for the future
gross 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 using a
discount rate of 10 percent are reported.
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. These calculations were made annually in aggregate
for
8
<PAGE>
MESA Royalty Trust
March 15, 1999
Page 2
the Trust properties. 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, 1998, was zero and no deficit is estimated for the life of the
properties.
Reserves attributable to the Trust interest were estimated by allocating to the
Trust a portion of the estimated combined net reserves of the properties based
on future revenue. Because the reserve volumes attributable to the Trust are
estimated using an allocation of reserves based on estimates of future revenue,
a change in prices or costs will result in changes in the estimated reserves.
Therefore, the reserves estimated will vary if different future price and cost
assumptions are used.
Estimates of reserves and future net revenue should be regarded only as
estimates that may change as further production history and additional
information become 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, 1998. In our preparation of the study, data available from wells drilled on
the appraised properties through December 31, 1998 were used in estimating gross
ultimate recovery. Gross production estimated to December 31, 1998 was deducted
from gross ultimate recovery to arrive at the estimates of gross reserves as of
December 31, 1998. In these fields, this required that the production rates be
estimated for up to six months since production data for certain properties were
available only through July 1998.
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, including 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:
o 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.
o Developed - Reserves that are recoverable from existing wells with current
operating methods and expenses. Developed reserves include both producing
and nonproducing reserves. Estimates of producing reserves assume recovery
by existing wells producing from present completion intervals with normal
operating methods and expenses. Developed nonproducing 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.
Nonproducing reserves require only moderate expense to be brought into
production.
9
<PAGE>
MESA Royalty Trust
March 15, 1999
Page 3
o Undeveloped - Reserves that are recoverable from additional wells yet to be
drilled. Undeveloped reserves are those considered proved for production by
reasonable geological interpretation of adequate subsurface control in
reservoirs that are producing or proved by other wells but are not
recoverable from existing wells. This classification of reserves requires
drilling of additional wells, major deepening of existing wells, or
installation of enhanced recovery or other facilities.
Helium reserves were classified using the same standards as those described in
the foregoing definitions of petroleum reserves. Because 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, 1998, are as follows:
TOTAL PROVED RESERVES:
Natural Gas (Mcf)............................ 16,819,005
Helium (Mcf)................................. 37,692
Natural Gas Liquids (bbl).................... 741,928
PROVED DEVELOPED RESERVES
Natural Gas (Mcf)............................ 16,819,005
Helium (Mcf)................................. 37,692
Natural Gas Liquids (bbl).................... 741,928
Proved natural gas liquids 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 gas 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 1998 values and were not adjusted for inflation.
10
<PAGE>
MESA Royalty Trust
March 15, 1999
Page 4
A summary of estimated revenue and costs attributable to the Combined Interest
in proved reserves and the future net revenue and present worth attributable to
the Trust interest, as of December 31, 1998 is as follows:
COMBINED INTEREST:
Future Gross Revenue ($)......................... 705,111,072
Production Taxes ($)............................. (32,342,337)
Ad Valorem Taxes ($)............................. (45,529,121)
Operating Costs ($).............................. (107,050,540)
Capital Costs ($)................................ (9,067,600)
Future Net Revenue ($)1.......................... 511,121,473
Net Revenue Attributable to Plant Interests ($).. (1,275,349)
Overhead ($)..................................... (176,100,600)
Deficit Balance and Interest on Deficit ($)...... 0
Revenue Subject to Net Profits Interest ($)1..... 333,745,525
TRUST INTEREST:
Future Net Revenue ($)1.......................... 34,351,826
Present Worth at 10 Percent ($)1................. 16,822,136
(1)IFuture 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 estimated proved reserves, estimated
future net revenue from proved reserves, and present worth of estimated future
net revenue from proved reserves of natural gas liquids, and gas contained in
this report has been prepared in accordance with Paragraphs 10-13, 15 and
30(a)-(b) of Statement of Financial Accounting Standards No. 69 (November 1982)
of the Financial Accounting Standards Board and Rules 4-10(a)(1)-(13) of
Regulation S-X and Rule 302(b) of Regulation S-K of the Securities and Exchange
Commission; provided, however, (i) future income tax expenses have not been
taken into account in estimating the future net revenue and present worth values
set forth herein and (ii) minor amounts of revenue from helium produced with the
natural gas are included herein.
To the extent the above enumerated rules, regulations, and statements require
determinations of an accounting or legal nature or information beyond the scope
of this report, we are necessarily unable to express an opinion as to whether
the above-described information is in accordance therewith or sufficient
therefore.
Submitted,
/s/ D. RICHARD MASSENGILL
D. Richard Massengill
11
<PAGE>
CONOCO INC.
LETTER REPORT
DATED
MARCH 25, 1999
ON
RESERVES AND REVENUE
AS OF
DECEMBER 31, 1998
FROM
CERTAIN PROPERTIES
OWNED BY
MESA ROYALTY TRUST
12
<PAGE>
[CONOCO LOGO]
- --------------------------------------------------------------------------------
Frank P. Koskimaki
Leader - Reservoir Management P. O. Box 2197
Reservoir Technology Center Houston, Texas 77252
Exploration Production Technology (281) 293-1404
March 22, 1999
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, 1998
SAN JUAN BASIN PROPERTIES, NEW MEXICO
Ladies and Gentlemen:
Pursuant to your request, estimates have been prepared as of December 31, 1998
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, 1998. MRT net reserves are defined as that portion of the Conoco
net reserves attributable to the interest owned by MRT.
Values shown herein are expressed in terms of future revenue, future cash flow,
and present worth. Future revenue is that revenue which will accrue from
production and sale of the estimated net reserves. Future cash flow is
calculated by deducting estimated production and ad valorem taxes, operating and
transportation expenses, capital costs, and abandonment costs from the future
revenue. Federal income taxes are not taken into account in the preparation of
these estimates. Present worth is defined as future cash flow discounted at a
specified discount rate compounded monthly over the expected period of
realization. A discount rate of 10 percent is used in this report.
Reserves attributable to the MRT interest are calculated by allocating to MRT a
portion of the Conoco net reserves based on future cash flow. Because reserves
volumes are estimated using future cash flow, a change in prices or costs will
result in changes of reserves. Therefore, the MRT net reserves will vary if
different price and cost assumptions are used.
Petroleum reserves included in this report are classified as proved and judged
to be economically producible in future years from known reservoirs under
existing economic and operating conditions. Total proved reserves are the sum of
developed and undeveloped reserves. Proved developed reserves are those
recoverable from existing
13
<PAGE>
1998 Mesa Royalty Trust Reserves
March 22, 1999
wells with current operating methods and expenses, and thus require little or no
capital expenditure to produce. Proved undeveloped reserves are those which
require major capital expenditures for new wells and/or facilities. Estimates of
the MRT net reserves and production as of December 31, 1998 are tabulated below
along with the MRT net reserves reported last year for comparison.
