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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, 1996
[_] 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 1-8432
MESA OFFSHORE TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-6004065
(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) 216-6369
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
------------------- ------------------------
UNITS OF BENEFICIAL INTEREST PACIFIC 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 71,980,216 Units of Beneficial Interest in
Mesa Offshore Trust held by non-affiliates of the registrant at the closing
sales price on March 20, 1997, of $.25 was approximately $17,995,000.
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, 1997, 71,980,216 Units of Beneficial Interest in Mesa
Offshore Trust.
Documents Incorporated By Reference: None.
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<PAGE>
TABLE OF CONTENTS
PART I
PAGE
Item 1. Business....................................................... 1
Description of the Trust..................................... 1
Description of the Units..................................... 2
Termination of the Trust..................................... 5
Description of Royalty Properties............................ 6
Contracts.................................................... 14
Regulation and Prices........................................ 16
Item 2. Properties..................................................... 17
Item 3. Legal Proceedings.............................................. 17
Item 4. Submission of Matters to a Vote of Security Holders............ 17
PART II
Item 5. Market for the Registrant's Common Equity and Related
Unitholder Matters........................................... 18
Item 6. Selected Financial Data........................................ 18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.......................... 18
Item 8. Financial Statements and Supplementary Data.................... 22
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure....................... 30
PART III
Item 10. Directors and Executive Officers of the Registrant............. 30
Item 11. Executive Compensation......................................... 30
Item 12. Security Ownership of Certain Beneficial Owners and Management. 30
Item 13. Certain Relationships and Related Transactions................. 30
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K................................................... 30
SIGNATURES................................................................ 32
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 -- Termination of the Trust,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and Note 1 to the financial statements of the Trust regarding the
future net revenues of the Trust, are forward-looking statements. Although MESA
Inc. has advised the Trust that it believes that the expectations reflected in
such forward-looking statements are reasonable, no assurance can be given that
such expectations will prove to have been correct. Important factors that could
cause actual results to differ materially from expectations ("Cautionary
Statements") are disclosed in this Form 10-K, including, without limitation in
conjunction with the forward-looking statements included in this Form 10-K. All
subsequent written and oral forward-looking statements attributable to the Trust
or persons acting on its behalf are expressly qualified in their entirety by the
Cautionary Statements.
<PAGE>
PART I
ITEM 1. BUSINESS.
DESCRIPTION OF THE TRUST
The Mesa Offshore 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) 216-6369.
The principal asset of the Trust consists of a 99.99% interest in the Mesa
Offshore Royalty Partnership (the "Partnership"). The Trust was created on
December 28, 1982, effective December 1, 1982, when Mesa Petroleum Co. conveyed
to the Partnership certain overriding royalty interests (collectively, the
"Royalty") carved out of Mesa Petroleum Co.'s existing working interests in
ten producing and non-producing oil and gas leases offshore Louisiana and Texas
(the "Royalty Properties"). The Partnership was formed for the purpose of
receiving and holding the Royalty, receiving the proceeds from the Royalty,
paying the liabilities and expenses of the Partnership and disbursing remaining
revenues to the Trustee and Mesa Offshore Management Co., the managing general
partner of the Partnership at that time, in accordance with their interests.
MESA Inc., successor to Mesa Limited Partnership, which was successor to Mesa
Petroleum Co., operates the Royalty Properties through Mesa Operating Co., a
subsidiary of MESA, Inc. Pursuant to an amendment to the Partnership Agreement
(defined below), Mesa Operating Co. became the managing general partner of the
Partnership (the "Managing General Partner") on January 5, 1994. As
hereinafter used in this report, the term Mesa generally refers to the operator
of the Royalty Properties, unless otherwise indicated. See "Termination of the
Trust" on page 5 of this Form 10-K for additional information regarding Mesa
and the Trust.
Units of beneficial interest ("units") in the Trust were issued on
December 28, 1982 to Mesa Petroleum Co. shareholders, who received one unit for
each share of Mesa Petroleum Co. common stock held. The units are listed on the
Pacific Exchange under the symbol MOS.
The terms of the Mesa Offshore Trust Indenture (the "Trust Indenture")
provide, among other things, that: (1) the Trust cannot acquire any asset other
than its interest in the Partnership and cannot engage in any business or
investment activity; (2) the Royalty can be sold in part or in total for cash
upon approval of the unitholders or upon termination of the Trust; (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 borrowing;
(4) the Trustee will make quarterly distributions of cash available for
distribution to the unitholders in January, April, July and October of each
year; and (5) the Trust will terminate upon the first to occur of the following
events: (i) the total amount of cash received per year by the Trust for each of
three successive years commencing after December 31, 1987 is less than 10 times
one-third of the total amount payable to the Trustee as compensation for such
three-year period or (ii) a vote by the unitholders in favor of termination.
Amounts paid to the Trustee as compensation were $123,000, $149,000 and
$177,500, for the years 1996, 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 terms of the First Amended and Restated Articles of General Partnership
of the Partnership (the "Partnership Agreement") provide that the Partnership
shall dissolve upon the occurrence of any of the following: (a) December 31,
2030; (b) the election of the Trustee to dissolve the Partnership; (c) the
termination of the Trust; (d) the bankruptcy of the Managing General Partner; or
(e) the dissolution of the Managing General Partner or its election to dissolve
the Partnership; provided that the Managing General Partner shall not elect to
dissolve the Partnership so long as the Trustee remains the only other partner
of the Partnership.
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The discussions of terms of the Trust Indenture and the Partnership
Agreement contained herein are qualified in their entirety by reference to the
Trust Indenture and the Partnership Agreement themselves, which are exhibits to
this Form 10-K and are available upon request from the Trustee.
Under the instrument conveying the Royalty to the Partnership, the Trust is
entitled to its share (99.99%) of 90% of the Net Proceeds, as hereinafter
defined, realized from the sale of the minerals as, if and when produced from
the Royalty Properties. See "Description of Royalty Properties" on page 6 of
this Form 10-K. The instrument of conveyance provides for a monthly computation
of Net Proceeds. "Net Proceeds" means the excess of Gross Proceeds, as
hereinafter defined, received by Mesa during a particular period over operating
and capital costs and an amount to be recovered for future abandonment costs
during such period. "Gross Proceeds" means generally the amount received by
Mesa from the sale of its share of minerals covered by the Royalty, subject to
certain adjustments. Operating costs means, generally, costs incurred by Mesa in
operating the Royalty Properties, including capital costs. If operating and
capital costs exceed the Gross Proceeds for any month, the excess plus interest
thereon at the prime rate of the Bank of America plus one-half percent is
recovered out of future Gross Proceeds prior to the making of further payment to
the Trust. The Trust is not liable for any operating costs or other costs or
liabilities attributable to the Royalty Properties or minerals produced
therefrom. Mesa, as owner of the working interest in the Royalty Properties, is
required to maintain books and records sufficient to determine the amounts
payable under the Royalty. Additionally, in the event of a controversy between
Mesa and any purchaser as to the correct sale price for any production, amounts
received by Mesa and promptly deposited by it with an escrow agent are not
considered as having been received by Mesa and therefore are not subject to
being payable with respect to the Royalty until the controversy is resolved; but
all amounts thereafter paid to Mesa by the escrow agent will be considered
amounts received from the sale of production. Similarly, operating costs include
any amounts Mesa is required to pay whether as a refund, interest or penalty to
any purchaser because the amount initially received by Mesa 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, Mesa is 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 Mesa in accordance
with reasonable and prudent business judgment and good oil and gas field
practices. Mesa 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. Mesa markets the production on terms
deemed by it to be the best reasonably obtainable in the circumstances. See
"Contracts" on page 14 of this Form 10-K. The Trustee has no power or
authority to exercise any control over the operation of the Royalty Properties
or the marketing of production therefrom.
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,
which ranks equally as to distributions and has one vote on any matter submitted
to unitholders. Each unit evidences an undivided interest in the Trust, which in
turn owns a 99.99% interest in the Partnership.
