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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM
__________________ TO _________________________
COMMISSION FILE NUMBER 1-8432
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) 216-5100
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 STOCK EXCHANGE
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of 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, 1996, of $.219 was $15,745,672.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
As of March 20, 1996, 71,980,216 Units of Beneficial Interest in Mesa
Offshore Trust.
Documents Incorporated By Reference: None.
<PAGE>
TABLE OF CONTENTS
PART I
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PAGE
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Item 1. Business........................................................................................ 1
Description of the Trust........................................................................ 1
Description of the Units........................................................................ 2
Termination of the Trust........................................................................ 5
Description of Royalty Properties............................................................... 7
Contracts....................................................................................... 15
Regulation and Prices........................................................................... 17
Item 2. Properties...................................................................................... 19
Item 3. Legal Proceedings............................................................................... 19
Item 4. Submission of Matters to a Vote of Security Holders............................................. 19
PART II
Item 5. Market for the Registrant's Common Equity and Related Unitholder Matters........................ 20
Item 6. Selected Financial Data......................................................................... 20
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.................................................................................... 20
Item 8. Financial Statements and Supplementary Data..................................................... 24
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.................................................................................... 33
PART III
Item 10. Directors and Executive Officers of the Registrant.............................................. 33
Item 11. Executive Compensation.......................................................................... 33
Item 12. Security Ownership of Certain Beneficial Owners and Management.................................. 33
Item 13. Certain Relationships and Related Transactions.................................................. 33
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................................ 33
SIGNATURES................................................................................................. 35
</TABLE>
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-K includes "forward-looking statements" within the meaning
of Section 27A of the Securities Act of 1933, as amended, and Section 21E of
the Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-K, 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
financial position of MESA, Inc., the drilling program currently being pursued
by Mesa and the potential effects of such matters on 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.
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) 216-5100.
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 pages 5 and 6 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 traded
on the Pacific Stock 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
$149,000, $177,500, and $207,000, for the years 1995, 1994 and 1993,
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.
1
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 7 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 15 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
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
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. Although it is not clear, under
this provision, it is expected that 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
prior to March 14, 1995. Upon a disposition of a unit acquired after 1986 or
disposition of an oil and gas property to which the depletion is attributable,
either occurring after March 13, 1995, depletion attributable to a positive
Section 743(b) adjustment will be subject to recapture as ordinary income. 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
4
Royalty income as unrelated business income. Tax-exempt unitholders should
consult their own tax advisors with respect to the treatment of royalty
income.
TERMINATION 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 page 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.
Amounts paid to the Trustee as compensation were $149,000, $177,500 and
$207,500 for the years 1995, 1994 and 1993, respectively. Royalty income of
$3,139,620 for 1995 was above the termination threshold prescribed in the
Indenture.
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.
In addition, MESA Inc. has advised the Trust that its independent public
accountants included a going concern paragraph in their report on its 1995
financial statements. The going concern paragraph refers to MESA Inc.'s
current financial forecasts, which indicate that MESA Inc. will be unable to
fund required debt principal and interest obligations due in June 1996 with
cash flows from operating activities, available cash, and investment balances.
In an effort to address its liquidity issues, in July 1995 MESA Inc.'s Board
of Directors approved and implemented a proposal solicitation process which
expanded its exploration of strategic alternatives from the selling of the
Hugoton field to include consideration of the sale of MESA Inc., a
stock-for-stock merger, joint ventures, asset sales, equity infusions, and
refinancing transactions. On February 28, 1996, MESA Inc. signed a letter of
intent with Rainwater, Inc. (Rainwater), an independent investment company
owned by Ft. Worth, Texas, investor Richard Rainwater, to raise $265 million
of equity in connection with a refinancing of MESA Inc.'s debt. The proposed
transaction is subject to certain conditions, including negotiation and
execution of definitive agreements, arrangement of the new debt financing, due
diligence by Rainwater and MESA Inc. stockholder approval. There can be no
assurance that this transaction will be completed, what the final terms or
timing thereof will be. Further, there can be no assurance regarding the
availability or terms of any refinancing debt.