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------
MRT NET PROVED RESERVES
SAN JUAN BASIN CONVENTIONAL FRUITLAND COAL TOTAL
DEVELOPED + UNDEVELOPED RESERVOIRS RESERVOIRS ALL RESERVOIRS
--------------------------------------------------------------------
12/31/97 12/31/98 12/31/97 12/31/98 12/31/97 12/31/98
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Natural Gas, MMscf 10,982 12,789 1,322 1,768 12,304 14,557
- ---------------------------------------------------------------------------------------------------
Condensate, Mbbl 24 57 0 0 24 57
- ---------------------------------------------------------------------------------------------------
Natural Gas Liquids, Mbbl 626 821 8 0 634 821
- ---------------------------------------------------------------------------------------------------
MRT NET PROVED RESERVES
SAN JUAN BASIN CONVENTIONAL FRUITLAND COAL TOTAL
DEVELOPED ONLY RESERVOIRS RESERVOIRS ALL RESERVOIRS
--------------------------------------------------------------------
12/31/97 12/31/98 12/31/97 12/31/98 12/31/97 12/31/98
- ---------------------------------------------------------------------------------------------------
Natural Gas, MMscf 10,688 12,395 1,322 1,768 12,010 14,163
- ---------------------------------------------------------------------------------------------------
Condensate, Mbbl 23 54 0 0 23 54
- ---------------------------------------------------------------------------------------------------
Natural Gas Liquids, Mbbl 608 796 8 0 616 796
- ---------------------------------------------------------------------------------------------------
</TABLE>
Total reserves increased in 1998 due to drilling in unproved areas for
conventional gas reservoirs, upwards revisions to performance estimates based on
a detailed reservoir analysis, and a higher percentage of net proceeds allocated
to the MRT. The reserves values reflect natural gas shrinkage of 12.86 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. The minor
natural gas liquid volume reported for the Fruitland Coal in last year's report
was a result of erroneous coding of input data in one lease.
Product prices and operating costs used for yearend 1998 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 1998
product prices are substantially lower than last year.
Natural gas prices are 15 percent lower.
-------------------------------------------------------------
PRODUCT PRICES DECEMBER 1997 DECEMBER 1998
-------------------------------------------------------------
Natural Gas, $/Mscf 2.10 1.79
-------------------------------------------------------------
Condensate, $/Bbl 16.74 9.79
-------------------------------------------------------------
Natural Gas Liquids, $/Bbl 12.86 8.39
-------------------------------------------------------------
Revenue and cash flow values in this report are based on product prices for San
Juan Basin effective in December 1998. The gas price excludes a transportation
expense of $0.48 per Mcf. The price also excludes combined production and ad
valorem tax rates
14
<PAGE>
1998 Mesa Royalty Trust Reserves
March 22, 1999
of 11.1 percent and 9.9 percent of revenue for conventional and Fruitland Coal
gas, respectively. These taxes compare with the 1997 numbers of 14.5 percent and
9.5 percent, respectively. These taxes and transportation expenses are also
excluded from the annual per well operating costs tabulated below. Operating
costs on a per well basis are slightly higher than 1997, reflecting declining
production and increased maintenance work on older wells.
-------------------------------------------------------------------
OPERATING COSTS NET ACTIVE OPERATING COSTS
COMPLETIONS ($/WELL/YEAR)
-------------------------------------------------------------------
12/31/97 12/31/98 12/31/97 12/31/98
-------------------------------------------------------------------
Conventional Gas 406 445 16,300 17,100
-------------------------------------------------------------------
Fruitland Coal Gas 14 14 45,700 49,700
-------------------------------------------------------------------
A summary of estimated future revenue, taxes, costs, cash flow, and present
worth attributable to CONOCO'S net reserves as of December 31, 1998 is shown in
the table below, along with what was reported last year for comparison. All
costs are yearend 1998 estimates and are not adjusted for inflation. Cash flow
and present worth are reported on a before federal income tax (BFIT) basis.
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------
CONOCO NET INTEREST CONVENTIONAL FRUITLAND COAL TOTAL
SAN JUAN BASIN RESERVOIRS RESERVOIRS ALL RESERVOIRS
- ---------------------------------------------------------------------------------------------------
12/31/97 12/31/98 12/31/97 12/31/98 12/31/97 12/31/98
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Future Revenue, M$ 580,104 576,865 80,885 57,922 660,989 634,787
- ---------------------------------------------------------------------------------------------------
Production & Ad Valorem
Taxes, M$ 84,115 64,032 7,687 5,734 91,802 69,766
- ---------------------------------------------------------------------------------------------------
Operating & Transportation
Costs, M$ 180,635 207,254 29,019 20,429 209,654 227,683
- ---------------------------------------------------------------------------------------------------
Abandonment Costs, M$ 1,544 1,594 54 53 1,598 1,647
- ---------------------------------------------------------------------------------------------------
Capital Costs, M$ 7,732 9,258 16,187 956 23,919 10,214
- ---------------------------------------------------------------------------------------------------
Future BFIT Cash Flow, M$ 306,078 294,727 27,938 30,750 334,016 325,477
- ---------------------------------------------------------------------------------------------------
Deficit Balance, M$ 0 0 0 0 0 0
- ---------------------------------------------------------------------------------------------------
Future BFIT Cash Flow
Subject to MRT Interest, M$ 306,078 294,727 27,938 30,750 334,016 325,477
- ---------------------------------------------------------------------------------------------------
Present Worth @ 10% M$ 129,541 105,359 23,454 24,653 152,995 130,012
- ---------------------------------------------------------------------------------------------------
</TABLE>
Conoco's future revenues are reduced by significantly lower product prices, but
higher reserves for the conventional gas reservoirs partially offset the effect
of lower prices.
The higher total operating costs for conventional gas reservoirs reflects the
additional wells from the 1998 drilling program. The total Fruitland Coal
operating costs, however, are lower as a result of a lower projection of the
number of future wells as production declines.
Capital costs are associated with projects required to produce undeveloped
proved reserves and maintain existing production of developed reserves. The
increase in capital for the conventional reservoirs reflects the additional
wells needed to develop the increased proved undeveloped reserves. The
significant decrease in capital for the Fruitland Coal reservoirs is a result of
a correction in the way future capital was previously allocated to MRT leases in
the SMOG calculations.