DISTRIBUTIONS
The Trustee determines for each month the amount of cash available for
distribution for such month. Such amount (the "Monthly Distribution Amount")
is equal to the excess, if any, of the cash distributed by the Partnership to
the Trust during such month, plus any other cash receipts of the Trust during
such month (other than interest earned on the Monthly Distribution Amount for
any other month) over the liabilities of the Trust paid during such month, and
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
2
<PAGE>
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 later date as
the Trustee determines is required to comply with legal or stock exchange
requirements. However, to reduce the administrative expenses of the Trust, the
Trust Indenture provides that the Trustee does not distribute cash monthly, but
rather, during January, April, July and October of each year, distributes to
each person who was a unitholder of record on a Monthly Record Date 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.
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 passive nature of the Trust assets, the restrictions on the
power of the Trustee to incur liabilities and the required financial net worth
of any trustee, the imposition of any liability on a unitholder is extremely
unlikely.
FEDERAL INCOME TAX MATTERS
OWNERSHIP OF UNITS
The federal income tax consequences to the unitholders of owning units
depend on whether the Trust is classifiable as a grantor trust, a non-grantor
trust, or a corporation. The Trustee reports on the basis that the Trust is a
grantor trust. Based on its recent audit policy, the Internal Revenue Service
(the "IRS") is expected to concur with such action. No IRS ruling has been
received 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 will assert on audit that the Trust is taxable as a corporation and that a
court might agree with such assertion.
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.
BACKUP WITHHOLDING
Distributions from the Trust are generally subject to backup withholding at
a rate of 31% of such distributions. Backup withholding will not normally apply
to distributions to a unitholder, however, unless such unitholder fails to
properly provide to the Trust his taxpayer identification number ("TIN") or
the IRS notifies the Trust that the TIN provided by such unitholder is
incorrect.
3
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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. Depletion attributable to a positive Section
743(b) basis adjustment of 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
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). However, for tax years beginning after December 31, 1987, such
effectively connected income will be subjected to withholding equal to the
highest applicable percentage (tax rate)-39.6% for individual foreign
unitholders and 35% for corporate foreign unitholders.
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 percent 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
percent of the outstanding units are not subject to United States federal income
tax on the gain on the disposition of their units.
Federal income taxation of a 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.
TAX-EXEMPT ORGANIZATIONS
The Revenue Reconciliation Act of 1993 repealed the rule that automatically
characterized a tax-exempt organization's share of a publicly traded
partnership's gross income as derived from an unrelated trade or business.
Beginning in 1994, investments in publicly traded partnerships are treated the
same as investments in other partnerships for purposes of the rules governing
unrelated business taxable income. The Royalty and interest income should not be
unrelated business taxable income so long as, generally, a unitholder did not
incur debt to acquire a unit or otherwise incur or maintain a debt that would
not have been incurred or maintained if such unit had not been acquired.
Legislative proposals have been made from time to time which, if adopted, would
result in the treatment of Royalty income as unrelated business income.
Tax-exempt unitholders should consult their own tax advisors with respect to the
treatment of royalty income.
4
<PAGE>
TERMINATION OF THE TRUST
As discussed above under "Description of the Trust", the terms of the
Mesa Offshore Trust Indenture provide that the Trust will terminate upon the
first to occur of the following events: (1) the total amount of cash received
per year by the Trust for each of three successive years commencing after
December 31, 1987 is less than 10 times one-third of the total amount payable to
the Trustee as compensation for such three year period or (2) a vote by the
unitholders in favor of termination. Because the Trust will terminate in the
event the total amount of cash received per year by the Trust falls below
certain levels, it would be possible for the Trust to terminate even though some
of the Royalty Properties continued to have remaining productive lives. For
information regarding the estimated remaining life of each of the Royalty
Properties and the estimated future net revenues of the Trust based on
information provided by Mesa, see pages 13 and 14 of this Form 10-K and Note 6
in the Notes to Financial Statements included elsewhere in this Form 10-K. 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 discussion 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.
In addition, in the event of a dissolution of the Partnership (which could
occur under the circumstances described above under "Description of the
Trust") and a subsequent winding up and termination thereof, the assets of the
Partnership (i.e., the Royalty interest) could either (i) be distributed in kind
ratably to the Managing General Partner and the Trustee or (ii) be sold and the
proceeds thereof distributed ratably to the Managing General Partner and the
Trustee. In the event of a sale of the Royalty and a distribution of the cash
proceeds to the Trustee, the Trustee would make a final distribution to
unitholders of such cash proceeds plus any other cash held by the Trust after
the payment of or provision for all liabilities of the Trust, and the Trust
would be terminated.
Mesa has advised the Trust that it has completed its South Marsh Island
drilling program at a cost of approximately $21.9 million ($13.8 million net to
the Trust). During 1996, Mesa recovered approximately $9.8 million in drilling
costs net to the Trust. Mesa recovered all remaining costs related to the South
Marsh Island drilling program as of the February 1997 reporting month. In
addition, the Trust recovered approximately $.6 million in administrative
expenses paid from the Trust's reserve fund during the period in which Royalty
income was not paid to the Trust, replenishing the Trust's expense reserve fund
balance to $2 million.
As discussed above, the Mesa Offshore Trust Indenture provides that the
Trust will terminate in the event the total amount of cash received per year by
the Trust falls below certain levels for three successive years. The recovery of
costs associated with the South Marsh Island drilling program and the Matagorda
Island 624 drilling program caused the cash received by the Trust in 1996 to
fall below the termination threshold prescribed in the Indenture. However, based
on the overall success of the South Marsh Island drilling program, payments of
Royalty income to the Trust have resumed during 1997 and the Trust expects that
the cash it receives in 1997 will likely be above the termination threshold
prescribed in the Trust Indenture.
Furthermore, the December 31, 1996, reserve report prepared for the
Partnership indicates that 85% of future net revenues will be received by the
Trust during the next two years. As such, it is possible, depending on market
conditions and the success of future drilling activities, if any, that as early
as 1999 the Trust may commence a period of three successive years in which
annual net royalty income would be below the termination threshold prescribed in
the Indenture, resulting in termination of the Trust pursuant to the terms
discussed above.
5
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DESCRIPTION OF ROYALTY PROPERTIES
PRODUCING ACREAGE AND WELLS AS OF DECEMBER 31, 1996
<TABLE>
<CAPTION>
PRODUCING WELLS(1)
------------------------------------------
PRODUCING ACRES GROSS NET
-------------------- -------------------- --------------------
PROPERTY GROSS NET(2) OIL GAS OIL GAS
- ------------------------------------- --------- --------- --- --- --- ---
<S> <C> <C> <C> <C> <C> <C>
Offshore Louisiana--
South Marsh
Island 155...................... 5,000 2,625 -- 4 -- 2.1
South Marsh
Island 156...................... 5,000 2,625 -- 1 -- .5
West Delta 61...................... 5,000 3,750 -- 1 -- .8
West Delta 62...................... 5,000 3,750 -- 3 -- .9
Offshore Texas--
Brazos A-7......................... 5,760 2,160 -- 1 -- .4
Brazos A-39........................ 5,760 2,160 -- 2 -- .8
Matagorda
Island 624...................... 5,617 1,369 -- 3 -- .7
--------- --------- --- --- --- ---
Total..................... 37,137 18,439 0 15 0 6.2
========= ========= === === === ===
</TABLE>
- ------------
(1) Dual completions are counted as one well. For information regarding wells
producing at December 31, 1996, see "Net Proceeds, Production and Average
Prices" on page 21 of this Form 10-K.
(2) Net Producing Acres are calculated by multiplying gross producing acres by
the net Royalty interest (as defined by the Trust Indenture) attributable to
the Trust for each property.
RESERVES
A study of the proved oil and gas reserves attributable to the Partnership
as of December 31, 1996, has been made by MESA Inc. The following letter (the
"Reserve Report") summarizes such reserve study. The Reserve Report reflects
estimated reserve quantities and future net revenue based upon estimates of the
future timing of actual production without regard to when received in cash by
the Trust, which differs from the manner in which the Trust recognizes and
accounts for its royalty income. 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
contained in Item 8 of this Form 10-K.
6
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MESA INC.