If the Rainwater transaction is not completed, MESA Inc. has advised the
Trust it will pursue other alternatives to address its liquidity issues and
financial condition, including other potential transactions arising from the
proposal solicitation process, the possibility of seeking to restructure its
balance sheet by negotiating with its current debt holders or seeking
protection from its creditors under the Federal Bankruptcy Code.
5
MESA Inc.'s projected debt service problems, as well as any refinancing,
restructuring or other strategic alternative, could have significant effects
on the Trust, although the precise nature of such effects cannot be predicted
or quantified at this time. No assurance can be given by the Trust regarding
MESA Inc.'s financial condition. An event of bankruptcy of MESA Inc. that
includes the Managing General Partner would cause a dissolution of the
Partnership which could cause a termination of the Trust as described above.
An event of bankruptcy of MESA Inc. could also result in a delay in receipt of
royalty payments by the Trust, increased administrative expenses of the Trust
and other effects which cannot be predicted or quantified at this time.
As discussed under "Management's Discussion and Analysis of Financial
Condition and Results of Operations" elsewhere in this Form 10-K, Mesa has
advised the Trust that in October 1995 it completed the drilling of the A-8
well on Matagorda Island block 624 at a total cost of approximately $3,202,000
($940,000 net to the Trust). In addition, Mesa has advised the Trust that it
is pursuing its planned drilling program on the South Marsh Island property
which includes up to five wells from the existing "A" platform on the South
Marsh Island 155 block during 1996. Mesa anticipates that the total cost of
these five wells, if each is drilled, will be approximately $22 million ($14
million net to the Trust). During the fourth quarter of 1995, Mesa recovered
approximately $573,000 in drilling expenses related to the drilling of the A-8
well on Matagorda Island block 624. Mesa has advised the Trust that no Royalty
income will be paid to the Trust until Mesa recovers all costs related to the
Matagorda Island and South Marsh Island drilling along with any additional
completion costs required if the drilling is successful. In addition, if
payments of Royalty income to the Trust are resumed, distributions to
unitholders may be further delayed to allow the Trust to recover
administrative expenses paid during the period that Royalty income was not
paid to the Trust. The recovery of costs associated with the Matagorda Island
and South Marsh Island drilling programs is expected to cause the cash
received by the Trust in 1996 to fall below the termination threshold
prescribed in the Indenture; therefore 1996 could be the first of three
successive years of below threshold income, resulting in the termination of
the Trust as early as the end of 1998. If the drilling is successful, the
effect on Royalty income and Trust reserves will depend on the quality and
quantity of reserves found.
6
DESCRIPTION OF ROYALTY PROPERTIES
PRODUCING ACREAGE AND WELLS AS OF DECEMBER 31, 1995
<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 -- 1 -- .5
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 -- 1 -- .8
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 10 0 4.5
========= ========= === === === ===
</TABLE>
- ------------
(1) Dual completions are counted as one well. For information regarding wells
producing at December 31, 1995, see "Net Proceeds, Production and Average
Prices" on page 23 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, 1995, 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 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.
7
MESA INC.
LETTER REPORT
DATED
FEBRUARY 28, 1996
ON
RESERVES AND REVENUE
AS OF
DECEMBER 31, 1995
FROM
CERTAIN PROPERTIES
OWNED BY THE
MESA OFFSHORE ROYALTY PARTNERSHIP
8
February 28, 1996
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, 1995,
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, 1995. Data available from wells drilled on the appraised properties through
December 31, 1995 were used in estimating gross ultimate recovery. Gross
production estimated to December 31, 1995, was deducted from gross ultimate
recovery to arrive at the estimates of gross reserves. 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
1995.
9
Page 2
February 28, 1996
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
analyses, reserves were estimated only to the limit of economic rates of
production under existing economic and operating conditions using prices and
costs as of the date the estimate is made, including consideration of changes in
existing prices provided only by contractual arrangements but not including
escalations based upon future conditions. The petroleum reserves are classified
as follows:
PROVED -- Reserves that have been proved to a high degree of certainty
by analysis of the producing history of a reservoir and/or by
volumetric analysis of adequate geological and engineering data.
