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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, 1995
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM
_________________ TO _________________
COMMISSION FILE NUMBER 1-7884
MESA ROYALTY TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 74-6284806
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
TEXAS COMMERCE BANK
NATIONAL ASSOCIATION
CORPORATE TRUST DIVISION
712 MAIN STREET
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 216-5100
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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UNITS OF BENEFICIAL INTEREST NEW YORK STOCK EXCHANGE
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of 1,863,590 Units of Beneficial Interest in
Mesa Royalty Trust held by non-affiliates of the registrant at the closing
sales price on March 20, 1996, of $40.00 was $74,543,600.
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 20, 1996, 1,863,590 Units of Beneficial Interest in Mesa
Royalty Trust.
Documents Incorporated By Reference: None.
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<PAGE>
TABLE OF CONTENTS
PART I
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PAGE
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Item 1. Business........................................................................................ 1
Description of the Trust........................................................................ 1
Description of the Units........................................................................ 3
Description of Royalty Properties............................................................... 5
Contracts....................................................................................... 21
Regulation and Prices........................................................................... 22
Item 2. Properties...................................................................................... 24
Item 3. Legal Proceedings............................................................................... 24
Item 4. Submission of Matters to a Vote of Security Holders............................................. 24
PART II
Item 5. Market for the Registrant's Common Equity and Related Unitholder Matters........................ 25
Item 6. Selected Financial Data......................................................................... 25
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.................................................................................... 25
Item 8. Financial Statements and Supplementary Data..................................................... 28
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.................................................................................... 35
PART III
Item 10. Directors and Executive Officers of the Registrant.............................................. 35
Item 11. Executive Compensation.......................................................................... 35
Item 12. Security Ownership of Certain Beneficial Owners and Management.................................. 35
Item 13. Certain Relationships and Related Transactions.................................................. 36
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................................ 36
SIGNATURES................................................................................................. 37
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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, including without
limitation the statements under "Business -- Description of the Trust"
regarding the financial position of MESA Inc. and its potential effects on the
Trust, are forward-looking statements. Although the Working Interest Owners
have advised the Trust that they believe that the expectations reflected in
the forward-looking statements contained herein are reasonable, no assurance
can be given that such expectations will prove to have been correct. Important
factors that could cause actual results to differ materially from expectations
("Cautionary Statements") are disclosed in this Form 10-K, including without
limitation in conjunction with the forward-looking statements included in this
Form 10-K. All subsequent written and oral forward-looking statements
attributable to the Trust or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.
PART I
ITEM 1. BUSINESS.
DESCRIPTION OF THE TRUST
The Mesa Royalty Trust (the "Trust"), created under the laws of the State
of Texas, maintains its offices at the office of the Trustee, Texas Commerce
Bank National Association (the "Trustee"), 712 Main Street, Houston, Texas
77002. The telephone number of the Trust is (713) 216-5100.
The Trust was created on November 1, 1979 when Mesa Petroleum Co.
conveyed to the Trust a 90% net profits overriding royalty interest (the
"Royalty") in certain producing oil and gas properties located in the Hugoton
field of Kansas, the San Juan Basin field of New Mexico and Colorado, and the
Yellow Creek field of Wyoming (collectively, the "Royalty Properties"). Mesa
Petroleum Co. was the predecessor to Mesa Limited Partnership ("MLP") which
was the predecessor to MESA Inc. On April 30, 1991, MLP sold its interests in
the Royalty Properties located in the San Juan Basin field to Conoco Inc.
("Conoco"), a wholly-owned subsidiary of E. I. duPont de Nemours & Company.
Conoco sold the portion of its interests in the San Juan Basin Royalty
Properties located in Colorado to MarkWest Energy Partners, Ltd. (effective
January 1, 1993) and Red Willow Production Company (effective April 1, 1992).
MarkWest Energy Partners, Ltd. and Red Willow Production Company are referred
to collectively herein as "MarkWest". On October 26, 1994, MarkWest Energy
Partners, Ltd. sold substantially all of its interest in the Colorado San Juan
Basin Royalty Properties to Amoco Production Company ("Amoco"), a subsidiary
of Amoco Corp. The Hugoton Royalty Properties are operated by Mesa Operating
Co., a subsidiary of MESA Inc., and MESA Inc.'s interest in such properties is
owned by Hugoton Capital Limited Partnership, another MESA Inc. subsidiary.
The San Juan Basin Royalty Properties located in New Mexico are operated by
Conoco. The San Juan Basin Royalty Properties located in Colorado are operated
by Amoco. As used in this report, the term "Mesa" generally refers to the
operator of the Hugoton Royalty Properties, Conoco refers to the operator of
the 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
$5,941,088 and $6,927,776 for the years 1995 and 1994, 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" on page 5 of
this Form 10-K. The Conveyance provides for a monthly computation of Net
Proceeds. "Net Proceeds" means the excess of Gross Proceeds, as hereinafter
defined, received by the working interest owners during a particular period
over operating and capital costs for such period. "Gross Proceeds" means the
amount received by the working interest owners from the sale of minerals
1
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 the 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 thirty 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 addition, MESA Inc. has advised the Trust that its independent public
accountants included a going concern paragraph in their report on its 1995
financial statements. The going concern paragraph refers to MESA Inc.'s
current financial forecasts, which indicate that MESA Inc. will be unable to
fund required debt principal and interest obligations due in June 1996 with
cash flows from operating activities, available cash, and investment balances.
In an effort to address its liquidity issues, in July 1995 MESA Inc.'s Board
of Directors approved and implemented a proposal solicitation process which
expanded its exploration of strategic alternatives from the selling of the
Hugoton field to include consideration of the sale of MESA Inc., a
stock-for-stock merger, joint ventures, asset sales, equity infusions, and
refinancing transactions. On February 28, 1996, MESA Inc. signed a letter of
intent with Rainwater, Inc. (Rainwater), an independent investment company
owned by Ft. Worth, Texas investor Richard Rainwater, to raise $265 million of
equity in connection with a refinancing of MESA Inc.'s debt. The proposed
transaction is subject to certain conditions, including negotiation and
execution of definitive agreements, arrangement of the new debt financing, due
diligence by Rainwater and MESA Inc. stockholder approval. There can be no
assurance that this transaction will be completed or what the final terms or
timing thereof will be. Further, there can be no assurance regarding the
availability or terms of any refinancing debt.
If the Rainwater transaction is not completed, MESA Inc. has advised the
Trust it will pursue other alternatives to address its liquidity issues and
financial condition, including other potential transactions arising from the
proposal solicitation process, the possibility of seeking to restructure its
balance sheet by negotiating with its current debt holders or seeking
protection from its creditors under the Federal Bankruptcy Code.