LETTER REPORT
DATED
MARCH 26, 1997
ON
RESERVES AND REVENUE
AS OF
DECEMBER 31, 1996
FROM
CERTAIN PROPERTIES
OWNED BY THE
MESA OFFSHORE ROYALTY PARTNERSHIP
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MARCH 26, 1997
MESA Offshore 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, 1996,
of the extent and value of the proved crude oil, condensate, natural gas
liquids, and natural gas reserves of certain properties subject to a net profits
interest owned by the Mesa Offshore Royalty Partnership, hereinafter referred to
as the "Partnership", a partnership owned 99.99 percent by the Mesa Offshore
Trust. The interest appraised is referred to herein as the "Partnership
Interest" and consists of a 90 percent net profits interest in 10 Mesa Operating
Co. (hereinafter referred to as "MESA") leases located in the Gulf of Mexico
offshore from Louisiana and Texas. The 10 offshore leases subject to the net
profits interest are hereinafter referred to as the "Subject Properties". Three
of these leases have been abandoned; reserves of the remaining 7 leases are
reported herein.
The reserve estimates are based on a detailed study of the Subject Properties.
The method or combination of methods used in the study of each reservoir was
tempered by experience in the area, consideration of the stage of development of
the reservoir, and the quality and completeness of basic data.
Estimates of oil, condensate, natural gas liquids and gas 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.
In the preparation of this report, MESA has used internal information with
respect to property interests owned by the Partnership, production from such
properties, current costs of operation and development, current prices for
production, agreements relating to current and future operations and sale of
production, and various other information.
The development status shown herein represents the status applicable on December
31, 1996. Data available from wells drilled on the appraised properties through
December 31, 1996 were used in estimating gross ultimate recovery. Gross
production estimated to December 31, 1996, was deducted from gross ultimate
recovery to arrive at the estimates of gross reserves. In most fields, this
required that the production rates be estimated for up to three months since
production data for certain properties were available only through September
1996.
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Page 2
MARCH 26, 1997
The reserve volumes and revenue values shown in this report for Partnership
Interest were estimated from projections of reserves and revenue attributable to
the combined interests consisting of the Partnership Interest and the retained
MESA interest in the Subject Properties (Combined Interest). Net reserves
attributable to the Partnership Interest were estimated by allocating to the
Partnership a portion of the estimated combined net reserves of the Subject
Properties based on future revenue. Because the net reserve volumes attributable
to the Partnership Interest 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 net reserves. Therefore, the estimated net reserves
attributable to the Partnership Interest will vary if different future price and
cost assumptions are used.
Petroleum reserves included in this report are classified as proved and are
judged to be economically producible in future years from known reservoirs under
existing economic and operating conditions and assuming continuation of current
regulatory practices using conventional production methods and equipment. In the
analysis, reserves were estimated only to the limit of economic rates of
production under existing economic and operating conditions using prices and
costs as of the date the estimate is made, including consideration of changes in
existing prices provided only by contractual arrangements but not including
escalations based upon future conditions. The petroleum reserves are classified
as follows:
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 analysis and
electrical-log interpretation when the producing characteristics of the
formation are known from nearby fields. Volumetrically, the structure,
areal extent, volume, and characteristics of the reservoir are well
defined by a reasonable interpretation of adequate subsurface well
control and by known continuity of hydrocarbon-saturated material above
known fluid contacts, if any, or above the lowest known structural
occurrence of hydrocarbons.
DEVELOPED -- Reserves that are recoverable from existing wells with
current operating methods and expenses.
Developed reserves include both producing and nonproducing reserves.
Estimates of producing reserves assume recovery by existing wells
producing from present completion intervals with normal operating
methods and expenses. Developed nonproducing reserves are in reservoirs
behind the casing or at minor depths below the producing zone and are
considered proved by production from other wells in the field, by
successful drill-stem tests, or by core analysis from the particular
zones. Nonproducing reserves require only moderate expense to be
brought into production.
9
<PAGE>
Page 3
MARCH 26, 1997
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.
Estimates of the net proved reserves attributable to the Partnership Interest,
as of December 31, 1996, are as follows:
TOTAL PROVED RESERVES
Natural Gas (Mcf)......................... 4,060,606
Oil and Condensate (bbl).................. 192,574
Natural Gas Liquids (bbl)................. 83,166
PROVED DEVELOPED RESERVES.....................
Natural Gas (Mcf)......................... 4,060,606
Oil and Condensate (bbl).................. 192,574
Natural Gas Liquids (bbl)................. 83,166
Revenue values attributable to the net proved reserves of the Partnership
Interest are expressed in terms of estimated future net revenue and present
worth of future net revenue. Future net revenue attributable to the Partnership
Interest was estimated monthly from a projection of the combined MESA and
Partnership future net revenue. Combined future net revenue values were
calculated by deducting operating expenses and capital costs from the future
gross revenue of the Combined Interest. The monthly values for the aggregate of
the Combined Interest in the Subject Properties were reduced by an overhead
charge, by a monthly amount necessary for MESA to accrue the abandonment costs
over the life of the properties, by the deficit balance as described below from
the previous month, and by the interest on that deficit balance when such
deficits occur. If the adjusted revenue resulting from this calculation was
negative, it was carried forward to the next month as a deficit balance. If the
adjusted revenue was greater than zero, it was multiplied by a factor of 90
percent to arrive at the future net revenue of the Partnership Interest. The
above calculations were made monthly in the aggregate for the Subject
Properties. Interest was charged monthly on the net profits deficit balance
(cost not recovered currently) at the rate of 9.0 percent per year. The deficit
balance as of December 31, 1996 was zero.
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 tempered by MESA's experience in the area. The
rates used for future production are rates that MESA has determined are within
the capacity of the well or reservoir to produce.
Gas volumes shown herein are expressed at standard conditions of 60 degrees
Fahrenheit and at 15.025 pounds per square inch absolute. Condensate reserves
estimated herein are those to be obtained from normal separator recovery.
10
<PAGE>
Page 4
MARCH 26, 1997
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:
OIL AND CONDENSATE PRICES
Oil and condensate prices were held constant for the life of the properties.
NATURAL GAS PRICES
Gas prices were held constant for the life of the properties.
NATURAL GAS LIQUIDS PRICES
Natural gas liquids 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 Partnership could reasonably expect to be received over the life of the
properties.
OPERATING AND CAPITAL COSTS
Current estimates of operating costs were used for the life of the properties
with no increases in the future based on inflation. Future capital expenditures
were estimated using 1996 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 Partnership Interest, as of December 31, 1996 is as follows:
COMBINED INTEREST:
Future Gross Revenue ($).............................. 34,100,213
Production and Ad Valorem Taxes ($)................... 0
Operating Costs ($)................................... (5,662,400)
Capital Costs ($)(1) ................................. (10,796,918)
Future Net Revenue ($)................................ 17,640,895
Deficit Balance and Interest on Deficit ($)........... (6,286)
Accrued Revenue for Abandonment Costs ($) 9,708,389
Overhead ($).......................................... (470,780)
Revenue Subject to Net Profits Interest ($)........... 26,872,218
PARTNERSHIP INTEREST:
Future Net Revenue ($)(2)............................. 21,175,667
Present Worth at 10 Percent ($)....................... 18,585,364
(1) Includes abandonment costs.
(2) Future income tax expenses were not taken into account in the preparation
of these estimates.
11
<PAGE>
Page 5
MARCH 26, 1997
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 oil, condensate, 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, future income tax expenses have not been taken
into account in estimating the future net revenue and present worth values set
forth herein.
To the extent the above enumerated rules, regulations, and statements require
determinations of an accounting or legal nature or information beyond the scope
of this report, MESA is 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
12
<PAGE>
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production and timing of
development expenditures, including many factors beyond the control of the
producer. The preceding reserve data in the Reserve Report 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. Accordingly, reserve
estimates are often different from the quantities of hydrocarbons that are
ultimately recovered.
Also, while estimates of reserves attributable to the Royalty Properties
are shown in order to comply with requirements of the Securities and Exchange
Commission (the "SEC"), there is no precise method of allocating estimates of
physical quantities of reserves between Mesa and the Partnership, since the
Royalty is not a working interest and the Partnership does not own and is not
entitled to receive any specific volume of reserves from the Royalty. Reserve
quantities in the previously mentioned reserve study have been allocated based
on the method referenced in the Reserve Report. The quantities of reserves
attributable to the Partnership 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 Report 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 Report 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 Report use market prices as of December 31, 1996
pursuant to gas contracts in effect on January 1, 1997. These prices (having a
weighted average of $3.725 per Mcf as of December 31, 1996) 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 sold from the Royalty Properties during
1996 was $2.25 per Mcf, representing a combination of contract prices and spot
market prices.