Commercial productivity has been established by actual production,
successful testing, or in certain cases by favorable core analyses and
electrical-log interpretation when the producing characteristics of the
formation are known from nearby fields. Volumetrically, the structure,
areal extent, volume, and characteristics of the reservoir are well
defined by a reasonable interpretation of adequate subsurface well
control and by known continuity of 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 analyses from the particular
zones. Nonproducing reserves require only moderate expense to be
brought into production.
10
Page 3
February 28, 1996
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, 1995, are as follows:
TOTAL PROVED RESERVES
Natural Gas (Mcf)......................... 2,281,262
Oil and Condensate (bbl).................. 123,220
Natural Gas Liquids (bbl)................. 29,948
PROVED DEVELOPED RESERVES.....................
Natural Gas (Mcf)......................... 1,621,034
Oil and Condensate (bbl).................. 110,538
Natural Gas Liquids (bbl)................. 6,085
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, 1995 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.
11
Page 4
February 28, 1996
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 1995 values and were not adjusted for inflation.
A summary of estimated revenue and costs attributable to the Combined Interest
in proved reserves and the future net revenue and present worth attributable to
the Partnership Interest, as of December 31, 1995 is as follows:
COMBINED INTEREST:
Future Gross Revenue ($).............................. 23,560,731
Production and Ad Valorem Taxes ($)................... 0
Operating Costs ($)................................... (8,899,590)
Capital Costs ($)(1) ................................. (14,906,235)
Future Net Revenue ($)................................ (245,094)
Deficit Balance and Interest on Deficit ($)........... (122,434)
Accrued Revenue for Abandonment Costs ($) 9,261,135
Overhead ($).......................................... (811,860)
Revenue Subject to Net Profits Interest ($)........... 8,081,747
PARTNERSHIP INTEREST:
Future Net Revenue ($)(2)............................. 7,273,572
Present Worth at 10 Percent ($)....................... 5,638,585
(1) Includes abandonment costs.
(2) Future income tax expenses were not taken into account in the preparation
of these estimates.
12
Page 5
February 28, 1996
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
Vice President - Exploration and Production
13
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,
1995 pursuant to gas contracts in effect on January 1, 1996. These prices
(having a weighted average of $2.21 per Mcf as of December 31, 1995) were held
constant over the estimated life of the Royalty Properties. Such prices were
influenced by seasonal demand for natural gas and may not be the most
appropriate or representative prices to use for estimating future revenues or
related reserve data. The average price of natural gas sold from the Royalty
Properties during 1995 was $1.54 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,
1995. 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, 1995(1)(2)
-------- -----------------------
South Marsh Island 155/156...................... 3-4 years
West Delta 61/62................................ 13-14 years
Brazos A-7...................................... 1-2 years
Brazos A-39..................................... 3-4 years
Matagorda Island 624............................ 1-2 years
14
- ------------
(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, 1995 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. During the period from November 1994 through April 1995,
pursuant to a contract entered into effective November 1, 1994, the majority
of Mesa's offshore gas production (including production from the Royalty
Properties) was sold to Natural Gas Clearinghouse ("NGC") at prices based on
third party published index prices for the pipelines into which gas produced
from contract properties was delivered, plus two cents. Generally, index
prices approximate "spot" market prices. The NGC contract expired on April 30,
1995. Mesa has advised the Trust that for the remainder of 1995 its offshore
gas production was marketed under short term contracts at spot market prices
to multiple purchasers, including NGC, Penn Union Energy and Neste. 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 1995 were generally lower than spot market prices in 1994.
Information regarding recent prices received for production from the Royalty
Properties is provided below.
BRAZOS A-7 AND A-39. In March 1996, the gas from this property was
being sold to Penn Union Energy at an average price of $1.87 per MMBtu.
SOUTH MARSH ISLAND 155 AND 156. In March 1996, the gas from this
property was being sold to Penn Union Energy at an average price of $2.33
per MMBtu.
WEST DELTA 61 AND 62. In March 1996, the gas from this property was
being sold to Penn Union Energy at an average price of $2.81 per MMBtu.