15
<PAGE>
1998 Mesa Royalty Trust Reserves
March 22, 1999
A summary of estimated future cash flow and present worth attributable to the
MRT interest as of December 31, 1998 is tabulated below along with what was
reported last year for comparison.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------
MRT INTEREST
(10.29282%) CONVENTIONAL FRUITLAND TOTAL
SAN JUAN BASIN RESERVOIRS COAL RESERVOIRS ALL RESERVOIRS
- -------------------------------------------------------------------------------------------------
12/31/97 12/31/98 12/31/97 12/31/98 12/31/97 12/31/98
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Future BFIT Cash Flow, M$ 31,504 30,336 2,876 3,165 34,380 33,501
- -------------------------------------------------------------------------------------------------
Present Worth @ 10%, M$ 13,333 10,844 2,414 2,537 15,747 13,381
- -------------------------------------------------------------------------------------------------
</TABLE>
Compared to last year, future cash flow and present worth for conventional gas
is lower, reflecting the decrease in product prices. The Fruitland Coal cash
flow and present worth are higher because the reductions for price were more
than offset by higher net MRT reserves.
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/ FRANK P. KOSKIMAKI
Frank P. Koskimaki
16
<PAGE>
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, generally, 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 $1.78 per Mcf for Hugoton
properties and $1.79 per Mcf for San Juan Basin properties as of December 31,
1998) were held constant over the estimated life of the Royalty Properties. Such
prices were influenced by seasonal demand for natural gas and may not be the
most appropriate or representative prices to use for estimating future revenues
or related reserve data. The average price of natural gas from the Royalty
Properties during 1998 was $2.04 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 $55,000
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.
The working interest owners have advised the Trustee that there have been
no events subsequent to December 31, 1998 that have caused a significant change
in the estimated proved reserves referred to in the Reserve Reports.
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.
ASSETS
Reference is made to Item 6 of this Form 10-K for information concerning
the Trust's assets.
17
<PAGE>
CONTRACTS
HUGOTON FIELD
Natural gas and natural gas liquids produced by PNR from the Hugoton field
and attributable to the Royalty accounted for approximately 68% of the Royalty
income of the Trust during 1998.
PNR has advised the Trust that since June 1, 1995 natural gas produced from
the Hugoton field has generally been sold under short-term and multi-month
contracts at market clearing prices to multiple purchasers including Williams
Energy Supply ("WESCO"), OnEok Gas Marketing, Inc., Amoco Production Company
and Anadarko Energy Services, Inc. PNR has advised the Trust that it expects to
continue to market gas production from the Hugoton field under short-term and
multi-month contracts. Overall market prices received for natural gas from the
Hugoton Royalty Properties were lower in 1998 compared to 1997.
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 and ending June 1, 2000, but which
may be continued in effect year-to-year thereafter. 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, 1998 through March 31, 1999, was 251 billion cubic feet of gas,
compared with 277 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 32% of the Royalty income of the Trust
during 1998. 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 past decade has been affected generally by a surplus in natural gas
deliverability compared to demand. Demand for gas declined during this period
due to a number of factors including the implementation of energy conservation
programs, a shift in economic activity away from energy intensive industries and
competition from alternative fuel sources such as residual fuel oil, coal and
nuclear energy. The surplus of natural gas deliverability caused a significant
deterioration in gas prices. 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 from 1995 to $2.17 per Mcf in 1996 and $2.37 per Mcf
in 1997 and decreased to an estimated $1.90 in 1998, according to Natural Gas
Monthly published by the Energy Information Administration of the Department of
Energy. Spot prices for domestic natural gas were negatively affected by warmer
than normal weather in the winters of 1997-98 and 1998-99.
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.
18
<PAGE>
COMPETITION
The production and sale of gas in the Hugoton field and San Juan Basin
areas is highly competitive, and the working interest owners' competitors in
these areas include the major oil and gas companies, independent oil and gas
concerns, and individual producers and operators. There are numerous producers
in the Hugoton field and the San Juan Basin areas. The working interest owners
have advised the Trust that they believe that their competitive position in
their respective areas is affected by price, contract terms and quality of
service. PNR has also advised the Trust that it believes that its competitive
position in the Hugoton field is enhanced by virtue of its substantial holdings
and ownership and control of its wells, gathering systems and processing plant.
Market conditions in the San Juan Basin are negatively affected by the fact that
most of the gas produced from such areas is transported on one of only two major
pipelines, and the transportation of such gas is generally controlled by a small
number of distribution companies.
REGULATION AND PRICES
GENERAL
The production and sale of natural gas from the Royalty Properties are
affected from time to time in varying degrees by political developments and
federal, state and local laws and regulations. In particular, oil and gas
production operations and economics are, or in the past have been, affected by
price controls, taxes, conservation, safety, environmental and other laws
relating to the petroleum industry, by changes in such laws and by constantly
changing administrative regulations.
FERC REGULATION
In recent years, the FERC has required interstate pipeline companies to
"unbundle" their services. To the extent a pipeline company or its sales
affiliate makes gas sales as a merchant in the future, it does so pursuant to
private contracts in direct competition with all other sellers, such as the
working interest owners. In recent years, the FERC also has pursued a number of
other policy initiatives which could significantly affect the marketing of
natural gas. Several of these initiatives are intended to enhance competition in
natural gas markets, although some, such as "spin-downs," may have the adverse
effect of increasing the cost of doing business on some in the industry. On July
29, 1998, the FERC issued two orders in which the FERC is considering revisions
to its regulation of short-term and long-term transportation markets. 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.
Natural gas gathering has received greater regulatory scrutiny at both the state
and federal levels as the pipeline restructuring under Order 636 continues. For
example, Oklahoma and Kansas have enacted a prohibition against discriminatory
gathering rates, and certain Texas regulatory officials have expressed interest
in evaluating similar rules in their respective states.
19
<PAGE>
ENVIRONMENTAL MATTERS
The working interest owners' operations are subject to numerous federal,
state and local laws and regulations controlling the discharge of materials into
the environment or otherwise relating to the protection of the environment,
including the Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA" or "Superfund"), the Solid Waste Disposal Act, the Clean Air
Act, and the Federal Water Pollution Control Act. These laws and regulations,
including their state counterparts, can impose liability upon the lessee under a
lease for the cost of cleanup of discharged materials resulting from a lessee's
operations or can subject the lessee to liability for damages to natural
resources. Violations of environmental laws, regulations, or permits can result
in civil and criminal penalties as well as potential injunctions curtailing
operations in affected areas and restrictions on the injection of liquids into
the subsurface that may contaminate groundwater. The working interest owners
have advised the Trust that they maintain insurance for costs of cleanup
operations, but they are not fully insured against all such risks. A serious
release of regulated materials could result in the DOI requiring lessees under
federal leases to suspend or cease operations in the affected area. In addition,
the recent trend toward stricter standards and regulations in environmental
legislation is likely to continue. For example, from time to time legislation
has been proposed in Congress that would reclassify certain oil and gas
production wastes as "hazardous wastes" which would subject the handling,
disposal and cleanup of these wastes to more stringent requirements and result
in increased operating costs for the Royalty Properties, as well as the oil and
gas industry in general. State initiatives to further regulate the disposal of
oil and gas wastes are also pending in certain states, and these initiatives
could have a similar impact on the Royalty Properties.