The following is a summary of the estimated remaining life for each of the
Royalty Properties provided to the Trustee by Mesa as of December 31, 1996.
There are numerous uncertainties present in estimating the remaining productive
lives for the Royalty Properties. The following summary represents an estimate
only and should not be construed as being exact. The estimated remaining
productive life of each property varies depending on the recoverable reserves
and annual production assumed by Mesa. In addition, future economic and
operating conditions may cause significant changes in such estimates.
ESTIMATED
REMAINING LIFE
AS OF
PROPERTY DECEMBER 31, 1996(1)(2)
-------- -----------------------
South Marsh Island 155/156...................... 2-3 years
West Delta 61/62................................ 12-13 years
Brazos A-7...................................... 1-2 years
Brazos A-39..................................... 2-3 years
Matagorda Island 624............................ 3-4 years
(SEE NOTES ON FOLLOWING PAGE)
13
<PAGE>
- ------------
(1) The Trust will terminate in the event the total amount of cash received per
year by the Trust falls below certain levels. Accordingly, it would be
possible for the Trust to terminate even though some of the Royalty
Properties continued to have remaining productive lives. See "Termination
of the Trust" on page 5 of this Form 10-K.
(2) Estimates of remaining lives may vary significantly from year to year.
The future net revenues contained in the Reserve Report have not been
reduced for future general and administrative costs and expenses of the Trust,
which are expected to approximate $500,000 annually. The general and
administrative 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.
Mesa has advised the Trust that there have been no events subsequent to
December 31, 1996 that have caused a significant change in the estimated proved
reserves referred to in the Reserve Report.
PROCEEDS, PRODUCTION AND AVERAGE PRICES
Reference is made to "Net Proceeds, Production and Average Prices" under
Item 7 of this Form 10-K.
ASSETS
Reference is made to Item 6 of this Form 10-K for information relating to
the assets of the Trust.
CONTRACTS
GENERAL. Mesa has advised the Trust that during 1996 its offshore gas
production was marketed under short term contracts at spot market prices to
multiple purchasers, including Penn Union Energy, Energy Source Inc. and Conoco.
Mesa has further advised the Trust that it expects to continue to market its
production under short term contracts for the foreseeable future. Spot market
prices for natural gas in 1996 were generally higher than spot market prices in
1995. Information regarding recent prices received for production from the
Royalty Properties is provided below.
BRAZOS A-7 AND A-39. In March 1997, most of the gas from this
property was being sold to Penn Union Energy at an average price of $1.75
per MMBtu.
SOUTH MARSH ISLAND 155 AND 156. In March 1997, most of the gas from
this property was being sold to Penn Union Energy at an average price of
$1.71 per MMBtu.
WEST DELTA 61 AND 62. In March 1997, most of the gas from this
property was being sold to Penn Union Energy at an average price of $1.73
per MMBtu.
MATAGORDA ISLAND 624. In March 1997, most of the gas from this
property was being sold to Penn Union Energy at an average price of $1.63
per MMBtu.
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 in comparison 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
general 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 per Mcf in
1995, according to the Natural Gas Monthly published by the Energy Information
Administration of the Department of Energy. However, the estimated annual
average wellhead price for natural gas in 1996 increased to approximately $2.12
(based on the first 11 months of 1996). In
14
<PAGE>
addition, spot domestic natural gas prices have generally increased in early
1997 and are higher than gas prices in early 1996.
The seasonal nature of demand for natural gas and its effects on sales
prices and production volumes may cause the amounts of cash distributions by the
Trust to vary substantially on a seasonal basis. Generally, production volumes
and prices are higher during the first and fourth quarters of each calendar year
due primarily to peak demand in these periods. Because of the time lag between
the date on which Mesa receives payment for production from the Royalty
Properties and the date on which distributions are made to unitholders, the
seasonality that generally affects production volumes and prices is generally
reflected in distributions to unitholders in later periods.
COMPETITION
The production and sale of gas from the areas in which the Royalty
Properties are located is highly competitive and Mesa has a number of
competitors in these areas. Mesa has advised the Trust that it believes that its
competitive position in these areas is affected by price, contract terms and
quality of service. Mesa's business is affected not only by such competition,
but also by general economic developments, governmental regulations and other
factors.
MARKETING OF LIQUIDS
Mesa generally reserves in its gas purchase contracts the right to extract
condensate and other liquid and liquifiable hydrocarbons from all gas produced.
Mesa is currently selling the condensate and other liquids to various purchasers
under contracts with terms of one year or less.
A Mesa subsidiary, Mesa Transmission Co., owns a 100% interest in a
pipeline which transports crude oil from South Marsh Island 155 and 156 to an
underwater connection with Marathon Pipe Line Company's ("Marathon") pipeline
on South Marsh Island 139. In 1996, Mesa charged $3.57 per barrel for
transportation of crude oil from these properties, which included Marathon's
currently posted tariff of $1.52 per barrel and Mesa Transmission Co.'s tariff
of $2.05 per barrel. Tariffs charged by Mesa Transmission Co. are subject to
approval by the Federal Energy Regulatory Commission (the "FERC").
Future pipeline construction and operation arrangements may be necessary
for the marketing of crude oil and other liquid hydrocarbon production, if any,
from the other Royalty Properties. Mesa Transmission Co. could be involved in
such arrangements.
15
<PAGE>
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.
OPERATING HAZARDS AND UNINSURED RISKS
Mesa's oil and gas activities are subject to all of the risks normally
incident to exploration for and production of oil and gas, including blowouts,
cratering and fires, each of which could result in damage to life and property.
Offshore operations are subject to a variety of operating risks, such as
hurricanes and other adverse weather conditions and lack of access to existing
pipelines or other means of transporting production. Furthermore, offshore oil
and gas operations are subject to extensive governmental regulations, including
certain regulations that may, in certain circumstances, impose absolute
liability for pollution damages, and to interruption or termination by
governmental authorities based on environmental or other considerations. In
accordance with customary industry practices, Mesa carries insurance against
some, but not all, of these risks. Losses and liabilities resulting from such
events would reduce revenues and increase costs to Mesa to the extent not
covered by insurance.
FERC REGULATION
The FERC has recently required interstate pipeline companies to
"unbundle" their services. To the extent a pipeline company or its sales
affiliate makes gas sales as a merchant in the future, it does so pursuant to
private contracts in direct competition with all other sellers, such as Mesa. In
recent years, the FERC also has pursued a number of other policy initiatives
which could significantly affect the marketing of natural gas. Several of these
initiatives are intended to enhance competition in natural gas markets, although
some, such as "spin-downs," may have the adverse effect of increasing the cost
of doing business on some in the industry. As to all of these recent FERC
initiatives, Mesa has advised the Trust that the on-going, or, in some
instances, preliminary evolving nature of these regulatory initiatives makes it
impossible at this time to predict their ultimate impact on Mesa's business.
STATE REGULATION
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.
ENVIRONMENTAL
Mesa's 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. Mesa maintains insurance for costs of cleanup
operations, but it is 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, legislation has been proposed in
Congress that would
16
<PAGE>
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.
From time to time, federal and state environmental agencies propose
regulations which could have a direct and material impact on Mesa's operations.
For example, the Oil Pollution Act of 1990 ("OPA") and regulations thereunder
impose a variety of regulations on "responsible parties," including the owners
and operators of offshore facilities, related to the discharge of petroleum
products in reportable quantities in waters of the United States. In 1993, the
Minerals Management Service ("MMS") proposed regulations that would require
owners and operators of offshore facilities to establish $150 million in
financial responsibility. However, in October 1996, the President signed a bill
that amends OPA to reduce the level of financial responsibility to $35 million.
Therefore, the MMS proposal will not become effective. Under current federal
regulations concerning offshore operations, the MMS is authorized to require
lessees to post supplemental bonds to cover their potential leasehold
abandonment costs. By letter dated November 9, 1995, Mesa was advised by the MMS
that it does not qualify for a waiver from supplemental bond requirements and
that Mesa may be required to post supplemental bonds covering its potential
obligations with respect to offshore operations. Mesa Inc. executed a guarranty
of abandonment liability (area wide) with the MMS on April 26, 1996, in
satisfaction of these obligations.
Mesa has advised the Trust that it is 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 Mesa's financial position or results of
operations.