MATAGORDA ISLAND 624. In March 1996, the gas from this property was
being sold to Penn Union Energy at an average price of $1.73 per MMBtu.
MARKET FOR NATURAL GAS
Natural gas sales are no longer subject to price regulation and are made
at negotiated contract prices, which may be more or less than the market value
of the natural gas. Regulated natural gas sales had been priced at contract
prices limited to the maximum lawful prices determined under the Natural Gas
Policy Act of 1978 ("NGPA"). The Natural Gas Wellhead Decontrol Act of 1989
(the "Decontrol Act") amended the NGPA to remove as of January 1, 1993 all
remaining price controls on natural gas. See "Regulation and Prices -- Natural
Gas Regulations" on page 17 of this Form 10-K.
15
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 (estimated) per Mcf in 1995, according to the Natural
Gas Monthly published by the Energy Information Administration of the
Department of Energy. Spot domestic natural gas prices have generally
increased in late 1995 and early 1996 and are higher than gas prices in early
1995.
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. Many of these competitors have financial resources
greatly in excess of those of Mesa. 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 1995, Mesa charged $3.56 per barrel for
transportation of crude oil from these properties, which included Marathon's
currently posted tariff of $1.51 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.
16
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.
NATURAL GAS REGULATIONS
Historically, interstate pipeline companies generally acted as wholesale
merchants by purchasing natural gas from producers and reselling the gas to
local distribution companies and large end-users. Commencing in late 1985, the
FERC issued a series of orders that have had a major impact on natural gas
pipeline operations, services and rates and thus have significantly altered
the marketing and price of natural gas. The FERC's key rulemaking action,
Order No. 636 ("Order 636"), issued in April 1992, requires each pipeline
company, among other things, to "unbundle" its traditional wholesale services
and create and make available on an open and nondiscriminatory basis numerous
constituent services (such as gathering services, storage services, firm and
interruptible transportation services, and stand-by sales and gas balancing
services) and to adopt a new ratemaking methodology to determine appropriate
rates for those services. To the extent the pipeline company or its sales
affiliate makes gas sales as a merchant in the future, it does so in direct
competition with all other sellers pursuant to private contracts; however,
pipeline companies and their affiliates were not required to remain
"merchants" of gas, and several of the interstate pipeline companies have
become "transporters only." In subsequent orders, the FERC largely affirmed
the major features of Order 636 and denied a stay of the implementation of the
new rules pending judicial review. In addition and following the conclusion of
individual restructuring proceedings for each interstate pipeline pursuant to
Order 636, the FERC has approved, with modifications, all of the restructuring
plans and has generally accepted compliance filings implementing Order 636 on
every interstate pipeline as of the end of 1994. Order 636, as well as the
FERC orders approving the individual pipeline compliance filings implementing
Order 636, are the subject of numerous appeals to the United States Courts of
Appeal. Mesa has informed the Trust that it cannot predict whether the orders
will be affirmed on appeal or what the effects will be on the production and
pricing of natural gas relating to the Royalty Properties.