The working interest owners have advised the Trust that they are not
involved in any administrative or judicial proceedings relating to the Royalty
Properties arising under federal, state or local environmental protection laws
and regulations or which would have a material adverse effect on the working
interest owners' financial position or results of operations.
ITEM 2. PROPERTIES.
Reference is made to Item 1 of this Form 10-K.
ITEM 3. LEGAL PROCEEDINGS.
There are no pending legal proceedings to which the Trust is a party.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the
fourth quarter of 1998.
20
<PAGE>
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,
1998, were as follows:
<TABLE>
<CAPTION>
1998 1997
----------------------------------- -----------------------------------
QUARTER HIGH LOW DISTRIBUTION HIGH LOW DISTRIBUTION
- ------------------------------ --------- --------- ------------ --------- --------- ------------
<S> <C> <C> <C> <C> <C> <C>
First......................... $ 45.69 $ 44.00 $ 1.1749 $ 47.25 $ 43.75 $ 2.0912
Second........................ $ 45.88 $ 43.88 $ .8763 $ 45.00 $ 43.50 $ .8868
Third......................... $ 45.38 $ 44.13 $ .7580 $ 46.69 $ 43.50 $ .9146
Fourth........................ $ 45.75 $ 43.25 $ .5436 $ 47.75 $ 44.38 $ 1.1291
</TABLE>
At March 26, 1999, the 1,863,590 units outstanding were held by 1,593
unitholders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
-------------- -------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
Royalty income....................... $ 6,209,778 $ 9,287,406 $ 7,669,020 $ 5,941,088 $ 6,927,776
Distributable income................. $ 6,248,216 $ 9,358,576 $ 7,689,372 $ 5,957,482 $ 6,967,277
Distributable income per unit........ $ 3.3528 $ 5.0218 $ 4.1261 $ 3.1967 $ 3.7386
Total assets at year end............. $ 14,902,521 $ 17,616,866 $ 18,975,935 $ 20,715,506 $ 23,240,108
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
As discussed under "Description of the Trust" in Item 1 of this Form
10-K, the Trust's source of cash is the Royalty income received from its share
of the net proceeds from the Royalty Properties. Reference is made to Note 6 in
the Notes to Financial Statements under Item 8 of this Form 10-K for a
discussion of estimated 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 1998 AND 1997
The Trust's Royalty income was $6,209,778 in 1998, a decrease of
approximately 33%, as compared to $9,287,406 in 1997, primarily as a result of
lower natural gas production and natural gas and natural gas liquids prices.
Royalty income from the Hugoton Royalty Properties was $4,235,415 in 1998,
a decrease of approximately 30%, as compared to $6,011,781 in 1997, primarily as
a result of lower natural gas and natural gas liquids prices in 1998.
The average price received for natural gas and natural gas liquids from the
Hugoton Royalty Properties was $2.10 per Mcf and $10.64 per barrel,
respectively, in 1998 as compared to $2.43 per Mcf and $15.27 per barrel,
respectively, in 1997. Net production attributable to the Hugoton Royalty was
1,539,202 Mcf of natural gas and 94,275 barrels of natural gas liquids in 1998
as compared with 1,682,623 Mcf of natural gas and 125,934 barrels of natural gas
liquids in 1997.
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 $1,974,363 in
1998 as compared to $3,275,625 in 1997. The decrease in Royalty income was due
primarily to decreased natural gas and natural gas liquids prices in 1998. No
Royalty income was received from Amoco with respect to the San Juan Basin
Royalty Properties located in the state of
21
<PAGE>
Colorado in 1998 or 1997, 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 $1.92 per Mcf and
$11.12 per barrel, respectively, in 1998 compared with $2.21 per Mcf and $15.88
per barrel, respectively, in 1997. Net production attributable to the San Juan
Basin Royalty was 811,007 Mcf of natural gas and 37,521 barrels of natural gas
liquids, oil and condensate in 1998 as compared to 1,203,514 Mcf of natural gas
and 38,782 barrels of natural gas liquids, oil and condensate in 1997.
As more fully discussed in Note 6 of the Notes to Financial Statements
contained in Item 8 of this Form 10-K, production attributable to the Trust's
interest in the Royalty Properties is calculated based on Royalty income
received from the applicable working interest owner by the Trust.
Conoco has informed the Trust that it believes the production from the
Fruitland Coal formation will generally qualify for the tax credits provided
under Section 29 of the Code. See "Description of the Units -- Federal Income
Tax Matters -- Section 29 Credit" under Item 1 of this Form 10-K.
YEARS 1997 AND 1996
The Trust's Royalty income was $9,287,406 in 1997, an increase of
approximately 21%, as compared to $7,669,020 in 1996, primarily as a result of
higher natural gas and natural gas liquids prices.
Royalty income from the Hugoton Royalty Properties was $6,011,781 in 1997,
a decrease of approximately 2%, as compared to $6,157,832 in 1996, primarily as
a result of decreased natural gas production, partially offset by increased
natural gas and natural gas liquids prices.
The average price received for natural gas and natural gas liquids from the
Hugoton Royalty Properties was $2.43 per Mcf and $15.27 per barrel,
respectively, in 1997 as compared to $2.02 per Mcf and $13.28 per barrel,
respectively, in 1996. Net production attributable to the Hugoton Royalty was
1,682,623 Mcf of natural gas and 125,934 barrels of natural gas liquids in 1997
as compared with 2,006,444 Mcf of natural gas and 159,004 barrels of natural gas
liquids in 1996.
Royalty income from the San Juan Basin Royalty Properties located in the
state of New Mexico was $3,275,625 in 1997 as compared to $1,511,188 in 1996 due
primarily to higher natural gas production and prices. No Royalty income was
received from Amoco with respect to the San Juan Basin Royalty Properties
located in the state of Colorado in 1997 or 1996 as costs associated with the
development drilling program from Royalty Properties in that state have not been
fully recovered.