2
MESA Inc.'s projected debt service problems, as well as any refinancing,
restructuring or other strategic alternative, could have significant effects
on the Trust, although the precise nature of such effects cannot be predicted
or quantified at this time. No assurance can be given by the Trust regarding
MESA Inc.'s financial condition. An event of bankruptcy of MESA Inc. could
result in a delay in receipt of royalty payments by the Trust, increased
administrative expenses of the Trust and other effects which cannot be
predicted or quantified at this time.
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 22, 1996.
DISTRIBUTIONS
The Trustee determines for each month the amount of cash available for
distribution for such month. Such amount (the "Monthly Distribution Amount")
consists of the cash received from the Royalty during such month less the
obligations of the Trust paid during such month, adjusted for changes made by
the Trustee during such month in any cash reserves established for the payment
of contingent or future obligations of the Trust. The Monthly Distribution
Amount for each month is payable to unitholders of record on the monthly
record date (the "Monthly Record Date") which is the close of business on the
last business day of such month or such other date as the Trustee determines
is required to comply with legal or stock exchange requirements. However, to
reduce the administrative expenses of the Trust, under the Trust Indenture the
Trustee does not distribute cash monthly, but rather, during January, April,
July and October of each year distributes to each person who was a unitholder
of record during one or more of the immediately preceding three months, 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 Texas Commerce Bank National Association or the interest rate which Texas
Commerce Bank 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.
3
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 under the Revenue Act of 1987, 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.
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, and classified as either long-term or short-term depending on
the holding period of the unit. Presently, long term treatment applies for
units held more than one year. 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, it is
expected that 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 (collectively "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
4
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 unitholders 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.
DESCRIPTION OF ROYALTY PROPERTIES
PRODUCING ACREAGE AND WELLS AS OF DECEMBER 31, 1995
<TABLE>
<CAPTION>
PRODUCING GAS
PRODUCING ACRES(1) WELLS(1)(2)
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GROSS NET GROSS NET
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Hugoton Area (Kansas)(3).......................... 103,364 103,114 465 464.1
San Juan Basin (Northwestern New Mexico and
Southwestern Colorado).......................... 40,716 31,328 371 189.7
------- ------- ----- -----
Total.................................. 144,080 134,442 836 653.8
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(1) The Trust does not have a working interest in the producing acres and
producing gas wells. The gross and net amounts in the table above
represent gross and net amounts attributable to the working interest
owners and are the basis for the Gross Proceeds amounts discussed under
"Description of the Trust" on page 1 of this Form 10-K.
(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 81% of the Trust's reserves and was carved out of Mesa'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").
5
HUGOTON FIELD INFILL DRILLING
On April 25, 1986, the KCC issued an order authorizing a four-year phased
program of infill drilling within the Hugoton field. Under such program,
producers were permitted to drill up to 25% of the total number of infill
wells for which they qualified each calendar year. Mesa commenced its infill
drilling program in early 1987 and by the second quarter of 1989, all of the
151 qualifying infill wells in which the Trust has an interest had been
completed, as Mesa elected to drill its allotment of qualifying wells
primarily on acreage dedicated to the Trust. Drilling and completion costs on
each infill well were approximately $165,000 per well. Production from the
Hugoton infill wells began in January 1988.
SAN JUAN BASIN
The Trust's interest in the San Juan Basin was conveyed from Mesa'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 19% 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. Mesa completed the sale of its underlying interest in the San Juan
Basin Royalty Properties to Conoco on April 30, 1991. Conoco subsequently sold
its underlying interest in the Colorado portion of the San Juan Basin Royalty
Properties to MarkWest Energy Partners, Ltd. (effective January 1, 1993) and
Red Willow Production Company (effective April 1, 1992). On October 26, 1994,
MarkWest Energy Partners, Ltd. sold substantially all of its interest in the
Colorado San Juan Basin Royalty Properties to Amoco. See "Description of the
Trust" on page 1 of this Form 10-K. The San Juan Basin Royalty Properties
located in Colorado account for less than 5% of the Trust's reserves.
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, 1995, 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, 42 (24.6 net) have been successfully completed, of which 37 (22.9 net)
are producing at a combined rate of 62.8 (32.3 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. This amount includes
expenditures of approximately $5.0 million for pipeline connections,
compressors, salt water disposal systems, and clean-up of the areas
surrounding certain wells. The Trust's share of the total expenditures was
approximately $2.4 million. The Trust's share of the cost of drilling and
completing the Fruitland Coal wells was subject to recovery by the working
interest owner on a state-by-state basis before distributions were made from
the San Juan Basin Royalty. Accordingly, no distributions related to the San
Juan Basin Royalty were made from August 1990 through November 1992 as a
result of the costs associated with the Fruitland Coal wells. 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. 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."
6
RESERVES
A study of the proved oil and gas reserves attributable to the Hugoton
Royalty as of December 31, 1995 has been made by MESA Inc. The following
letter (the "Mesa Reserve Report") summarizes such reserve study, and
references to the reserves of the Trust and the future net revenue and present
worth attributable to the Trust interest in the Mesa Reserve Report refer to
the Trust's interest in the Hugoton Royalty Properties. The Mesa 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.
The Mesa Reserve Report reflects an increase in the future net revenue
and present worth attributable to the Trust's interest in the Hugoton Royalty
Property due to a change in the treatment of gathering charges. Prior reserve
reports charged gathering costs against Trust revenues. This is inconsistent
with the way Net Proceeds is calculated. The Mesa Reserve Report excludes
gathering costs if not in the vicinity of the well to be consistent with the
calculation of Net Proceeds.
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, 1995 has been made by
Conoco, the working interest owner of such properties. The Conoco report
(together with the Mesa Reserve Report, the "Reserve Reports") on page 16
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.
7
MESA INC.
SUMMARY REPORT
DATED
FEBRUARY 28, 1996
ON
RESERVES AND REVENUE
AS OF
DECEMBER 31, 1995
FROM CERTAIN PROPERTIES
OWNED BY
MESA ROYALTY TRUST
8
February 28, 1996
MESA Royalty Trust
Texas Commerce Bank
National Association (as Trustee)
P.O. Box 2558
Houston TX 77252
Gentlemen:
Pursuant to your request, we have prepared estimates, as of December 31, 1995,
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 Mesa
Operating Co. hereinafter referred to as "MESA". These properties are located in
the Kansas Hugoton and Panoma-Council Grove fields in Kansas. MESA is 100
percent owned by MESA Inc., the successor to Mesa Limited Partnership.
Our 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, 1995. 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.
Reserves and revenue values shown in this report were estimated from projections
of reserves and revenue attributable to the combined MESA 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 the Trust
9
Page 2
February 28, 1996
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, 1995 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, 1995. In our preparation of the study, data available from wells drilled on
the appraised properties through December 31, 1995 were used in estimating gross
ultimate recovery. Gross production estimated to December 31, 1995, was deducted
from gross ultimate recovery to arrive at the estimates of gross reserves as of
December 31, 1995. In these fields, this required that the production rates be
estimated for up to two months since production data for certain properties were
available only through October 1995.