Mesa has advised the Trust that it owns, directly or indirectly, certain
natural gas facilities that it believes meet the traditional tests the FERC
has used to establish a company's status as a gatherer not subject to FERC
jurisdiction under the Natural Gas Act of 1938 (the "NGA"). Moreover, recent
orders of the FERC have been more liberal in their reliance upon or use of the
traditional tests, such that in many instances, what was once classified as
"transmission" may now be "gathering." Mesa transports gas from the Royalty
Properties through these facilities. Other gas from the Royalty Properties is
also transported through gathering facilities owned by others, including
interstate pipelines. On May 27, 1994, the FERC issued orders in the context
of the "spin-off" or "spin-down"
17
of interstate pipeline-owned gathering facilities. A "spin-off" is a
FERC-approved sale of such facilities to a non-affiliate. A "spin-down" is the
transfer by the interstate pipeline of its gathering facilities to an
affiliate. A number of spin-offs and spin-downs have been approved by the FERC
and implemented. The FERC held that it retains jurisdiction over gathering
provided by interstate pipelines but that it generally does not have
jurisdiction over pipeline gathering affiliates, except in the event of
affiliate abuse, such as actions by the affiliate undermining open and
nondiscriminatory access to the interstate pipeline. These orders require
nondiscriminatory access for all sources of supply, prohibit the tying of
pipeline transportation service to any service provided by the pipeline's
gathering affiliate, and require the new gathering company to submit a
"default" contract if a satisfactory contract cannot be mutually agreed upon
with existing customers. Several petitions for rehearing were filed. Pursuant
to a November 30, 1994 meeting, the FERC issued a series of rehearing orders
largely affirming the May 27, 1994 orders. The FERC clarified that "default"
contracts are intended to serve only as a transition mechanism to prevent
arbitrary termination of gathering service to existing customers. Also, the
FERC now requires that an interstate pipeline must not only seek authority
under Section 7(b) of the NGA to abandon certificated facilities, but also
must file for authority under Section 4 of the NGA to terminate service from
both certificated and uncertificated facilities. On December 31, 1994, an
appeal was filed with the U.S. Court of Appeals for the D.C. Circuit to
overturn three of the FERC's rehearing orders. On February 28, 1996, the FERC
issued a Statement of Policy regarding the application of its jurisdiction
under the NGA and the Outer Continental Shelf Lands Act over new natural gas
facilities and services on the Outer Continental Shelf ("OCS"). In its Policy
Statement, the FERC concluded that it will retain its existing primary
function test to determine whether particular facilities on the OCS constitute
gathering facilities exempt from the FERC's NGA jurisdiction. However, the
FERC added a new factor to its primary function test for facilities that are
designed to collect gas produced in water depths of 200 meters or more. Such
facilities now will be presumed to qualify as gathering facilities up to the
point or points of potential connection with the interstate pipeline grid.
Downstream of that point, the facilities will be evaluated under the existing
primary function test. Existing interstate pipelines and gathering facilities
would retain their present status barring some change in circumstances. Mesa
has advised the Trust that it cannot predict what the ultimate effect of the
FERC's orders pertaining to gathering will have on its production and
marketing, or whether the Appellate Court will affirm the FERC's orders on
these matters.
State regulation of gathering facilities generally includes various
safety, environmental, and in some circumstances, non-discriminatory take
requirements, but does not generally entail rate regulation. Natural gas
gathering has received greater regulatory scrutiny at both the state and
federal levels as the pipeline restructuring under Order 636 continues.
ENVIRONMENTAL
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 reclassify certain oil
and gas production wastes as "hazardous wastes" which would subject the
18
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. In May 1995, the U.S. House of Representatives
approved a bill that would amend OPA to reduce the level of financial
responsibility to $35 million. The U.S. Senate passed a related measure on
November 17, 1995 that would also amend OPA to reduce the level of financial
responsibility to $35 million. The Clinton administration has expressed its
support for this legislation, but has not yet taken any action on the bills
approved by the House of Representatives and the U.S. Senate. The MMS had
indicated that it would not move forward with the adoption of the rule until
the United States Congress has had an opportunity to act on the pending
amendments to OPA. Based on the passage of these bills and the support of the
Clinton administration, it appears that the level of financial responsibility
required by OPA will be reduced and the MMS will probably not move forward
with the adoption of its rule as it was proposed. Within the next several
years, both the Texas and Louisiana state water discharge regulations and the
federal National Pollutant Discharge Elimination System permits may prohibit
the discharge of produced water, sand and other substances related to the
offshore oil and gas industry. Mesa has advised the Trust that the cost to
reformat operations to comply with these zero discharge mandates may be
significant. Amendments to the federal Clean Air Act require most industrial
operations in the United States, including offshore operations, to incur
future capital expenditures over the next several years in connection with air
emission control equipment necessary to maintain and obtain operating permits
and approvals. Some of Mesa's facilities are included within the categories of
air pollutant sources which will be affected by these regulations.
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 1995.