The average price received for natural gas and natural gas liquids, oil and
condensate from the San Juan Basin Royalty Properties was $2.21 per Mcf and
$15.88 per barrel, respectively, in 1997 compared with $1.33 per Mcf and $13.97
per barrel, respectively, in 1996. Net production attributable to the San Juan
Basin Royalty was 1,203,514 Mcf of natural gas and 38,782 barrels of natural gas
liquids, oil and condensate in 1997 as compared to 749,222 Mcf of natural gas
and 36,852 barrels of natural gas liquids, oil and condensate in 1996.
INFORMATION SYSTEMS FOR THE YEAR 2000
The inability of some computer programs and embedded chips to distinguish
between the year 1900 and year 2000 (the "Year 2000 problem") poses a serious
threat of business disruption to any organization that utilizes computer
technology and computer chip technology in their business systems or equipment.
In proactive response to the Year 2000 problem, PNR established a "Year 2000"
project to assess, to the extent possible, PNR's internal Year 2000 problem; to
take remedial actions necessary to minimize the Year 2000 risk exposure to PNR
and significant third parties with whom it has data interchange; and, to test
its systems and processes once remedial actions have been taken. PNR has
contracted with IBM Global Services to perform the assessment and remedial
phases of its Year 2000 project.
As of December 31, 1998, PNR estimates that the assessment phase is
approximately 86% complete on a worldwide basis and has included, among other
procedures, (1) the identification of necessary remediation, upgrade and/or
replacement of existing information technology applications and systems; (2) the
assessment of non-information technology exposures, such as telecommunications
systems, security systems, elevators and process control equipment; (3) the
initiation of inquiry and dialogue with significant third party business
partners, customers and suppliers in an effort to
22
<PAGE>
understand and assess their Year 2000 problems, readiness and potential impact
on PNR and its Year 2000 problem; (4) the implementation of processes designed
to reduce the risk of reintroduction of Year 2000 problems into PNR's systems
and business processes; and, (5) the formulation of contingency plans for
mission-critical information technology systems.
PNR expects to complete the assessment phase of its Year 2000 project by
the end of the first quarter of 1999 but is being delayed by limited responses
received on inquiries made of third party businesses.
As of December 31, 1998, PNR estimates that the remedial phase is
approximately 54% complete, on a worldwide basis, subject to the continuing
results of the third party inquiry assessments and the testing phase. The
remedial phase has included the upgrade and/or replacement of certain
application and hardware systems. The remediation of non-information technology
is expected to be completed during July 1999. PNR's Year 2000 remedial actions
have not significantly delayed other information technology projects or
upgrades. The testing phase of PNR's Year 2000 project is expected to be
completed by March 1999 and all other information technology systems and
non-information technology remediation by the end of the third quarter of 1999.
None of PNR's costs related to the Year 2000 are passed through to the Trust.
A failure to remedy a critical Year 2000 problem could have a materially
adverse effect on PNR's results of operations and financial condition. The most
likely worst case scenario which may be encountered as a result of a Year 2000
problem could include information and non-information system failures, the
receipt or transmission of erroneous data, lost data or a combination of similar
problems of a magnitude to PNR that cannot be accurately assessed at this time.
In the assessment phase of PNR's Year 2000 project, contingency plans are
being designed to mitigate the exposures to mission critical information
technology systems, such as oil and gas sales receipts; vendor and royalty cash
distributions; debt compliance; accounting; and, employee compensation. Such
contingency plans anticipate the extensive utilization of third-party data
processing services, personal computer applications and the substitution of
courier and mail services in place of electronic data interchange. Given the
uncertainties regarding the scope of the Year 2000 problem and the compliance of
significant third parties, there can be no assurance that contingency plans will
have anticipated all Year 2000 scenarios.
Conoco has essentially completed the inventory and assessment phases and
has entered the remediation and testing phases of its plan to become Year
2000-capable. Their target for completing Year 2000 modifications is mid-1999;
however, additional refinements and testing may continue through the end of
1999. However, Conoco cannot reasonably estimate the potential impact on its
financial condition and operations if key third parties, including governments,
do not become Year 2000-capable on a timely basis. Conoco is working through
various trade associations as well as communicating directly with its
significant suppliers and customers to determine their Year 2000 capability. In
addition, Conoco has begun contingency planning to handle potential disruptions
in electrical, telecommunications, transportation and distribution services.
There can be no guarantee that these efforts will prevent the failure of third
parties to become Year 2000-capable and from having a material adverse affect on
Conoco's financial condition or operations or the Royalty Properties operated by
Conoco. None of Conoco's costs related to the Year 2000 are passed through to
the Trust.
The Trustee has developed and is implementing a program to prepare its
systems and applications for the Year 2000, including those used to render
services to the Trust. In that connection, the Trustee intends to have such
systems and applications capable of processing, on and after January 1, 2000,
date, and date-related data consistent with the functionality of such systems
and applications, without a material adverse effect upon its performance of
services as Trustee. Third parties that the Trust conducts business with could
be prone to Year 2000 problems that could not be assessed or detected by the
Trust. The Trust is contacting the major third parties to determine whether they
will be able to resolve, in a timely manner, any Year 2000 problems directly
affecting the Trust and to inform them of the Trust's internal assessment of its
Year 2000 review.
The information above with respect to PNR and Conoco is based on
information provided by PNR and Conoco to the Trustee for use in this Form 10-K.