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
analyses, 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:
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 hydrocarbonsaturated material above
known fluid contacts, if any, or above the lowest known structural
occurrence of hydrocarbons.
10
Page 3
February 28, 1996
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 analyses from the particular
zones. Nonproducing reserves require only moderate expense to be
brought into production.
UNDEVELOPED -- Reserves that are recoverable from additional wells yet
to be drilled.
Undeveloped reserves are those considered proved for production by
reasonable geological interpretation of adequate subsurface control in
reservoirs that are producing or proved by other wells but are not
recoverable from existing wells. This classification of reserves
requires drilling of additional wells, major deepening of existing
wells, or installation of enhanced recovery or other facilities.
Reserves recoverable by enhanced recovery methods, such as injection of external
fluids to provide energy not inherent in the reservoirs, may be classified as
proved developed or proved undeveloped reserves depending upon the extent to
which such enhanced recovery methods are in operation. These reserves are
considered to be proved only in cases where a successful fluid injection program
is in operation, a pilot program indicates successful fluid injection, or
information is available concerning the successful application of such methods
in the same reservoir and it is reasonably certain that the program will be
implemented.
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, 1995, are as follows:
TOTAL PROVED RESERVES
Natural Gas (Mcf)......................... 34,988,041
Helium (Mcf).............................. 90,656
Natural Gas Liquids (bbl)................. 1,690,794
PROVED DEVELOPED RESERVES
Natural Gas (Mcf)......................... 34,988,041
Helium (Mcf).............................. 90,656
Natural Gas Liquids (bbl)................. 1,690,794
11
Page 4
February 28, 1996
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. Changes in Hugoton field reserves reflect MESA's
practice of recovering ethane at the Satanta Plant. In previous years Hugoton
proved reserve estimates were prepared assuming that MESA would not recover
ethane which resulted in slightly higher natural gas volumes and lower natural
gas liquids volumes. The decision as to whether or not to recover ethane is
economic and based on the relative value of ethane as a liquid versus the
energy-equivalent value of such ethane if left in the residue natural gas. In
the future, if economic conditions warrant, MESA may revise proved reserves to
reflect any changes in such relative values.
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.
The KCC held hearings from August 1992 to September 1993 to consider changes to
the methods in which fieldwide allowables are allocated among individual wells
within the Hugoton field. Specifically, the KCC considered proposals from
various producers to amend calculations of well deliverability, the allocation
of allowables for infilled units, and the make up of underages from prior
periods. On February 2, 1994, the KCC issued an order, effective as of April 1,
1994, establishing new field rules which modify the formulas and calculations
used to allocate allowables among wells in the field. The standard pressure used
in each well's calculated deliverability was reduced by 35%, greatly benefitting
MESA Inc. high deliverability wells. Also, the new rules assign a 30% greater
allowable to 640-acre units with infill wells than similar units without infill
wells. Essentially all of MESA Inc. Hugoton infill wells have been drilled,
resulting in an increase to MESA Inc. in assigned allowables beginning in April,
1994. The new field rules also allow Hugoton producers to make up pre-1994
canceled underages over a 10-year period.
MESA Inc. 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 salable gas; however,
neither the gross nor net volumes were reduced for plant fuel usage, which is
estimated to be 12.5 billion cubic feet of gross wet gas. The value of this fuel
is deducted as part of the plant operating costs.
Revenue values in this report were estimated using current prices and costs.
Future prices were estimated using guidelines established by the Securities and
Exchange Commission and the Financial Accounting Standards Board.
The assumptions used for estimating future prices and costs are as follows:
NATURAL GAS PRICES
Gas prices were held constant for the life of the properties.
12
Page 5
February 28, 1996
NATURAL GAS LIQUIDS AND HELIUM PRICES
Natural gas liquids and helium prices were held constant for the life of the
properties.
The initial and future prices and producing rates used in this report are those
that the Trust could reasonably expect to be received over the life of the
properties.
OPERATING AND CAPITAL COSTS
Estimates of operating costs based on current costs were used for the life of
the properties with no increases in the future based on inflation. Future
capital expenditures were estimated using 1995 values and were not adjusted for
inflation.
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, 1995 is as follows:
COMBINED INTEREST:
Future Gross Revenue ($)................................ 1,305,747,681
Production Taxes ($).................................... (39,426,501)
Ad Valorem Taxes ($).................................... (79,262,918)
Operating Costs ($)..................................... (120,699,996)
Capital Costs ($)....................................... (9,461,556)
------------------
Future Net Revenue ($)(1)............................... 1,056,896,710
Net Revenue Attributable to Plant Interests ($)......... (112,966,820)
Overhead ($)............................................ (140,039,424)
Deficit Balance and Interest on Deficit ($)............. 0
------------------
Revenue Subject to Net Profits Interest ($)(1)........... 803,890,466
TRUST INTEREST
Future Net Revenue ($)(1).............................. 82,742,999
Present Worth at 10 Percent ($)(1)..................... 35,147,310
(1) Future income tax expenses were not taken into account in the preparation of
these estimates. Approximately 3 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.
13
Page 6
February 28, 1996
To the extent the above enumerated rules, regulations, and statements require
determinations of an accounting or legal nature or information beyond the scope
of our report, we are necessarily unable to express an opinion as to whether the
above-described information is in accordance therewith or sufficient therefor.
Submitted,
/s/ DENNIS E. FAGERSTONE
Dennis E. Fagerstone
Vice President - Exploration and Production
14
CONOCO INC.
LETTER REPORT
DATED
MARCH 24, 1996
ON
RESERVES AND REVENUE
AS OF
DECEMBER 31, 1995
FROM
CERTAIN PROPERTIES
OWNED BY
MESA ROYALTY TRUST
15
March 20, 1996
Mesa Royalty Trust
Texas Commerce Bank
National Association (As Trustee)
P.O. Box 2558
Houston, Texas 77252
Re: MESA ROYALTY TRUST RESERVES AS OF DECEMBER 31, 1995
SAN JUAN BASIN PROPERTIES, NEW MEXICO
Gentlemen:
Pursuant to your request, estimates have been prepared as of December 31, 1995
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% 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, 1995. 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, abandonment costs, and capital 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. In this report, a discount rate of 10% is used with
mid-year discounting.
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 reserve
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.
16
Petroleum reserves included in this report are classified as proved and judged
to be economically producible in future years from known reservoirs under
existing economic and operating conditions. Total proved reserves are the sum of
developed and undeveloped reserves. Proved developed reserves are those
recoverable from existing wells with current operating methods and expenses, and
thus require little or no capital expenditure to produce. Proved undeveloped
reserves are those which require major capital expenditures for new wells and/or
facilities. Estimates of the MRT net reserves as of December 31, 1995 are
tabulated below.