19
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 Stock Exchange -- ticker symbol MOS. The high and low sales prices and
distributions per unit for each quarter in the two years ended December 31,
1995 were as follows:
<TABLE>
<CAPTION>
1995 1994
------------------------------------- -------------------------------------
DISTRIBUTION DISTRIBUTION
HIGH LOW PAID HIGH LOW PAID
--------- --------- ------------- --------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
First Quarter........................ $ .250 $ .188 $ .017 $ .469 $ .344 $ .0385
Second Quarter....................... $ .250 $ .156 $ .010 $ .563 $ .281 $ .0372
Third Quarter........................ $ .250 $ .188 $ .012 $ .375 $ .250 $ .0296
Fourth Quarter....................... $ .250 $ .125 $ .002 $ .313 $ .156 $ .0167
</TABLE>
At March 20, 1996, the 71,980,216 units outstanding were held by 16,845
unitholders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991
------------- -------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
Royalty income.................. $ 3,139,620 $ 9,104,615 $ 13,867,712 $ 4,044,916 $ 2,865,775
Distributable income............ $ 2,803,862 $ 8,783,711 $ 13,458,769 $ 1,448,357 $ 2,314,983
Distributable income per unit... $ .0390 $ .1220 $ .1870 $ .0201 $ .0322
Excess cost carryforward........ $ (138,514) $ -- $ -- $ -- $ (453,329)
Total assets at year end........ $ 3,103,451 $ 4,724,878 $ 8,725,736 $ 9,295,438 $ 6,490,950
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
FINANCIAL REVIEW
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.
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.
YEARS 1994 AND 1993
Royalty income decreased to $9,104,615 in 1994 as compared to $13,867,712
in 1993. Distributable income decreased to $8,783,711 ($.1220 per unit) in
1994 as compared to $13,458,769 ($.1870 per unit) in 1993. The decrease in
Royalty income was primarily due to lower natural gas prices and decreased
production.
Production volumes for natural gas decreased to 5,580,788 Mcf in 1994
compared with 6,288,356 Mcf in 1993. The decrease was due primarily to natural
production decline. The average sale price received for natural gas in 1994
was $2.01 per Mcf compared with $2.20 per Mcf in 1993.
Crude oil, condensate and natural gas liquids production volumes
decreased to 181,775 barrels in 1994 compared with 289,189 barrels in 1993.
The decrease was due primarily to natural production decline. The average sale
price in 1994 for crude oil, condensate and natural gas liquids was $13.21 per
barrel compared with $15.44 per barrel in 1993.
20
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 and anticipates spending up to approximately $22
million ($14 million net to the Trust) in 1996.
ADDITIONAL DRILLING PROJECTS
Mesa contracted for and received three dimensional seismic surveys on
South Marsh Island blocks 155 and 156, West Delta blocks 61 and 62, Matagorda
Island block 624 and Brazos block A-7 during 1994 and 1995. Mesa completed the
drilling of the A-8 well in October 1995 on Matagorda Island block 624. The
well was completed and connected to existing production facilities at a total
cost of $3,202,000 ($940,000 net to the Trust). In addition, Mesa has advised
the Trust that it is pursuing its planned drilling program which includes up
to five wells from the existing "A" platform on the South Marsh Island 155
block. Mesa anticipates that the total cost of these five projects, assuming
each is undertaken, will be approximately $22 million ($14 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 drilling program currently being pursued by Mesa and
its potential effects on the Trust.
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 one well on the Matagorda Island 624
property in 1995 and is currently pursuing its planned drilling program on the
South Marsh Island properties. During the fourth quarter of 1995, Mesa
recovered approximately $573,000 in drilling expenses related to the drilling
of the A-8 well on Matagorda Island block 624. Mesa has advised the Trust that
no Royalty income will be paid to the Trust until Mesa recovers all costs
related to the Matagorda Island and South Marsh Island drilling along with any
additional completion costs required if the drilling is successful. In
addition, if payments of Royalty income to the Trust are resumed,
distributions to unitholders may be further delayed to allow the Trust to
recover administrative expenses paid during the period that Royalty income was
not paid to the Trust.
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 is
expected to cause the cash received by the Trust in 1996 to fall below the
threshold level; therefore 1996 could be the first of three successive years
of below threshold income, resulting in the termination of the Trust as early
as the end of 1998. If the drilling is successful, the effect on Royalty
income and Trust reserves will depend on the quality and quantities of
reserves found. See "Termination of the Trust" elsewhere in this Form 10-K.