PLATFORM ABANDONMENT AND REMOVAL
Mesa is responsible for the abandonment and removal of its offshore
drilling and production structures within one year after the cessation of
production, although extensions can be requested.
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 1996.
17
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER
MATTERS.
The units of beneficial interest of Mesa Offshore Trust are traded on the
Pacific Exchange -- ticker symbol MOS. The high and low sales prices and
distributions per unit for each quarter in the two years ended December 31, 1996
were as follows:
<TABLE>
<CAPTION>
1996 1995
------------------------------------- -------------------------------------
DISTRIBUTION DISTRIBUTION
HIGH LOW PAID HIGH LOW PAID
--------- --------- ------------- --------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
First Quarter............................. $ .250 $ .125 $-- $ .250 $ .188 $.017
Second Quarter............................ $ .688 $ .156 $-- $ .250 $ .156 $.010
Third Quarter............................. $ .438 $ .156 $-- $ .250 $ .188 $.012
Fourth Quarter............................ $ .281 $ .188 $-- $ .250 $ .125 $.002
</TABLE>
At March 20, 1997, the 71,980,216 units outstanding were held by 15,786
unitholders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
-------------- ------------- ------------- -------------- -------------
<S> <C> <C> <C> <C> <C>
Royalty income..................... $ 36,014 $ 3,139,620 $ 9,104,615 $ 13,867,712 $ 4,044,916
Distributable income............... $ -- $ 2,803,862 $ 8,783,711 $ 13,458,769 $ 1,448,357
Distributable income per unit...... $ -- $ .0390 $ .1220 $ .1870 $ .0201
Excess cost carryforward........... $ (3,149,598) $ (138,514) $ -- $ -- $ --
Total assets at year end........... $ 2,602,742 $ 3,103,451 $ 4,724,878 $ 8,725,736 $ 9,295,438
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
FINANCIAL REVIEW
YEARS 1996 AND 1995
Royalty income was $36,014 in 1996 as compared to $3,139,620 in 1995. There
was no distributable income in 1996 as compared to $2,803,862 ($.0390 per unit)
in 1995. The decrease in Royalty income and lack of distributable income was
primarily due to the recovery of capital costs associated with drilling and
completion of the wells on South Marsh Island.
Production volumes for natural gas increased to 4,499,242 Mcf in 1996
compared with 3,662,986 Mcf in 1995. The increase was due primarily to new
production on South Marsh Island, offset in part by a natural production decline
on other properties. The average sale price received for natural gas in 1996 was
$2.25 per Mcf compared with $1.54 per Mcf in 1995.
Crude oil, condensate and natural gas liquids production volumes increased
to 162,405 barrels in 1996 compared with 113,322 barrels in 1995. The increase
was due primarily to new production on South Marsh Island, offset in part by a
natural production decline on other properties. The average sale price in 1996
for crude oil, condensate and natural gas liquids was $15.83 per barrel compared
with $14.65 per barrel in 1995.
YEARS 1995 AND 1994
Royalty income decreased to $3,139,620 in 1995 as compared to $9,104,615 in
1994. Distributable income decreased to $2,803,862 ($.0390 per unit) in 1995 as
compared to $8,783,711 ($.1220 per unit) in 1994. The decrease in Royalty income
was primarily due to lower natural gas prices, decreased production and the
recovery of capital costs associated with drilling of the A-8 well on Matagorda
Island block 624 in the fourth quarter of 1995.
18
<PAGE>
Production volumes for natural gas decreased to 3,662,986 Mcf in 1995
compared with 5,580,788 Mcf in 1994. The decrease was due primarily to natural
production decline. The average sale price received for natural gas in 1995 was
$1.54 per Mcf compared with $2.01 per Mcf in 1994.
Crude oil, condensate and natural gas liquids production volumes decreased
to 113,322 barrels in 1995 compared with 181,775 barrels in 1994. The decrease
was due primarily to natural production decline. The average sale price in 1995
for crude oil, condensate and natural gas liquids was $14.65 per barrel compared
with $13.21 per barrel in 1994.
GENERAL
From inception of the Trust on December 1, 1982 through December 31, 1987,
Mesa, as working interest owner, spent $110 million ($99 million net to the
Trust) to explore and develop the Royalty Properties. No significant
expenditures regarding exploration and development were made during 1988, 1989
or 1990. Beginning in late 1991 and continuing in 1992, Mesa spent $9.6 million
($8.7 million net to the Trust) on exploration and development. No significant
exploration and development expenditures were made in 1993 or 1994. As discussed
below, Mesa spent $3.4 million ($1.2 million net to the Trust) on exploration
and development during 1995, $21.9 million ($13.8 million net to the Trust) in
1996 and anticipates spending up to approximately $.4 million ($.15 million net
to the Trust) primarily on planned workovers and recompletions in 1997.
ADDITIONAL DRILLING PROJECTS
During 1996, Mesa drilled five wells from the existing "A" platform on
the South Marsh Island 155/156 block at a total cost of $21.9 million ($13.8
million net to the Trust). See "Liquidity and Capital Resources" and
"Operational Review" below and "Termination of the Trust" elsewhere in this
Form 10-K for additional information regarding the South Marsh Island drilling
program.
LIQUIDITY AND CAPITAL RESOURCES
In accordance with the provisions of the Trust conveyance, generally all
revenues received by the Trust, net of Trust administrative expenses and any
cash reserves established for the payment of contingent or future obligations of
the Trust, are distributed currently to the unitholders.
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 Partnership, of which the
Trust has a 99.99% interest.
As discussed above, Mesa drilled five wells on the South Marsh Island
properties in 1996. During 1996, Mesa recovered approximately $9.8 million in
drilling expenses net to the Trust related to the drilling on the South Marsh
Island blocks 155/156. Mesa recovered all remaining costs related to the South
Marsh Island drilling program as of the February 1997 reporting month. In
addition, the Trust recovered approximately $.6 million in administrative
expenses paid from the Trust's reserve fund during the period in which Royalty
income was not paid to the Trust, replenishing the Trust's expense reserve fund
balance to $2 million.
The Indenture governing the Trust provides that the Trust will terminate if
the total amount of cash per year received by the Trust falls below certain
levels for each of three successive years. The recovery of costs associated with
the Matagorda Island 624 and South Marsh Island drilling programs caused the
cash received by the Trust in 1996 to fall below the termination threshold
prescribed in the Indenture. However, based on the overall success of the South
Marsh Island drilling program, payments of Royalty income to the Trust have
resumed during 1997 and the Trust expects that the cash it receives in 1997 will
likely be above the termination threshold prescribed in the Indenture. See
"Termination of the Trust" elsewhere in this Form 10-K.
Furthermore, the December 31, 1996, reserve report prepared for the
Partnership indicates that 85% of future net revenues will be received by the
Trust during the next two years. As such, it is possible, depending on market
conditions and the success of future drilling activities, if any, that as
19
<PAGE>
early as 1999 the Trust may commence a period of three successive years in which
annual net royalty income would be below the termination threshold prescribed in
the Indenture, resulting in termination of the Trust pursuant to the terms
discussed above.
OPERATIONAL REVIEW
As discussed in Item 1 of this Form 10-K, substantially all of the gas
produced from the Trust properties during 1996 was sold at prices approximating
spot market prices.
The Brazos A-7 and A-39 blocks experienced a decrease in natural gas
production in 1996 as compared to 1995 primarily due to natural production
decline. Mesa has farmed out a portion of Brazos A-7 to another operator and
will have an option to participate at a 10% working interest in the completion
of an exploratory well to be drilled in the second quarter of 1997. Estimated
costs of such participation are $2 million ($.2 million net to the Trust). On
block A-39, well A-3 ceased production in February 1996. Mesa commenced
operations in April to perform a through tubing recompletion in the A-3 well.
However, operational problems were encountered, and the work was suspended.
Operations resumed and were completed in September 1996 at an estimated cost of
$710,000 ($319,500 net to the Trust).
The South Marsh Island 155 and 156 blocks experienced an increase in
production in 1996 as compared to 1995, primarily due to new production from the
A-20, A-21, A-6 sidetrack, A-22 and A-14 sidetrack wells which were drilled in
the first three quarters of 1996. The initial gross producing rates of the five
wells was approximately 40 MMcf of gas and 1,000 barrels of condensate per day
which has subsequently declined to approximately 15 MMcf of gas and 450 barrels
of condensate per day as of March 1997. The decrease in production is primarily
due to natural production decline. Mesa has advised the Trust that it may
perform a recompletion of the A-6 sidetrack well in the second quarter of 1997.