<TABLE>
<CAPTION>
DEVELOPED + UNDEVELOPED Conventional Fruitland Total
TOTAL MRT NET PROVED RESERVES Reservoirs Coal Reservoirs All Reservoirs
SAN JUAN BASIN 12/31/95 12/31/95 12/31/95
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural Gas, MMcf 5,985 2,543 8,528
Condensate, Mbbl 26 0 26
Natural Gas Liquids, Mbbl 307 11 318
- --------------------------------------------------------------------------------------------------------------
DEVELOPED ONLY Conventional Fruitland Total
MRT NET PROVED RESERVES Reservoirs Coal Reservoirs All Reservoirs
SAN JUAN BASIN 12/31/95 12/31/95 12/31/95
- --------------------------------------------------------------------------------------------------------------
Natural Gas, MMcf 5,632 2,543 8,175
Condensate, Mbbl 24 0 24
Natural Gas Liquids, Mbbl 288 11 299
- --------------------------------------------------------------------------------------------------------------
</TABLE>
Some tabulated totals may not agree due to rounding.
The above values for year end 1995 reflect natural gas shrinkage of 8.9% for
conventional reservoirs due to processing and plant fuel use (no shrinkage for
Fruitland Coal gas), and an average net back to producing properties of 61% of
recovered natural gas liquids.
Product prices and operating costs used for year end 1995 are tabulated below.
Prices are held constant over the life of the properties, but operating costs
are adjusted after 1996 to reflect change in planned levels of conventional and
Fruitland Coal remedial activity.
PRODUCT PRICES 12/31/95
- -------------------------------------------------------------
Natural Gas, $ / Mcf 1.30
Condensate, $ / bbl 19.13
Natural Gas Liquids, $ / bbl 12.49
- -------------------------------------------------------------
17
12/31/95
OPERATING COSTS Through 1996 After 1996
- --------------------------------------------------------------------------------
Conventional Reservoirs, $ / well / year 15,500 12,300
Fruitland Coal Reservoirs, $ / well / year 17,500 26,700
- --------------------------------------------------------------------------------
Revenue and cash flow values in this report are based on product prices for San
Juan Basin effective in December 1995. The gas price excludes a transportation
expense of $0.43/Mcf. The price also excludes combined production and ad valorem
tax rates of 11.2% and 9.8% of revenue for conventional and Fruitland Coal gas,
respectively. These taxes and transportation expenses are also excluded from the
annual per well operating costs tabulated above.
Through 1996, operating costs for conventional gas wells are expected to remain
at 1994 levels, then drop due to reductions in planned remedial work. Fruitland
Coal operating costs are anticipated to be lower in 1996 due to reduced
partner-operated remedial work. However, after 1996, increased levels of
Fruitland Coal remedial activity are expected resulting in a return to
historical operating cost averages.
A summary of estimated future revenue, taxes, costs, cash flow, and present
worth attributable to Conoco net reserves as of December 31, 1995 is tabulated
below. Capital costs are associated with projects required to produce
undeveloped reserves and maintain existing production of developed reserves. All
costs are year end 1995 estimates and not adjusted for inflation.
<TABLE>
<CAPTION>
Conventional Fruitland Total
CONOCO NET INTEREST Reservoirs Coal Reservoirs All Reservoirs
SAN JUAN BASIN 12/31/95 12/31/95 12/31/95
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Future Revenue, M$ 360,103 84,134 444,237
Production and Ad Valorem
Taxes, M$ 40,332 8,245 48,577
Operating and Transportation
Costs, M$ 191,953 39,951 231,904
Abandonment Costs, M$ 1,377 155 1,532
Capital Costs, M$ 8,808 2,332 11,140
Future BFIT Cash Flow, M$ 117,633 33,451 151,084
Deficit Balance, M$ 0 0 0
Future BFIT Cash Flow Subject
to MRT Interest, M$ 117,633 33,451 151,084
Present Worth @ 10%, M$ 54,740 25,172 79,912
- --------------------------------------------------------------------------------------------------------------
</TABLE>
Some tabulated totals may not agree due to rounding.
18
A summary of estimated future revenue and present worth attributable to the MRT
interest as of December 31, 1995 is tabulated below.
<TABLE>
<CAPTION>
Conventional Fruitland Total
MRT INTEREST (10.29282%) Reservoirs Coal Reservoirs All Reservoirs
SAN JUAN BASIN 12/31/95 12/31/95 12/31/95
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Future BFIT Cash Flow, M$ 12,108 3,443 15,551
Present Worth @ 10%, M$ 5,634 2,591 8,225
- --------------------------------------------------------------------------------------------------------------
</TABLE>
Some tabulated totals may not agree due to rounding.
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.
Conoco Inc.
Reservoir Engineering and Reserves Tracking Group
Reservoir Technology Center
Exploration and Production - Technology
19
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 MESA Inc. 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 $1.77 per Mcf for Hugoton
properties and $1.30 per Mcf for San Juan properties as of December 31, 1995)
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 1995 was $1.39 per Mcf, representing a combination
of contract prices and spot market prices.
The future net revenues shown by the Reserve Reports have not been
reduced for costs and expenses of the Trust, which are expected to approximate
$50,000 annually. The costs and expenses of the Trust may increase in future
years, depending on the amount of Royalty income, increases in accounting,
engineering, legal and other professional fees and other factors.
The working interest owners have advised the Trustee that there have been
no events subsequent to December 31, 1995 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.
20
CONTRACTS
HUGOTON FIELD
Natural gas and natural gas liquids produced by Mesa from the Hugoton
field and attributable to the Royalty accounted for approximately 76% of the
Royalty income of the Trust during 1995.
Historically, Mesa's principal natural gas purchaser in the Hugoton field
has been Western Resources, Inc., previously the Kansas Power and Light
Company ("WRI"). Beginning on January 1, 1990, Mesa sold gas from the Hugoton
field to WRI pursuant to the contract (the "WRI Contract") described below.
The WRI Contract terminated on May 31, 1995.
The WRI Contract provided for WRI to purchase from 12.7 to 19.5 billion
cubic feet of gas per year (approximately 1.3 to 2.0 billion cubic feet of gas
per year net to the Trust subject to the effect of operating expenses and
capital costs) at market prices for a total of at least 92.4 billion cubic
feet of gas (approximately 10 billion cubic feet of gas net to the Trust
subject to the effect of operating expenses and capital costs) during the term
of the agreement as amended. Under the WRI Contract, WRI paid market clearing
prices as determined monthly based on a price index published by a third
party. The WRI Contract also contained take-or-pay provisions requiring WRI to
purchase and receive, or pay for if not taken, 85% of the nominated contract
quantities during each seasonal period. The WRI Contract provided WRI with
certain make-up rights during the one-year period following termination of the
WRI Contract. Upon termination of the WRI Contract on May 31, 1995, WRI
incurred a take-or-pay deficiency of approximately 2.0 billion cubic feet of
gas. WRI made up the entire amount of such deficiency during June 1995, and
the Trust received its proportionate share of the take-or-pay money in August
1995.