21
OPERATIONAL REVIEW
Substantially all of the gas produced from the Trust properties during
1995 was sold at prices approximating spot market prices. As discussed in Item
1 of this Form 10-K, from November 1, 1994 through April 30, 1995,
substantially all of Mesa's offshore gas production was available for purchase
under a contract with NGC. Since May 1, 1995, all of Mesa's offshore gas
production has been available for purchase under short term contracts with
various purchasers.
The Brazos A-7 and A-39 blocks experienced a decrease in natural gas
production in 1995 as compared to 1994 primarily due to natural production
decline. During 1995, Mesa purchased a three dimensional seismic survey of the
A-7 block at a cost of $222,000 ($200,000 net to the Trust). Mesa is currently
evaluating the survey. On block A-39, well A-3 ceased production in February
1996. A through tubing recompletion is planned for the second quarter at an
estimated cost of $89,000 ($40,000 net to the Trust).
The South Marsh Island 155 and 156 blocks experienced a decrease in
production in 1995 as compared to 1994 primarily due to natural production
decline. During 1994 Mesa obtained a new seismic survey for block 155 to
better evaluate exploration and development opportunities. The cost of the
survey was approximately $280,000 ($176,000 net to the Trust). In the first
quarter of 1995, Mesa's management approved the purchase of additional
three dimensional seismic data for the west half at block 156 at an estimated
cost of $198,000 ($125,000 net to the Trust). As discussed above, Mesa has
advised the Trust that it is pursuing its planned drilling program on this
property which includes up to five wells from the existing "A" platform. Mesa
commenced drilling in February 1996 with the A-20 development well on South
Marsh Island block 156. Mesa estimates that the completed well cost of the
A-20 well will be approximately $2,300,000 ($1,450,000 net to the Trust).
Preliminary results of the A-20 drilling indicate 70 feet of net gas pay in
its objective sand. Drilling was recently completed on the A-21 development
well which encountered 31 feet of net gas pay. Mesa estimates the completed
well cost of the A-21 well will be approximately $2,200,000 ($1,386,000 net to
the Trust). Wells A-20 and A-21 were logged but not tested. In late March
1996, Mesa commenced drilling the A-6 sidetrack development well on South
Marsh Island 155. Mesa estimates that the completed well cost of the A-6 well
will be approximately $2,000,000 ($1,260,000 net to the Trust). Mesa expects
to complete these three development wells during late April 1996. Mesa intends
to drill the A-22 exploratory well on South Marsh Island 155 during May 1996,
with a completed well cost estimated at approximately $6.0 million ($3.8
million net to the Trust). Depending on the success of the A-22 exploratory
well, an additional well may be drilled on the South Marsh Island block 155,
with a completed well cost estimated at approximately $6.0 million ($3.8
million net to the Trust). Mesa anticipates that completion of these latter
two wells, if each is undertaken, would occur by the fourth quarter of 1996.
The West Delta 61 and 62 blocks experienced a decrease in production in
1995 as compared to 1994 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. In addition
in 1995 Mesa purchased a three dimensional seismic survey of this property at
a cost of approximately $513,000 ($462,000 net to the Trust). The data from
this survey is currently being evaluated by Mesa.
Matagorda Island 624 natural gas production decreased in 1995 in
comparison to 1994 due to natural production decline. During 1994 Mesa
purchased a three dimensional seismic survey of this property at a cost of
approximately $250,000 ($73,000 net to the Trust). Mesa successfully drilled
the A-8 development well in the fourth quarter of 1995 to a total depth of
9,470 feet at an estimated cost of $3,202,000 ($940,000 net to the Trust). The
well encountered 29 feet of net gas pay and tested approximately 20 MMcf of
natural gas and 270 barrels of condensate per day. However, production from
the A-8 well declined rapidly and it is currently producing 1.1 MMcf per day
and 6 barrels of condensate per day.