23
<PAGE>
SUMMARY OF ROYALTY INCOME, PRODUCTION AND AVERAGE PRICES (UNAUDITED)
<TABLE>
<CAPTION>
SAN JUAN BASIN TOTAL
HUGOTON ------------------------------ -----------
------------------------- OIL,
NATURAL CONDENSATE
GAS AND NATURAL
NATURAL GAS LIQUIDS(2) NATURAL GAS GAS LIQUIDS(2) NATURAL GAS
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1998:
The Trust's proportionate share of --
Gross proceeds........................... $4,315,417 $1,003,090 $3,838,538 $ 594,315 $8,153,955
Less the Trust's proportionate share of --
Capital costs recovered(1)............... (76,949) -- (546,352) -- (623,301)
Operating costs.......................... (1,006,143) (1,699,546) (177,086) (2,705,689)
Interest on cost carryforward............ -- -- (35,506) -- (35,506)
----------- ---------- ----------- --------------- -----------
Royalty income............................. $3,232,325 $1,003,090 $1,557,134 $ 417,229 $4,789,459
=========== ========== =========== =============== ===========
Average sales price........................ $ 2.10 $ 10.64 $ 1.92 $ 11.12 $ 2.04
=========== ========== =========== =============== ===========
Net production volumes attributable (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
to the Royalty paid....................... 1,539,202 94,275 811,007 37,521 2,350,209
=========== ========== =========== =============== ===========
Year ended December 31, 1997:
The Trust's proportionate share of --
Gross proceeds........................... $5,432,474 $1,930,719 $5,041,640 $ 795,807 $10,474,114
Less the Trust's proportionate share of --
Capital costs recovered(1)............... (90,316) -- (316,032) -- (406,348)
Operating costs.......................... (1,253,384) (7,712) (2,028,792) (179,948) (3,282,176)
Interest on cost carryforward............ -- -- (37,050) -- (37,050)
----------- ---------- ----------- --------------- -----------
Royalty income............................. $4,088,774 $1,923,007 $2,659,766 $ 615,859 $6,748,540
=========== ========== =========== =============== ===========
Average sales price........................ $ 2.43 $ 15.27 $ 2.21 $ 15.88 $ 2.34
=========== ========== =========== =============== ===========
Net production volumes attributable (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
to the Royalty paid....................... 1,682,623 125,934 1,203,514 38,782 2,886,137
=========== ========== =========== =============== ===========
Year ended December 31, 1996:
The Trust's proportionate share of --
Gross proceeds........................... $5,274,074 $2,122,924 $3,292,237 $ 666,111 $8,566,311
Less the Trust's proportionate share of --
Capital costs recovered(1)............... (13,075) -- (296,530) -- (309,605)
Operating costs.......................... (1,214,307) (11,784) (1,981,941) (151,389) (3,196,248)
Interest on cost carryforward............ -- -- (17,300) -- (17,300)
----------- ---------- ----------- --------------- -----------
Royalty income............................. $4,046,692 $2,111,140 $ 996,466 $ 514,722 $5,043,158
=========== ========== =========== =============== ===========
Average sales price........................ $ 2.02 $ 13.28 $ 1.33 $ 13.97 $ 1.83
=========== ========== =========== =============== ===========
<CAPTION>
Net production volumes attributable (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
<S> <C> <C> <C> <C> <C>
to the Royalty paid...................... 2,006,444 159,004 749,222 36,852 2,755,666
=========== ========== =========== =============== ===========
<CAPTION>
OIL,
CONDENSATE
AND NATURAL
GAS LIQUIDS(2)
<S> <C>
Year ended December 31, 1998:
The Trust's proportionate share of --
Gross proceeds........................... $1,597,405
Less the Trust's proportionate share of --
Capital costs recovered(1)............... --
Operating costs.......................... (177,086)
Interest on cost carryforward............ --
------------
Royalty income............................. $1,420,319
============
Average sales price........................ $ 10.78
============
Net production volumes attributable (Bbls)
to the Royalty paid....................... 131,796
============
Year ended December 31, 1997:
The Trust's proportionate share of --
Gross proceeds........................... $2,726,526
Less the Trust's proportionate share of --
Capital costs recovered(1)............... --
Operating costs.......................... (187,660)
Interest on cost carryforward............ --
------------
Royalty income............................. $2,538,866
============
Average sales price........................ $ 15.41
============
Net production volumes attributable (Bbls)
to the Royalty paid....................... 164,716
============
Year ended December 31, 1996:
The Trust's proportionate share of --
Gross proceeds........................... $2,789,035
Less the Trust's proportionate share of --
Capital costs recovered(1)............... --
Operating costs.......................... (163,173)
Interest on cost carryforward............ --
------------
Royalty income............................. $2,625,862
============
Average sales price........................ $ 13.41
============
Net production volumes attributable (Bbls)
<S> <C>
to the Royalty paid...................... 195,856
============
</TABLE>
For a discussion of the method used to compute the net production volumes
in the table above, see Note 6 in the Notes to Financial Statements.
- ------------
(1) Capital costs recovered represents capital costs incurred during the current
or prior periods to the extent that such costs have been recovered by the
applicable working interest owners from current period gross proceeds. Cost
carryforward represents capital costs incurred during the current or prior
periods which will be recovered from future period gross proceeds. The cost
carryforward resulting from the Fruitland Coal drilling program was
$456,377, $475,335 and $456,198 at December 31, 1998, 1997 and 1996,
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.
24
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
MESA ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------------
1998 1997 1996
---------------- ---------------- ----------------
Royalty income.............................................. $ 6,209,778 $ 9,287,406 $ 7,669,020
<S> <C> <C> <C>
Interest income............................................. 73,714 109,948 90,384
General and administrative expenses......................... (35,276) (38,778) (70,032)
---------------- ---------------- ----------------
Distributable income........................................ $ 6,248,216 $ 9,358,576 $ 7,689,372
================ ================ ================
Distributable income per unit............................... $ 3.3528 $ 5.0218 $ 4.1261
================ ================ ================
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------
1998 1997
---------------- ----------------
<S> <C> <C>
ASSETS
Cash and short-term investments............................................... $ 1,002,130 $ 2,071,790
Interest receivable........................................................... 10,836 32,350
Net overriding royalty interests in oil and gas properties.................... 42,498,034 42,498,034
Less: accumulated amortization........................................... (28,608,479) (26,985,308)
---------------- ----------------
Total assets.................................................................. $ 14,902,521 $ 17,616,866
================ ================
LIABILITIES AND TRUST CORPUS
Distributions payable......................................................... $ 1,012,966 $ 2,104,140
Trust corpus (1,863,590 units of beneficial
interest authorized and outstanding)........................................ 13,889,555 15,512,726
---------------- ----------------
Total liabilities and trust corpus............................................ $ 14,902,521 $ 17,616,866
================ ================
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------------
1998 1997 1996
---------------- ---------------- ----------------
Trust corpus, beginning of year............................. $ 15,512,726 $ 17,414,537 $ 19,626,839
<S> <C> <C> <C>
Distributable income................................... 6,248,216 9,358,576 7,689,372
Distributions to unitholders........................... (6,248,216) (9,358,576) (7,689,372)
Amortization of net overriding royalty interests....... (1,623,171) (1,901,811) (2,212,302)
---------------- ---------------- ----------------
Trust corpus, end of year................................... $ 13,889,555 $ 15,512,726 $ 17,414,537
================ ================ ================
</TABLE>
The accompanying notes are an integral part of these financial statements.
25
<PAGE>
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"), a
subsidiary of E. I. duPont de Nemours & Company. Conoco sold the portion of its
interests in the San Juan Basin Royalty Properties located in Colorado to
MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow
Production Company (effective April 1, 1992). On October 26, 1994, MarkWest
Energy Partners, Ltd. sold substantially all of its interest in the Colorado San
Juan Basin Royalty Properties to Amoco Production Company ("Amoco"), a
subsidiary of Amoco Corp. Until August 7, 1997, MESA Inc. operated the Hugoton
Royalty Properties through Mesa Operating Co., 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.