Mesa has advised the Trust that since June 1, 1995 natural gas previously
subject to the WRI Contract has been sold under short-term contracts at market
clearing prices to multiple purchasers, including WRI, and that Mesa expects
to continue to market production from the Hugoton field under short-term
contracts and multi-month contracts during 1996. In addition, Mesa advised the
Trust that it entered into a five month contract with WRI effective as of
November 1, 1995. The contract provides for WRI to purchase up to 25 MMcf per
day of gas at market clearing prices determined monthly based on third party
published index prices, plus five cents per MMbtu. Overall market prices
received for natural gas from the Hugoton Royalty Properties were lower in
1995 compared to 1994.
In June 1994, Mesa entered into a Gas Transportation Agreement with WRI
(the "Gas Transportation Agreement") for a primary term of five years
commencing June 1, 1995 and ending June 1, 2000, but which may be continued in
effect year-to-year thereafter. Pursuant to the Gas Transportation Agreement,
WRI has agreed to compress and transport up to 160 MMcf per day of gas and
redeliver such gas to Mesa at the inlet of Mesa's Satanta Plant. Mesa has
agreed to pay WRI a fee of $0.06 per Mcf escalating 4% annually beginning June
1, 1996.
Allowable rates of production in the Hugoton field are set by the Kansas
Corporation Commission (the "KCC") based on the level of market demand. The
KCC has set the Hugoton field allowable for the period October 1, 1995 through
March 31, 1996, at 242 billion cubic feet of gas, compared with 247 billion
cubic feet of gas during the same period last year.
The KCC held hearings during September 1995 to consider regulatory
changes to the manner in which field wide allowables are allocated among
individual wells within the Panoma field, a producing formation which directly
underlies the Hugoton field and which is included in the "Hugoton Royalty
Properties" as such term is used herein. Specifically, the KCC considered
proposals from various producers to amend calculations of well deliverability,
the allocation of allowables based on acreage and the makeup of underages. The
KCC held an Administrative Hearing on November 22, 1995 in which it agreed to
several changes to the Panoma Field Rules. The KCC then issued an order
effective as of November 1, 1995 under which the Hugoton Royalty Properties'
percentage of the field allowable assigned increased.
21
Mesa estimates the gross allowable production from the Hugoton Royalty
Properties will be approximately 42 billion cubic feet in 1996 versus 40.5
billion cubic feet in 1995.
SAN JUAN BASIN
Natural gas produced from the San Juan Basin field and attributable to
the Royalty accounted for approximately 24% of the Royalty income of the Trust
during 1995. 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,
declined to $1.64 per Mcf in 1991 and improved to $2.04 per Mcf in 1993 but
declined again to $1.57 (estimated) per Mcf in 1995, according to the Natural
Gas Monthly published by the Energy Information Administration of the
Department of Energy. Spot domestic natural gas prices have generally
increased in late 1995 and early 1996 and are higher than gas prices in early
1995.
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.
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. Many of these competitors have
financial resources greatly in excess of those of certain of the working
interest owners, particularly Mesa. 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.
Mesa 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 area 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.
NATURAL GAS REGULATIONS
Historically, interstate pipeline companies generally acted as wholesale
merchants by purchasing natural gas from producers and reselling the gas to
local distribution companies and large end-users. Commencing in late 1985, the
FERC issued a series of orders that have had a major impact on natural gas
pipeline operations, services and rates and thus have significantly altered
the marketing and price
22
of natural gas. The FERC's key rulemaking action, Order No. 636 ("Order 636"),
issued in April 1992, requires each pipeline company, among other things, to
"unbundle" its traditional wholesale services and create and make available on
an open and nondiscriminatory basis numerous constituent services (such as
gathering services, storage services, firm and interruptible transportation
services, and stand-by sales and gas balancing services) and to adopt a new
ratemaking methodology to determine appropriate rates for those services. To
the extent the pipeline company or its sales affiliate makes gas sales as a
merchant in the future, it does so in direct competition with all other
sellers pursuant to private contracts; however, pipeline companies and their
affiliates were not required to remain "merchants" of gas, and several of the
interstate pipeline companies have become "transporters only." In subsequent
orders, the FERC largely affirmed the major features of Order 636 and denied a
stay of the implementation of the new rules pending judicial review. In
addition, following the conclusion of individual restructuring proceedings for
each interstate pipeline pursuant to Order 636, the FERC has approved, with
modifications, all of the restructuring plans and generally accepted
compliance filings implementing Order 636 on every interstate pipeline as of
the end of 1994. Order 636, as well as the FERC orders approving the
individual pipeline compliance filings implementing Order 636, are the subject
of numerous appeals to the United States Courts of Appeal. The Working
Interest Owners have informed the Trust that they cannot predict whether the
orders will be affirmed on appeal or what the effects will be on the
production and pricing of natural gas relating to the Royalty Properties.
The Working Interest Owners have advised the Trust that they own,
directly or indirectly, certain natural gas facilities that they believe meet
the traditional tests the FERC has used to establish a company's status as a
gatherer not subject to FERC jurisdiction under the Natural Gas Act of 1938
(the "NGA"). Moreover, recent orders of the FERC have been more liberal in
their reliance upon or use of the traditional tests, such that in many
instances, what was once classified as "transmission" may now be "gathering."
The Working Interest Owners transport gas from the Royalty Properties through
these facilities. Other gas from the Royalty Properties is also transported
through gathering facilities owned by others, including interstate pipelines.
On May 27, 1994, the FERC issued orders in the context of the "spin-off" or
"spin-down" of interstate pipeline-owned gathering facilities. A "spin-off" is
a FERC-approved sale of such facilities to a non-affiliate. A "spin-down" is
the transfer by the interstate pipeline of its gathering facilities to an
affiliate. A number of spin-offs and spin-downs have been approved by the FERC
and implemented. The FERC held that it retains jurisdiction over gathering
provided by interstate pipelines but that it generally does not have
jurisdiction over pipeline gathering affiliates, except in the event of
affiliate abuse, such as actions by the affiliate undermining open and
nondiscriminatory access to the interstate pipeline. These orders require
nondiscriminatory access for all sources of supply, prohibit the tying of
pipeline transportation service to any service provided by the pipeline's
gathering affiliate, and require the new gathering company to submit a
"default" contract if a satisfactory contract cannot be mutually agreed upon
with existing customers. Several petitions for rehearing were filed. Pursuant
to a November 30, 1994 meeting, the FERC issued a series of rehearing orders
largely affirming the May 27, 1994 orders. The FERC clarified that "default"
contracts are intended to serve only as a transition mechanism to prevent
arbitrary termination of gathering service to existing customers. Also, the
FERC now requires that an interstate pipeline must not only seek authority
under Section 7(b) of the NGA to abandon certificated facilities, but also
must file for authority under Section 4 of the NGA to terminate service from
both certificated and uncertificated facilities. On December 31, 1994, an
appeal was filed with the U.S. Court of Appeals for the D.C. Circuit to
overturn three of the FERC's rehearing orders. The Working Interest Owners
have advised the Trust that they cannot predict what the ultimate effect of
the FERC's orders pertaining to gathering will have on their production and
marketing, or whether the Appellate Court will affirm the FERC's orders on
these matters.