The drilling program resulted in an increase in the estimated proved reserves on
this property. See "Description of the Royalty Properties -- Reserves" in Item
1 of this Form 10-K for information regarding such reserves.
The West Delta 61 and 62 blocks experienced a decrease in production in
1996 as compared to 1995 primarily due to natural production decline. The Trust
is receiving royalty income from this property pursuant to a farmout agreement
with another operator. The interest in the farmout wells which is attributable
to the Trust consists of a 7.5% net profits interest.
Matagorda Island 624 production increased in 1996 as compared to 1995,
primarily due to production from the A-8 development well drilled in the fourth
quarter of 1995. This well is currently shut in due to a leak. Mesa has advised
the Trust that it may perform a workover of this well in the second quarter of
1997.
20
<PAGE>
NET PROCEEDS, PRODUCTION AND AVERAGE PRICES (UNAUDITED)
<TABLE>
<CAPTION>
SOUTH
MARSH HIGH WEST MATAGORDA
BRAZOS ISLAND 155 ISLAND DELTA ISLAND VERMILION
YEAR ENDED DECEMBER 31, 1996: A-7 AND A-39 AND 156 567 61 AND 62 624 381 TOTAL
------------- ---------- --------- --------- ---------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
90% of--
Gross proceeds................... $1,011,764 $7,714,044 $ -- $3,070,880 $ 906,788 $ -- $12,703,476
Less 90% of--
Operating costs.................. (600,885) (807,674) -- (727,325) 377,206) -- (2,513,090)
Capital costs recovered.......... -- (9,329,717) -- (5,335) 344,793) -- (9,679,845)
Accrual for future abandonment
costs and interest
on cost carryforward........... (86,181) (143,018) -- (231,185) (14,139) -- (474,523)
------------- ---------- --------- --------- ---------- --------- -----------
Net Proceeds
(Excess Costs)................... $ 324,698 $(2,566,365) $ -- $2,107,035 $ 170,650 $ -- $ 36,018
============= ========== ========= ========= ========== ========= ===========
Trust share of net proceeds
(99.99%)........................... $ 36,014
===========
90% of Production Volumes and Average
Sales Prices:
Crude oil, condensate and natural
gas liquids
(Bbls)......................... 477 148,046 -- 5,719 8,163 -- 162,405
============= ========== ========= ========= ========== ========= ==========
Average sales price per Bbl...... $ N/A $ 15.74 $ -- $ 17.20 $ 20.41 $ -- $ 15.83
============= ========== ========= ========= ========== ========= ==========
Natural gas (Mcf)................ 521,846 2,397,012 -- 1,220,306 360,078 -- 4,499,242
============= ========== ========= ========= ========== ========= ==========
Average sales price per Mcf...... $ 1.99 $ 2.25 $ -- $ 2.44 $ 2.06 $ -- $ 2.25
============= ========== ========= ========= ========== ========= ==========
Producing wells (gross).............. 3 5 -- 4 3 -- 15
YEAR ENDED DECEMBER 31, 1995:
90% of--
Gross proceeds................... $1,691,468 $ 2,707,851 $ -- $2,471,303 $ 441,242 $ -- $7,311,864
Less 90% of--
Operating costs.................. (672,629) (1,036,990) -- (753,871) (384,234) (862) (2,848,586)
Capital costs recovered.......... (209,034) (166,104) -- (62,267) (567,266) -- (1,004,671)
Accrual for future abandonment
costs and interest
on cost carryforward........... (127,301) (39,300) -- (128,166) (23,906) -- (318,673)
------------- ---------- --------- --------- ---------- --------- ----------
Net Proceeds
(Excess Costs)................... $ 682,504 $ 1,465,457 $ -- $1,526,999 $ (534,164) $ (862) $3,139,934
============= ========== ========= ========= ========== ========= ==========
Trust share of net proceeds
(99.99%)........................... $3,139,620
==========
90% of Production Volumes and Average
Sales Prices:
Crude oil, condensate and natural
gas liquids
(Bbls)......................... 2,886 95,368 -- 10,478 4,590 -- 113,322
============= ========== ========= ========= ========== ========= ==========
Average sales price per Bbl...... $ 16.09 $ 14.55 $ -- $ 14.82 $ 15.42 $ -- $ 14.65
============= ========== ========= ========= ========== ========= ==========
Natural gas (Mcf)................ 1,043,249 916,441 -- 1,451,446 251,850 -- 3,662,986
============= ========== ========= ========= ========== ========= ==========
Average sales price per Mcf...... $ 1.58 $ 1.44 $ -- $ 1.60 $ 1.47 $ -- $ 1.54
============= ========== ========= ========= ========== ========= ==========
Producing wells (gross).............. 3 2 -- 2 3 -- 10
YEAR ENDED DECEMBER 31, 1994:
90% of--
Gross proceeds................... $2,959,607 $ 4,601,565 $ -- $5,152,672 $ 901,303 $ 37,426 $13,652,573
Less 90% of--
Operating costs.................. (695,863) (1,066,432) (21,468) (821,338) (328,137) -- (2,933,238)
Capital costs recovered.......... -- (139,781) -- (408,174) (357,466) -- (905,421)
Accrual for future abandonment
costs.......................... (220,874) (241,308) -- (281,331) (131,735) 166,860 (708,388)
------------- ---------- --------- --------- ---------- --------- ----------
Net Proceeds
(Excess Costs)................... $2,042,870 $ 3,154,044 $ (21,468) $3,641,829 $ 83,965 $ 204,286 $9,105,526
============= ========== ========= ========= ========== ========= ==========
Trust share of net proceeds
(99.99%)........................... $9,104,615
==========
90% of Production Volumes and Average
Sales Prices:
Crude oil, condensate and natural
gas liquids (Bbls)............. 2,723 148,672 -- 26,188 4,192 -- 181,775
============= ========== ========= ========= ========== ========= ==========
Average sales price per Bbl...... $ 13.56 $ 13.28 $ -- $ 12.57 $ 14.44 $ -- $ 13.21
============= ========== ========= ========= ========== ========= ==========
Natural gas (Mcf)................ 1,462,904 1,378,661 -- 2,340,734 398,489 -- 5,580,788
============= ========== ========= ========= ========== ========= ==========
Average sales price per Mcf...... $ 2.00 $ 1.91 $ -- $ 2.06 $ 2.11 $ -- $ 2.01
============= ========== ========= ========= ========== ========= ==========
Producing wells (gross).............. 3 2 -- 2 3 -- 10
</TABLE>
- ------------
o The amounts shown are for the Mesa Offshore Royalty Partnership.
o Producing wells indicates the gross number of wells capable of production as
of the end of the period.
o Gross proceeds is based on actual production for a twelve-month period ending
on October 31 of each year, respectively.
o Capital costs recovered represent capital costs incurred during the current or
prior period to the extent that such costs have been recovered by Mesa from
gross proceeds.
o The cost carryforward resulting from the drilling on South Marsh Island was
$3.1 million at December 31, 1996. See the Operational Review Section for
additional information.