Chase Bank of Texas, National Association (the "Trustee") is trustee for
the Trust. The terms of the Mesa Royalty Trust Indenture (the "Trust
Indenture") provide, among other things, that:
(a) the Trust cannot engage in any business or investment activity or
purchase any assets;
(b) the Royalty can be sold in part or in total for cash upon approval
of the unitholders;
(c) the Trustee can establish cash reserves and borrow funds to pay
liabilities of the Trust and can pledge the assets of the Trust to
secure payment of the borrowings;
(d) the Trustee will make cash distributions to the unitholders in
January, April, July and October each year as discussed more fully in
Note 4;
(e) the Trust will terminate upon the first to occur of the following
events: (i) at such time as the Trust's royalty income for each of two
successive years is less than $250,000 per year or (ii) a vote by the
unitholders in favor of termination. Upon termination of the Trust, the
Trustee will sell for cash all the assets held in the Trust estate and
make a final distribution to unitholders of any funds remaining after
all Trust liabilities have been satisfied; and
(f) PNR, Conoco and Amoco (collectively the "Working Interest
Owners") will reimburse the Trust for 59.34%, 27.45% and 1.77%,
respectively, for general and administrative expenses of the Trust.
(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.
26
<PAGE>
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
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 generally accepted accounting principles
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.
(5) FEDERAL INCOME TAXES
The Trustee reports on the basis that the Trust is a grantor trust. Based
on its previous audit policy, the Internal Revenue Service (the "IRS") is
expected to concur with such action. No IRS ruling has been received or
requested with respect to the Trust, however, and no court case has been decided
involving identical facts and circumstances. It is possible, therefore, that the
IRS would assert upon audit that the Trust is taxable as a corporation and that
a court might agree with such assertion.
As a grantor trust, the Trust will incur no federal income tax liability.
In addition, it will incur little or no federal income tax liability if it is
held to be a non-grantor trust. If the Trust were held to be taxable as a
corporation, it would have to pay tax on its net taxable income at the corporate
rate.
(6) SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
Estimates of the proved oil and gas reserves attributable to the Hugoton
Royalty Properties as of December 31, 1998, 1997 and 1996 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 interest were
estimated by allocating to the Trust a portion of the estimated combined net
reserve volumes of the Hugoton Royalty Properties based on future net revenue.
Production volumes are allocated based on royalty income. Because the net
reserve volumes attributable to the Trust 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
27
<PAGE>
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
reserve volumes. Therefore, the estimated net reserve volumes attributable to
the Trust 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 were based on prices in effect as of each
year end and existing contract terms. Prices being received as of each year end
were used for sales of oil, condensate and natural gas liquids. 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.
28
<PAGE>
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
ESTIMATED QUANTITIES OF PROVED AND PROVED DEVELOPED RESERVES (UNAUDITED)
<TABLE>
<CAPTION>
OIL,
CONDENSATE
AND
NATURAL GAS
LIQUIDS NATURAL GAS
<S> <C> <C>
(BBLS) (MCF)
Proved Reserves:
December 31, 1995............................................................... 2,034,794 43,516,041
Revisions to previous estimates.............................................. 33,843 (1,945,600)
Production................................................................... (195,856) (2,755,666)
----------- -----------
December 31, 1996............................................................... 1,872,781 38,814,775
Revisions to previous estimates.............................................. (21,556) (323,513)
Production................................................................... (164,716) (2,886,137)
----------- -----------
December 31, 1997............................................................... 1,686,509 35,605,125
Revisions to previous estimates.............................................. 65,215 (1,841,219)
Production................................................................... (131,796) (2,350,209)
----------- -----------
December 31, 1998............................................................... 1,619,928 31,413,697
=========== ===========
Proved Developed Reserves:
December 31, 1996............................................................... 1,832,781 38,170,775
=========== ===========
December 31, 1997............................................................... 1,667,509 35,311,125
=========== ===========
December 31, 1998............................................................... 1,591,928 31,019,697
=========== ===========
</TABLE>
- ------------
1/5 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: 1998, 57,000 Bbls; 1997, 24,000 Bbls; 1996,
42,000 Bbls.
1/5 The Hugoton Royalty represents 46%, 61% and 64% of the estimated proved oil,
condensate and natural gas liquids reserves and 54%, 65% and 65% of the
estimated proved natural gas reserves as of December 31 of 1998, 1997 and
1996, respectively.
STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM PROVED OIL
AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (UNAUDITED)
<TABLE>
<CAPTION>
DECEMBER 31
------------------------
1998 1997
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
The Trust's proportionate share of future gross proceeds.............................. $ 137,913 $ 176,084
Less the Trust's proportionate share of --
Future operating costs.............................................................. (67,907) (74,242)
Future capital costs................................................................ (2,154) (3,850)
----------- -----------
Future royalty income................................................................. 67,852 97,992
Discount at 10% per annum............................................................. (37,648) (50,963)
----------- -----------
Standardized measure of future royalty income from
proved oil and gas reserves......................................................... $ 30,204 $ 47,029
=========== ===========
</TABLE>
29
<PAGE>
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
CHANGES IN THE STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME
FROM PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (UNAUDITED)
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------
1998 1997 1996
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure at beginning of year.............................. $ 47,029 $ 81,469 $ 43,372
----------- ----------- -----------
Revisions of previous estimates...................................... (3,790) (1,936) (1,479)
Net changes in price and production costs............................ (11,528) (31,364) 42,908
Royalty income....................................................... (6,210) (9,287) (7,669)
Accretion of discount................................................ 4,703 8,147 4,337
----------- ----------- -----------
Net changes in standardized measure.................................. (16,825) (34,440) 38,097
----------- ----------- -----------
Standardized measure at end of year.................................... $ 30,204 $ 47,029 $ 81,469
=========== =========== ===========
</TABLE>
- ------------
1/5 The Hugoton Royalty represents approximately 56% and 67% of the standardized
measure of future royalty income for 1998 and 1997, respectively.