23
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 recent changes to Mesa'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, but does not generally entail rate regulation. Natural gas
gathering has received greater regulatory scrutiny at both the state and
federal levels as the pipeline restructuring under Order 636 continues.
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 1995.
24
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,
1995, were as follows:
<TABLE>
<CAPTION>
1995 1994
----------------------------------- -----------------------------------
QUARTER HIGH LOW DISTRIBUTION HIGH LOW DISTRIBUTION
- ------------------------------ --------- --------- ------------ --------- --------- ------------
<S> <C> <C> <C> <C> <C> <C>
First......................... $ 43.50 $ 40.50 $ 1.1372 $ 46.38 $ 42.50 $ 1.2733
Second........................ $ 41.00 $ 39.75 $ .9870 $ 47.50 $ 44.25 $ .9866
Third......................... $ 42.50 $ 38.50 $ .7109 $ 45.00 $ 43.25 $ .8031
Fourth........................ $ 41.00 $ 38.00 $ .5842 $ 44.00 $ 43.00 $ .6751
</TABLE>
At March 20, 1996, the 1,863,590 units outstanding were held by 1,899
unitholders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991
-------------- -------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
Royalty income.................. $ 5,941,088 $ 6,927,776 $ 5,866,029 $ 3,124,236 $ 4,687,886
Distributable income............ $ 5,957,482 $ 6,967,277 $ 5,876,975 $ 3,021,875 $ 4,696,186
Distributable income per unit... $ 3.1967 $ 3.7386 $ 3.1536 $ 1.6215 $ 2.5200
Total assets at year end........ $ 20,715,506 $ 23,240,108 $ 25,432,085 $ 27,318,675 $ 28,541,100
</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 1995 AND 1994
The Trust's Royalty income was $5,941,088 in 1995, a decrease of
approximately 14%, as compared to $6,927,776 in 1994, primarily as a result of
lower natural gas production and prices.
Royalty income from the Hugoton Royalty Properties was $4,517,569 in
1995, a decrease of approximately 8%, as compared to $4,930,497 in 1994,
primarily as a result of decreased natural gas production and prices.
The average price received for natural gas and natural gas liquids from
the Hugoton Royalty Properties was $1.48 per Mcf and $10.72 per barrel,
respectively, in 1995 as compared to $1.68 per Mcf and $9.86 per barrel,
respectively, in 1994. Net production attributable to the Hugoton Royalty was
1,882,578 Mcf of natural gas and 161,820 barrels of natural gas liquids in
1995 as compared with 1,994,048 Mcf of natural gas and 154,545 barrels of
natural gas liquids in 1994.
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
$1,423,519 in 1995 as compared to $1,997,279 in 1994 due primarily to lower
25
natural gas production and prices. No Royalty income was received from
MarkWest or Amoco with respect to the San Juan Basin Royalty Properties
located in the state of Colorado in 1995 or 1994, as costs associated with the
development drilling program for Royalty Properties in that state have not
been fully recovered.
The average price received for natural gas and natural gas liquids, oil
and condensate from the San Juan Basin Royalty Properties was $1.19 per Mcf
and $11.12 per barrel, respectively, in 1995 compared with $1.68 per Mcf and
$11.44 per barrel, respectively, in 1994. Net production attributable to the
San Juan Basin Royalty was 911,312 Mcf of natural gas and 30,225 barrels of
natural gas liquids, oil and condensate in 1995 as compared to 968,501 Mcf of
natural gas and 32,360 barrels of natural gas liquids, oil and condensate in
1994.
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 1994 AND 1993
The Trust's Royalty income was $6,927,776 in 1994, an increase of
approximately 18%, as compared to $5,866,029 in 1993, primarily as a result of
higher allowable production in the Hugoton Royalty Properties.
Royalty income from the Hugoton Royalty Properties was $4,930,497 in
1994, an increase of approximately 33%, as compared to $3,700,696 in 1993,
primarily as a result of higher production.
The average price received for natural gas and natural gas liquids from
the Hugoton Royalty Properties was $1.68 per Mcf and $9.86 per barrel,
respectively, in 1994 as compared with $1.74 per Mcf and $14.21 per barrel,
respectively, in 1993. Net production attributable to the Hugoton Royalty
increased to 1,994,048 Mcf of natural gas and 154,545 barrels of natural gas
liquids in 1994 as compared with 1,643,381 Mcf of natural gas and 56,165
barrels of natural gas liquids in 1993 due primarily to increased allowables
and the startup of the Satanta Plant in the third quarter of 1993.
Royalty income from the San Juan Basin Royalty Properties located in the
state of New Mexico was $1,997,279 in 1994 as compared to $2,165,333 in 1993.
No Royalty income was received from MarkWest or Amoco with respect to the San
Juan Basin Royalty Properties located in the state of Colorado in 1994 or
1993, as costs associated with the development drilling program for Royalty
Properties in that state had not been fully recovered.
The average price received for natural gas and natural gas liquids, oil
and condensate from the San Juan Basin Royalty Properties was $1.68 per Mcf
and $11.44 per barrel, respectively, in 1994 compared with $1.84 per Mcf and
$12.67 per barrel, respectively, in 1993. Net production attributable to the
San Juan Basin Royalty was 968,501 Mcf of natural gas and 32,360 barrels of
natural gas liquids, oil and condensate in 1994 as compared to 979,707 Mcf of
natural gas and 29,398 barrels of natural gas liquids, oil and condensate in
1993.