21
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
YEARS ENDED DECEMBER 31
-----------------------------------------
1996 1995 1994
----------- ------------- -------------
Royalty income...................... $ 36,014 $ 3,139,620 $ 9,104,615
Interest income..................... 63,253 91,788 104,372
General and administrative expense.. (99,267) (427,546) (425,276)
----------- ------------- -------------
Distributable income................ $ -- $ 2,803,862 $ 8,783,711
=========== ============= =============
Distributable income per unit....... $ -- $ .0390 $ .1220
=========== ============= =============
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31
------------------------------------
1996 1995
----------------- -----------------
ASSETS
<S> <C> <C>
Cash and short-term investments............................................ $ 1,535,247 $ 2,015,016
Interest receivable........................................................ 5,090 21,275
Net overriding royalty interest in oil and gas properties.................. 380,905,000 380,905,000
Less: accumulated amortization........................................ (379,842,595) (379,837,840)
----------------- -----------------
$ 2,602,742 $ 3,103,451
================= =================
LIABILITIES AND TRUST CORPUS
Reserve for trust expenses................................................. $ 1,540,337 $ 2,000,000
Distribution payable....................................................... -- 36,291
Trust corpus (71,980,216 units of beneficial
interest authorized and outstanding)..................................... 1,062,405 1,067,160
----------------- -----------------
$ 2,602,742 $ 3,103,451
================= =================
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
------------------------------------------------
1996 1995 1994
-------------- -------------- ----------------
<S> <C> <C> <C>
Trust corpus, beginning of year................................ $ 1,067,160 $ 1,527,797 $ 3,208,542
Distributable income...................................... -- 2,803,862 8,783,711
Distributions to unitholders.............................. -- (2,803,862) (8,783,711)
Amortization of net overriding royalty interest........... (4,755) (460,637) (1,680,745)
-------------- -------------- ----------------
Trust corpus, end of year...................................... $ 1,062,405 $ 1,067,160 $ 1,527,797
============== ============== ================
</TABLE>
The accompanying notes are an integral part of these financial statements.
22
<PAGE>
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(1) TRUST ORGANIZATION AND PROVISIONS
THE TRUST
The Mesa Offshore Trust (the "Trust") was created effective December 1,
1982. On that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership,
which was predecessor to MESA Inc., transferred to the Trust a 99.99% interest
in the Mesa Offshore Royalty Partnership (the "Partnership"). The Trust is an
independent trust administered by Texas Commerce Bank National Association, as
trustee (the "Trustee").
The terms of the Mesa Offshore 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 interest in the Partnership 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 of 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) the total amount of cash received per year by the Trust for
each of three successive years commencing after December 31, 1987 is
less than 10 times one-third of the total amount payable to the Trustee
as compensation for such three-year period or (ii) a vote by the
unitholders in favor of termination. Amounts earned by the Trustee as
compensation were $123,000, $149,000 and $177,500 for the years 1996,
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 PARTNERSHIP
The Partnership was created to receive and hold a net overriding royalty
interest (the "Royalty") in ten producing and nonproducing oil and gas
properties located in federal waters offshore Louisiana and Texas (the "Royalty
Properties"). MESA Inc. created the Royalty out of its working interest in the
Royalty Properties and transferred it to the Partnership.
The Partnership is owned 99.99% by the Trust and 0.01% by Mesa Operating
Co. ("Mesa"), an operating subsidiary of MESA Inc. Mesa serves as the managing
general partner of the Partnership. Mesa receives no compensation for serving as
managing general partner other than the income it receives attributable to its
interest in the Partnership.
STATUS OF THE TRUST
Mesa has advised the Trust that in October 1995 it completed the drilling
on Matagorda Island block 624 and that it drilled five wells from the existing
"A" platform on the South Marsh Island 155 block during 1996. Mesa Inc.
recovered all remaining costs related to the South March Island drilling program
as of the February 1997 reporting month. In addition, the Trust recovered
approximately $.6 million in administrative expenses paid from the Trust's
reserve fund during the period in which Royalty income was not paid to the
Trust, replenishing the Trust's expense reserve fund balance to $2 million.
23
<PAGE>
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
The Trust Indenture provides that the Trust will terminate if the total
amount of cash per year received by the Trust falls below certain levels for
each of three successive years. The recovery of costs associated with the
Matagorda Island 624 and South Marsh Island drilling programs caused the cash
received by the Trust in 1996 to fall below the termination threshold prescribed
in the Indenture. However, based on the overall success of the South Marsh
Island drilling program, payments of Royalty income to the Trust have resumed as
of the April 30, 1997 payable date and the Trust expects that the cash it
receives in 1997 will likely be above the termination threshold prescribed in
the Trust Indenture.
Furthermore, the December 31, 1996, reserve report prepared for the
Partnership (see Note 6) indicates that 85% of future net revenues will be
received by the Trust during the next two years. As such, it is possible,
depending on market conditions and the success of future drilling activities, if
any, that as early as 1999 the Trust may commence a period of three successive
years in which annual net royalty income would be below the termination
threshold prescribed in the Indenture, resulting in termination of the Trust
pursuant to the terms discussed above.
(2) NET OVERRIDING ROYALTY INTEREST
The instruments conveying the Royalty to the Partnership provide that Mesa
will calculate and pay to the Partnership each month an amount equal to 90% of
aggregate net proceeds for the preceding month. Generally, net proceeds means
the excess of the amounts received by Mesa from sales of its share of oil and
gas from the Royalty Properties (gross proceeds) over the operating and capital
costs incurred. Costs exceeding gross proceeds for any month are recovered by
Mesa, with interest thereon at the prime rate of the Bank of America plus
one-half percent, out of future gross proceeds prior to making further royalty
payments to the Partnership.
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, which is calculated on the basis of current royalty
income in relation to estimated future royalty income, is charged directly to
trust corpus since such amounts do 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 Trust's interest in the
amount computed and paid by the working interest owner to the
Partnership for such month rather than either the value of a portion of
the oil and gas produced by the working interest owner for such month or
the amount subsequently determined to be 90% 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 are recorded in the month
they accrue.
This basis for reporting distributable income is considered to be the most
meaningful because distributions to the unitholders for a month are based on net
cash receipts for such month. However, it will differ from the basis used for
financial statements prepared in accordance with generally accepted accounting
principles because, under such accounting principles, royalty income for a month
would be based on net proceeds from production for such month without regard to
when calculated or received and interest income for a month would be calculated
only through the end of such month.
24
<PAGE>
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
(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 dates of 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 Royalty as
of December 31, 1996 and 1995, 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 the reserve report for the Partnership interest
were estimated by allocating to the Partnership a portion of the estimated
combined net reserve volumes of the Royalty Properties based on future net
revenue. Production volumes are allocated based on royalty income. Because the
net reserve volumes attributable to the Partnership 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
Partnership 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.
Future prices for natural gas were based on prices in effect as of each
year end and existing contract terms. Prices being received as of each year end
were used for sales of oil, condensate and natural gas liquids. Operating costs,
production and ad valorem taxes and future development and abandonment costs
were based on current costs as of each year end, with no escalation.
There are numerous uncertainties inherent in estimating the quantities and
value of proved reserves and in projecting the future rates of production and
timing of expenditures. The reserve data below represent estimates only and
should not be construed as being exact. Moreover, the discounted values should
not be construed as representative of the current market value of the Royalty. A
market value determination would include many additional factors including: (i)
anticipated future oil and gas prices; (ii) the effect of federal income taxes,
if any, on the future royalties; (iii) an allowance for return on investment;
(iv) the effect of governmental legislation; (v) the value of additional
reserves, not considered proved at present, which may be recovered as a result
of further exploration and development activities; and (vi) other business
risks.
Estimates of reserve volumes attributable to the Royalty are shown in order
to comply with requirements of the SEC. There is no precise method of allocating
estimates of physical quantities of
25
<PAGE>
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
reserve volumes between Mesa and the Partnership, since the Royalty is not a
working interest and the Partnership does not own and is not entitled to receive
any specific volume of reserves from the Royalty. The quantities of reserves
attributable to the Partnership have been and will be affected by changes in
various economic factors utilized in estimating net revenues from the Royalty
Properties, as well as any exploration activities which may be conducted by
Mesa. 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 future net revenues contained in the previously mentioned reserve
report have not been reduced for future general and administrative costs and
expenses of the Trust, which are expected to approximate $500,000 annually. The
general and administrative 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 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 Mesa maintains its
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 NATURAL
GAS LIQUIDS GAS
------------ -------------
(Bbls) (Mcf)
Proved Reserves:
December 31, 1993............... 205,350 6,071,323
------------ -------------
Revisions of previous
estimates.............. 64,908 1,047,161
Extensions, discoveries
and other additions.... 4,044 241,830
Production................ (121,244) (3,722,386)
------------ -------------
December 31, 1994............... 153,058 3,637,928
------------ -------------
Revisions of previous
estimates.............. 2,937 (611,229)
Extensions, discoveries
and other additions.... 45,832 827,402
Production................ (48,659) (1,572,839)
------------ -------------
December 31, 1995............... 153,168 2,281,262
------------ -------------
Revisions of previous
estimates.............. (10,158) (319,134)
Extensions, discoveries
and other additions.... 133,190 2,111,233
Production................ (460) (12,755)
------------ -------------
December 31, 1996............... 275,740 4,060,606
============ =============
Proved Developed Reserves:
December 31, 1994............... 144,702 3,080,069
============ =============
December 31, 1995............... 116,623 1,621,034
============ =============
December 31, 1996............... 275,740 4,060,606
============ =============
- ------------
(See Notes on following page.)