(7) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
SUMMARIZED QUARTERLY RESULTS
THREE MONTHS ENDED
------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
------------- ------------- ------------- ------------
1998:
<S> <C> <C> <C> <C>
Royalty income..................................... $ 2,183,079 $ 1,620,266 $1,400,356 $ 1,006,077
Distributable income............................... $ 2,189,509 $ 1,633,078 $1,412,663 $ 1,012,966
Distributable income per unit...................... $ 1.1749 $ .8763 $ .7580 $ .5436
1997:
Royalty income..................................... $ 3,862,915 $ 1,648,915 $1,698,336 $ 2,077,240
Distributable income............................... $ 3,897,302 $ 1,652,640 $1,704,494 $ 2,104,140
Distributable income per unit...................... $ 2.0912 $ .8868 $ .9146 $ 1.1292
</TABLE>
30
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO CHASE BANK OF TEXAS, NATIONAL ASSOCIATION (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, 1998 and 1997, and the
related statements of distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 1998. 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 generally accepted auditing
standards. 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
generally accepted accounting principles.
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, 1998 and 1997, and its distributable income and
changes in trust corpus for each of the three years in the period ended December
31, 1998, on the basis of accounting described in Note 3.
ARTHUR ANDERSEN LLP
Houston, Texas
March 26, 1999
31
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There are no directors or executive officers of the Registrant. The Trustee
is a corporate trustee which may be removed by the affirmative vote of the
majority at a meeting of the holders of units of beneficial interest of the
Trust at which a quorum is present.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS.
The following information has been taken from filings with the Securities
and Exchange Commission on Forms 13D and 13G and Form 4.
<TABLE>
<CAPTION>
AMOUNT
AND NATURE PERCENT
TITLE OF CLASS OF NAME AND ADDRESS OF BENEFICIAL OF
VOTING SECURITIES OF BENEFICIAL OWNER OWNERSHIP(1) CLASS
- ----------------------------------------- ----------------------------------------- ------------- -------
<S> <C> <C> <C>
Units of Beneficial Interest............. Alpine Capital, L.P. 720,716(2) 38.7%
201 Main Street, Suite 3100
Fort Worth, Texas 76102
Units of Beneficial Interest............. Beck, Mack & Oliver LLC 307,920(3) 16.52%
330 Madison Avenue
New York, NY 10017
</TABLE>
- ------------
(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. 12 dated March 22,
1999 of Alpine Capital, L.P. ("Alpine"), Robert W. Bruce III, Algenpar,
Inc., J. Taylor Crandall, The Anne T. Bass and Robert M. Bass Foundation,
Anne T. Bass and Robert M. Bass, and from Form 4's filed by Alpine, Mr.
Bruce, Algenpar, Inc. and Mr. Crandall dated February 9, 1999. Alpine
directly owns and has sole voting and dispositive power with respect to all
of such units. Such number of units does not include 49,784 units (which
constitutes approximately 2.7% 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 49,784 units owned by the
Foundation, may be deemed to be a beneficial owner of the 720,716 units
owned by Alpine and the 49,784 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 720,716
units owned by Alpine and the 49,784 units owned by the Foundation.
(3) Information obtained from Schedule 13G dated January 25, 1999 of Beck, Mack
& Oliver LLC ("BMO"). BMO has shared dispositive power with respect to all
of such units. All of such units are owned by the investment advisory
clients of BMO.
(B) SECURITY OWNERSHIP OF MANAGEMENT. Not applicable.
32
<PAGE>
(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.
<TABLE>
<CAPTION>
PAGE IN THIS
FORM 10-K
<S> <C>
Statements of Distributable Income................................................................... 25
Statements of Assets, Liabilities and Trust Corpus................................................... 25
Statements of Changes in Trust Corpus................................................................ 25
Notes to Financial Statements........................................................................ 26
Report of Independent Public Accountants............................................................. 31
</TABLE>
(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.)
<TABLE>
<CAPTION>
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
<S> <C> <C> <C>
4(a) * Mesa Royalty Trust Indenture between Mesa Petroleum Co. and Texas
Commerce Bank National Association, as Trustee, dated November 1,
1979............................................................... 2-65217 1(a)
4(b) * Overriding Royalty Conveyance between Mesa Petroleum Co. and Texas
Commerce Bank, as Trustee, dated November 1, 1979.................. 2-65217 1(b)
4(c) * First Amendment to the Mesa Royalty Trust Indenture dated as of
March 14, 1985 (Exhibit 4(c) to Form 10-K for year ended December
31, 1984 of Mesa Royalty Trust).................................... 1-7884 4(c)
4(d) * Form of Assignment of Overriding Royalty Interest, effective April
1, 1985, from Texas Commerce Bank National Association, as Trustee,
to MTR Holding Co. (Exhibit 4(d) to Form 10-K for year ended
December 31, 1984 of Mesa Royalty Trust)........................... 1-7884 4(d)
4(e) * Purchase and Sale Agreement, dated March 25, 1991, by and among
Mesa Limited Partnership, Mesa Operating Limited Partnership and
Conoco, as amended on April 30, 1991 (Exhibit 4(e) to Form 10-K for
year ended December 31, 1991 of Mesa Royalty Trust)................ 1-7884 4(e)
27 Financial Data Schedule
</TABLE>
(B) REPORTS ON FORM 8-K.
No reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust during the fourth quarter of 1998.
33
<PAGE>
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 CHASE BANK OF TEXAS, NATIONAL
ASSOCIATION, TRUSTEE
By _______/s/__PETE FOSTER____________
Pete Foster
Senior Vice President
& Trust Officer
March 26, 1999
The Registrant, Mesa Royalty Trust, has no principal executive officer,
principal financial officer, board of directors or persons performing similar
functions. Accordingly, no additional signatures are available and none have
been provided.
34
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
SEC FILE
OR
REGISTRATION
NUMBER
<S> <C> <C>
4(a) * Mesa Royalty Trust Indenture between Mesa Petroleum Co. and Texas
Commerce Bank National Association, as Trustee, dated November 1,
1979............................................................... 2-65217
4(b) * Overriding Royalty Conveyance between Mesa Petroleum Co. and Texas
Commerce Bank, as Trustee, dated November 1, 1979.................. 2-65217
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(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(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
27 Financial Data Schedule
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE 1998
FORM 10K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 1,002,130
<SECURITIES> 0
<RECEIVABLES> 10,836
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,012,966
<PP&E> 42,498,034
<DEPRECIATION> (28,608,479)
<TOTAL-ASSETS> 14,902,521
<CURRENT-LIABILITIES> 1,012,966
<BONDS> 0
<COMMON> 0
0
0
<OTHER-SE> 13,889,555
<TOTAL-LIABILITY-AND-EQUITY> 14,902,521
<SALES> 0
<TOTAL-REVENUES> 6,283,492
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 35,276
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 6,248,216
<INCOME-TAX> 0
<INCOME-CONTINUING> 6,248,216
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 6,248,216
<EPS-PRIMARY> 3.35
<EPS-DILUTED> 3.35
</TABLE>