26
SUMMARY OF ROYALTY INCOME, PRODUCTION AND AVERAGE PRICES (UNAUDITED)
<TABLE>
<CAPTION>
SAN JUAN BASIN TOTAL
HUGOTON ------------------------------ -------------------------
------------------------- OIL, OIL,
NATURAL CONDENSATE CONDENSATE
GAS AND NATURAL AND NATURAL
NATURAL GAS LIQUIDS(2) NATURAL GAS GAS LIQUIDS(2) NATURAL GAS GAS LIQUIDS
----------- ---------- ----------- --------------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Year ended December 31, 1995:
The Trust's proportionate share of --
Gross proceeds........................ $3,957,402 $1,747,635 $2,590,105 $ 494,985 $6,547,507 $2,242,620
Less the Trust's proportionate share of
Capital costs recovered(1)............ (22,092) -- (104,517) -- (126,609) --
Operating costs....................... (1,152,500) (12,876) (1,363,758) (158,768) (2,516,258) (171,644)
Interest on cost carryforward......... -- -- (34,528) -- (34,528) --
----------- ---------- ----------- --------------- ----------- ------------
Royalty income.......................... $2,782,810 $1,734,759 $1,087,302 $ 336,217 $3,870,112 $2,070,976
=========== ========== =========== =============== =========== ============
Average sales price..................... $ 1.48 $ 10.72 $ 1.19 $ 11.12 $ 1.39 $ 10.78
=========== ========== =========== =============== =========== ============
Net production volumes attributable (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
to the Royalty paid.................... 1,882,578 161,820 911,312 30,225 2,793,890 192,045
=========== ========== =========== =============== =========== ============
Year ended December 31, 1994:
The Trust's proportionate share of --
Gross proceeds........................ $4,472,631 $1,532,589 $3,766,012 $ 543,810 $8,238,643 $ 2,076,399
Less the Trust's proportionate share of
Capital costs recovered(1)............ (23,072) -- (299,728) -- (322,800) --
Operating costs....................... (1,042,164) (9,487) (1,808,935) (173,613) (2,851,099) (183,100)
Interest on cost carryforward......... -- -- (30,267) -- (30,267) --
----------- ---------- ----------- --------------- ----------- ------------
Royalty income.......................... $3,407,395 $1,523,102 $1,627,082 $ 370,197 $5,034,477 $ 1,893,299
=========== ========== =========== =============== =========== ============
Average sales price..................... $ 1.68 $ 9.86 $ 1.68 $ 11.44 $ 1.68 $ 10.24
=========== ========== =========== =============== =========== ============
Net production volumes attributable (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
to the Royalty paid.................... 1,994,048 154,545 968,501 32,360 2,962,549 186,905
=========== ========== =========== =============== =========== ============
Year ended December 31, 1993:
The Trust's proportionate share of --
Gross proceeds........................ $3,948,720 $ 825,916 $3,481,964 $ 532,439 $7,430,684 $ 1,358,355
Less the Trust's proportionate share of
Capital costs recovered(1)............ (44,119) -- (180,099) -- (224,218) --
Operating costs....................... (1,005,050) (24,771) (1,509,002) (142,039) (2,514,052) (166,810)
Interest on cost carryforward......... -- -- (17,930) -- (17,930) --
----------- ---------- ----------- --------------- ----------- ------------
Royalty income.......................... $2,899,551 $ 801,145 $1,774,933 $ 390,400 $4,674,484 $ 1,191,545
=========== ========== =========== =============== =========== ============
Average sales price..................... $ 1.74 $ 14.21 $ 1.84 $ 12.67 $ 1.78 $ 13.56
=========== ========== =========== =============== =========== ============
Net production volumes attributable (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls)
to the Royalty paid.................... 1,643,381 56,165 979,707 29,398 2,623,088 85,563
</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. The cost carryforward resulting from the Fruitland Coal drilling
program was $501,345, $436,854 and $328,536 at December 31, 1995, 1994 and
1993, respectively. The cost carryforwards at December 31, 1995, 1994 and
1993 relate solely to the San Juan Basin Colorado properties. See "San
Juan Basin Fruitland Coal Drilling" discussion on page 6 of this Form 10-K
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 Mesa and Conoco, respectively.
27
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
MESA ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
----------------------------------------------------
1995 1994 1993
---------------- ---------------- ----------------
<S> <C> <C> <C>
Royalty income.............................................. $ 5,941,088 $ 6,927,776 $ 5,866,029
Interest income............................................. 72,258 62,717 44,866
General and administrative expenses......................... (55,864) (23,216) (33,920)
---------------- ---------------- ----------------
Distributable income........................................ $ 5,957,482 $ 6,967,277 $ 5,876,975
================ ================ ================
Distributable income per unit............................... $ 3.1967 $ 3.7386 $ 3.1536
================ ================ ================
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31
----------------------------------
1995 1994
---------------- ----------------
ASSETS
<S> <C> <C>
Cash and short-term investments............................................... $ 1,075,495 $ 1,244,208
Interest receivable........................................................... 13,172 13,859
Net overriding royalty interests in oil and gas properties.................... 42,498,034 42,498,034
Less: accumulated amortization........................................... (22,871,195) (20,515,993)
---------------- ----------------
Total assets.................................................................. $ 20,715,506 $ 23,240,108
================ ================
LIABILITIES AND TRUST CORPUS
Distributions payable......................................................... $ 1,088,667 $ 1,258,067
Trust corpus (1,863,590 units of beneficial
interest authorized and outstanding)........................................ 19,626,839 21,982,041
---------------- ----------------
Total liabilities and trust corpus............................................ $ 20,715,506 $ 23,240,108
================ ================
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
----------------------------------------------------
1995 1994 1993
---------------- ---------------- ----------------
<S> <C> <C> <C>
Trust corpus, beginning of year............................. $ 21,982,041 $ 24,250,937 $ 26,423,121
Distributable income................................... 5,957,482 6,967,277 5,876,975
Distributions to unitholders........................... (5,957,482) (6,967,277) (5,876,975)
Amortization of net overriding royalty interests....... (2,355,202) (2,268,896) (2,172,184)
---------------- ---------------- ----------------
Trust corpus, end of year................................... $ 19,626,839 $ 21,982,041 $ 24,250,937
================ ================ ================
</TABLE>
The accompanying notes are an integral part of these financial statements.
28
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 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").
Texas Commerce Bank 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; and
(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. Royalty income of the Trust was
$5,941,088 and $6,927,776 for the years 1995 and 1994, 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.
(f) MESA Inc., CONOCO Inc. 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.
The initial carrying value of the Royalty represented the net book value
assigned by Mesa 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.
29
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
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 are based on a report prepared by MESA Inc. 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 contained in MESA Inc.'s report 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 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 report
prepared by Conoco Inc. These estimates were prepared in accordance with SEC
regulations and on a basis generally consistent with that used by MESA Inc.
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.
30
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
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.