26
<PAGE>
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM
PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (UNAUDITED)
<TABLE>
<CAPTION>
DECEMBER 31
--------------------
1996 1995
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Ninety percent of future gross proceeds.................................................... $ 30,690 $ 21,205
Less ninety percent of --
Future operating costs................................................................ (5,520) (8,740)
Future capital costs, net of amounts previously accrued............................... (3,994) (5,191)
--------- ---------
Future royalty income...................................................................... 21,176 7,274
Discount at 10% per annum.................................................................. (2,591) (1,635)
--------- ---------
Standardized measure of future royalty
income from proved oil and gas reserves.................................................. $ 18,585 $ 5,639
========= =========
</TABLE>
CHANGES IN THE STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM
PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM (UNAUDITED)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
---------------------------------
1996 1995 1994
--------- --------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure at beginning of year.................................... $ 5,639 $ 6,877 $ 14,779
--------- --------- -----------
Revisions of previous estimates and net changes in prices............... 2,580 (271) (570)
Extensions, discoveries and other additions............................. 9,838 1,485 295
Royalty income.......................................................... (36) (3,140) (9,105)
Accretion of discount................................................... 564 688 1,478
--------- --------- -----------
Net changes in standardized measure..................................... 12,946 (1,238) (7,902)
--------- --------- -----------
Standardized measure at end of year.......................................... $ 18,585 $ 5,639 $ 6,877
========= ========= ===========
</TABLE>
- ------------
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: 1996, 192,574 Bbls; 1995, 123,220 Bbls; 1994,
133,466 Bbls.
o The estimated quantities of proved reserves, standardized measure of future
royalty income and changes in the standardized measure represent 100% of
amounts for the Partnership in which the Trust has a 99.99% interest.
o The "Future capital costs, net of amounts previously accrued" at December
31, 1996 includes, in thousands, $9,187 of future abandonment costs net of
$8,738 previously accrued by Mesa.
o Natural gas prices have declined significantly since December 31, 1996.
Accordingly, the standardized measure of future royalty income from proved
oil and gas reserves would be reduced if it was calculated in the first
quarter of 1997.
27
<PAGE>
MESA OFFSHORE 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>
1996:
Royalty income.................................. $ 36,014 $ -- $ -- $ --
Distributable income............................ $ -- $ -- $ -- $ --
Distributable income per unit................... $ -- $ -- $ -- $ --
1995:
Royalty income.................................. $ 1,303,852 $ 836,005 $ 879,243 $ 120,520
Distributable income............................ $ 1,246,506 $ 688,638 $ 832,427 $ 36,291
Distributable income per unit................... $ .0173 $ .0096 $ .0116 $ .0005
</TABLE>
28
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO TEXAS COMMERCE BANK NATIONAL ASSOCIATION (TRUSTEE)
AND THE UNITHOLDERS OF THE MESA OFFSHORE TRUST:
We have audited the accompanying statements of assets, liabilities and
trust corpus of the Mesa Offshore Trust as of December 31, 1996 and 1995, and
the related statements of distributable income and changes in trust corpus for
each of the three years in the period ended December 31, 1996. 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
Offshore Trust as of December 31, 1996 and 1995, and its distributable income
and changes in trust corpus for each of the three years in the period ended
December 31, 1996, on the basis of accounting described in Note 3.
/s/ ARTHUR ANDERSEN LLP
-----------------------
Arthur Andersen LLP
Houston, Texas
March 26, 1997
29
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There are no directors or executive officers of the Registrant. The Trustee
is a corporate trustee which may be removed by the affirmative vote of a
majority of the units then outstanding 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. Not applicable.
(B) SECURITY OWNERSHIP OF MANAGEMENT. Not applicable.
(C) CHANGES IN CONTROL. Registrant knows of no arrangement, including the
pledge of securities of the Registrant, the operation of which may at a
subsequent date result in a change in control of the Registrant.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Not Applicable.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A)(1) FINANCIAL STATEMENTS
The following financial statements are set forth under Part II, Item 8 of
this Annual Report on Form 10-K on the pages indicated.
<TABLE>
<CAPTION>
PAGE IN THIS
FORM 10-K
------------
<S> <C>
Statements of Distributable Income................................................................... 22
Statements of Assets, Liabilities and Trust Corpus................................................... 22
Statements of Changes in Trust Corpus................................................................ 22
Notes to Financial Statements........................................................................ 23
Report of Independent Public Accountants............................................................. 29
</TABLE>
(A)(2) SCHEDULES
Schedules have been omitted because they are not required, not applicable
or the information required has been included elsewhere herein.
(A)(3) EXHIBITS
<TABLE>
<CAPTION>
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
<S> <C>
4(a) * Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas
Commerce Bank National Association, as Trustee, dated December 15,
1982............................................................... 2-79673 10(gg)
4(b) * Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa
Offshore Royalty Partnership, dated December 15, 1982.............. 2-79673 10(hh)
4(c) * Partnership Agreement between Mesa Offshore Management Co. and
Texas Commerce Bank National Association, as Trustee, dated
December 15, 1982.................................................. 2-79673 10(ii)
30
<PAGE>
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
4(d) * Amendment to Partnership Agreement between Mesa Offshore Management
Co., Texas Commerce Bank National Association, as TRUSTEE, and MESA
operating Limited Partnership, dated December 27, 1985 (Exhibit
4(d) to Form 10-K for year ended December 31, 1992 of Mesa Offshore
Trust)............................................................. 1-8432 4(d)
4(e) * Amemdment to Partnership Agreement between Texas Commerce Bank Na-
tional Association, as Trustee, and Mesa Operating dated as of
January 5, 1994 (Exhibit 4(e) to Form 10-K for year ended December
31, 1993 of Mesa Offshore Trust)................................... 1-8432 4(e)
27 Financial Data Schedule
</TABLE>
- ------------
* Previously filed with the Securities and Exchange Commission and incorporated
herein by reference.
(B) REPORTS ON FORM 8-K
None.
31
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
MESA OFFSHORE TRUST
By TEXAS COMMERCE BANK NATIONAL
ASSOCIATION, TRUSTEE
By /s/ PETE FOSTER
----------------------------
Pete Foster
Senior Vice President
& Trust Officer
March 27, 1997
The Registrant, Mesa Offshore 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.
32
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
<S> <C>
4(a) * Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas
Commerce Bank National Association, as Trustee, dated December 15,
1982............................................................... 2-79673 10(gg)
4(b) * Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa
Offshore Royalty Partnership, dated December 15, 1982.............. 2-79673 10(hh)
4(c) * Partnership Agreement between Mesa Offshore Management Co. and
Texas Commerce Bank National Association, as Trustee, dated
December 15, 1982.................................................. 2-79673 10(ii)
4(d) * Amendment to Partnership Agreement between Mesa Offshore Management
Co., Texas Commerce Bank National Association, as TRUSTEE, and MESA
operating Limited Partnership, dated December 27, 1985 (Exhibit
4(d) to Form 10-K for year ended December 31, 1992 of Mesa Offshore
Trust)............................................................. 1-8432 4(d)
4(e) * Amemdment to Partnership Agreement between Texas Commerce Bank Na-
tional Association, as Trustee, and Mesa Operating dated as of
January 5, 1994 (Exhibit 4(e) to Form 10-K for year ended December
31, 1993 of Mesa Offshore Trust)................................... 1-8432 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 OFFSHORE TRUST AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 1,535,247
<SECURITIES> 0
<RECEIVABLES> 5,090
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,540,337
<PP&E> 380,905,000
<DEPRECIATION> 379,842,595
<TOTAL-ASSETS> 2,602,742
<CURRENT-LIABILITIES> 1,540,337
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 1,062,405
<TOTAL-LIABILITY-AND-EQUITY> 2,602,742
<SALES> 36,014
<TOTAL-REVENUES> 99,267
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 99,267
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 0
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 0
<EPS-PRIMARY> .000
<EPS-DILUTED> .000
</TABLE>