ESTIMATED QUANTITIES OF PROVED AND PROVED DEVELOPED RESERVES (UNAUDITED)
OIL,
CONDENSATE
AND
NATURAL GAS
LIQUIDS NATURAL GAS
------------ -----------
(BBLS) (MCF)
Proved Reserves:
December 31, 1992....................... 1,508,165 45,401,767
Revisions to previous estimates...... (78,162) (1,459,365)
Production........................... (85,418) (2,623,233)
------------ -----------
December 31, 1993....................... 1,344,585 41,319,169
Revisions to previous estimates...... 454,487 10,719,834
Production........................... (186,905) (2,962,549)
------------ -----------
December 31, 1994....................... 1,612,167 49,076,454
Revisions to previous estimates...... 614,672 (2,766,523)
Production........................... (192,045) (2,793,890)
------------ -----------
December 31, 1995....................... 2,034,794 43,516,041
============ ===========
Proved Developed Reserves:
December 31, 1993....................... 1,316,685 40,996,769
============ ===========
December 31, 1994....................... 1,586,767 48,685,654
============ ===========
December 31, 1995....................... 2,013,794 43,163,041
============ ===========
31
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
- ------------
o 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: 1995, 26,000 Bbls; 1994, 30,800 Bbls;
1993, 32,200 Bbls.
o The Hugoton Royalty represents 83%, 74% and 70% of the estimated proved
oil, condensate and natural gas liquids reserves and 80%, 82% and 78% of
the estimated proved natural gas reserves as of December 31 of 1995, 1994
and 1993, respectively.
STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM PROVED OIL
AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (UNAUDITED)
<TABLE>
<CAPTION>
DECEMBER 31
------------------------
1995 1994
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
The Trust's proportionate share of future gross proceeds.............................. $ 180,123 $ 176,176
Less the Trust's proportionate share of --
Future operating costs.............................................................. (79,551) (74,642)
Future capital costs................................................................ (2,278) (2,615)
----------- -----------
Future royalty income................................................................. 98,294 98,919
Discount at 10% per annum............................................................. (54,922) (52,595)
----------- -----------
Standardized measure of future royalty income from
proved oil and gas reserves......................................................... $ 43,372 $ 46,324
=========== ===========
</TABLE>
- ------------
o The Hugoton Royalty represents approximately 81% and 77% of the
standardized measure of future royalty income for 1995 and 1994,
respectively.
CHANGES IN THE STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME
FROM PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (UNAUDITED)
DECEMBER 31
-------------------------------
1995 1994 1993
--------- --------- ---------
(IN THOUSANDS)
Standardized measure at beginning of year.. $ 46,324 $ 53,094 $ 54,170
--------- --------- ---------
Revisions of previous estimates.......... (1,643) (5,151) (627)
Royalty income........................... (5,941) (6,928) (5,866)
Accretion of discount.................... 4,632 5,309 5,417
--------- --------- ---------
Net changes in standardized measure...... (2,952) (6,770) (1,076)
--------- --------- ---------
Standardized measure at end of year........ $ 43,372 $ 46,324 $ 53,094
========= ========= =========
32
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
(7) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
SUMMARIZED QUARTERLY RESULTS
THREE MONTHS ENDED
------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
------------- ------------- ------------- ------------
<S> <C> <C> <C> <C>
1995:
Royalty income..................................... $ 2,102,914 $ 1,442,140 $1,315,134 $ 1,080,900
Distributable income............................... $ 2,119,343 $ 1,424,631 $1,324,841 $ 1,088,667
Distributable income per unit...................... $ 1.1372 $ .7645 $ .7109 $ .5841
1994:
Royalty income..................................... $ 2,362,870 $ 1,831,285 $1,491,461 $ 1,242,160
Distributable income............................... $ 2,373,082 $ 1,839,403 $1,496,725 $ 1,258,067
Distributable income per unit...................... $ 1.2734 $ .9870 $ .8032 $ .6750
</TABLE>
33
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO TEXAS COMMERCE BANK 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, 1995 and 1994, and
the related statements of distributable income and changes in trust corpus for
each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and its distributable
income and changes in trust corpus for each of the three years in the period
ended December 31, 1995, on the basis of accounting described in Note 3.
ARTHUR ANDERSEN LLP
Houston, Texas
March 26, 1996
34
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There are no directors or executive officers of the Registrant. The
Trustee is a corporate trustee which may be removed by the affirmative vote of
the majority at a meeting of the holders of units of beneficial interest of
the Trust at which a quorum is present.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(A) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS.
The following information has been taken from filings with the Securities
and Exchange Commission on 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. 611,816(2) 32.83%
201 Main Street, Suite 3100
Fort Worth, Texas 76102
Units of Beneficial Interest............. Beck, Mack & Oliver 308,940(3) 16.57%
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. 6 dated January 8,
1996 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 on March 8, 1996. 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 611,816
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 a general partner of Alpine, and as a director of
the Foundation, may also be deemed to be a beneficial owner of the 611,816
units owned by Alpine and the 49,784 units owned by the Foundation.
(3) Information obtained from Schedule 13G dated January 31, 1996 of Beck,
Mack & Oliver ("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.
35
(C) CHANGES IN CONTROL. Registrant knows of no arrangements, including
the pledge of securities of the Registrant, the operation of which may at a
subsequent date result in a change in control of the Registrant.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Not applicable.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A)(1) FINANCIAL STATEMENTS
The following financial statements are set forth under Part II, Item 8 of
this Annual Report on Form 10-K on the pages indicated.
PAGE IN THIS
FORM 10-K
------------
Statements of Distributable Income................................ 28
Statements of Assets, Liabilities and Trust Corpus................ 28
Statements of Changes in Trust Corpus............................. 28
Notes to Financial Statements..................................... 29
Report of Independent Public Accountants.......................... 34
(A)(2) SCHEDULES
Schedules have been omitted because they are not required, not applicable
or the information required has been included elsewhere herein.
(A)(3) EXHIBITS
(Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference.)
<TABLE>
<CAPTION>
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
<C> <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 1995.
36
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
MESA ROYALTY TRUST
By TEXAS COMMERCE BANK NATIONAL
ASSOCIATION, TRUSTEE
By MICHAEL J. ULRICH
Michael J. Ulrich
Senior Vice President
& Trust Officer
March 26, 1996
The Registrant, Mesa Royalty Trust, has no principal executive officer,
principal financial officer, board of directors or persons performing similar
functions. Accordingly, no additional signatures are available and none have
been provided.
37
EXHIBIT INDEX
<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>
____________
*Previously filed with the Securities and Exchange Commission
and incorporated herein by reference.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED
FROM MESA ROYALTY TRUST AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 1,075,495
<SECURITIES> 0
<RECEIVABLES> 13,172
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,088,667
<PP&E> 42,498,034
<DEPRECIATION> 22,871,195
<TOTAL-ASSETS> 20,715,506
<CURRENT-LIABILITIES> 1,088,667
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 19,626,839
<TOTAL-LIABILITY-AND-EQUITY> 20,715,506
<SALES> 5,941,088
<TOTAL-REVENUES> 6,013,346
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 55,864
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 0
<INCOME-TAX> 0
<INCOME-CONTINUING> 5,957,482
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 5,957,482
<EPS-PRIMARY> 3.197
<EPS-DILUTED> 3.197
</TABLE>