22
NET PROCEEDS, PRODUCTION AND AVERAGE PRICES (UNAUDITED)
<TABLE>
<CAPTION>
SOUTH
MARSH HIGH WEST MATAGORDA VERMIL-
BRAZOS ISLAND 155 ISLAND DELTA ISLAND ION
YEAR ENDED DECEMBER 31, 1995: 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................................ $ 1,691,468 $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
YEAR ENDED DECEMBER 31, 1993:
90% of--
Gross proceeds................................ $ 4,663,978 $9,697,901 $ (977) $2,656,275 $1,265,034 $ -- $18,282,211
Less 90% of--
Operating costs............................... (654,727) (1,229,157) (15,566) (697,901) (356,270) (15,516)(2,969,137)
Capital costs recovered....................... 5,850 (391) -- (527,898) (28,854) -- (551,293)
Accrual for future abandonment costs.......... (208,538) (276,481) (9) (339,421) (68,233) -- (892,682)
------------- ---------- --------- --------- ---------- --------- ----------
Net Proceeds
(Excess Costs)................................ $ 3,806,563 $8,191,872 $ (16,552) $1,091,055 $ 811,677 $ (15,516)$13,869,099
============= ========== ========= ========== ========== ========= ==========
Trust share of net proceeds (99.99%).............. $13,867,712
90% of Production Volumes and Average Sales Prices ==========
Crude oil, condensate and natural gas liquids
(Bbls)...................................... 7,865 264,862 -- 13,929 2,533 -- 289,189
============= ========== ========= ========== ========== ========= ==========
Average sales price per Bbl................... $ 17.12 $ 15.46 $ -- $ 13.67 $ 17.41 $ -- $ 15.44
============= ========== ========= ========== ========== ========= ==========
Natural gas (Mcf)............................. 2,188,005 2,663,028 -- 1,213,236 224,087 -- 6,288,356
============= ========== ========= ========== ========== ========= ==========
Average sales price per Mcf................... $ 2.06 $ 2.10 $ -- $ 2.07 $ 3.75 $ -- $ 2.20
============= ========== ========= ========== ========== ========= ==========
Producing wells (gross)........................... 3 3 -- 3 3 -- 12
</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 Matagorda Island 624
was $138,514 at December 31, 1995. See the Operational Review Section for
additional information.
23
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
--------------------------------------------
1995 1994 1993
------------- ------------- --------------
<S> <C> <C> <C>
Royalty income....................... $ 3,139,620 $ 9,104,615 $ 13,867,712
Interest income...................... 91,788 104,372 97,855
General and administrative expense... (427,546) (425,276) (506,798)
------------- ------------- --------------
Distributable income................. $ 2,803,862 $ 8,783,711 $ 13,458,769
------------- ------------- --------------
------------- ------------- --------------
Distributable income per unit........ $ .0390 $ .1220 $ .1870
------------- ------------- --------------
------------- ------------- --------------
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31
------------------------------------
1995 1994
----------------- -----------------
ASSETS
<S> <C> <C>
Cash and short-term investments............................................ $ 2,015,016 $ 3,171,260
Interest receivable........................................................ 21,275 25,821
Net overriding royalty interest in oil and gas properties.................. 380,905,000 380,905,000
Less: accumulated amortization........................................ (379,837,840) (379,377,203)
----------------- -----------------
$ 3,103,451 $ 4,724,878
----------------- -----------------
----------------- -----------------
LIABILITIES AND TRUST CORPUS
Reserve for trust expenses................................................. $ 2,000,000 $ 2,000,000
Distribution payable....................................................... 36,291 1,197,081
Trust corpus (71,980,216 units of beneficial
interest authorized and outstanding)..................................... 1,067,160 1,527,797
----------------- -----------------
$ 3,103,451 $ 4,724,878
----------------- -----------------
----------------- -----------------
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
------------------------------------------------
1995 1994 1993
-------------- -------------- ----------------
<S> <C> <C> <C>
Trust corpus, beginning of year................................ $ 1,527,797 $ 3,208,542 $ 5,847,081
Distributable income...................................... 2,803,862 8,783,711 13,458,769
Distributions to unitholders.............................. (2,803,862) (8,783,711) (13,458,769)
Amortization of net overriding royalty interest........... (460,637) (1,680,745) (2,638,539)
-------------- -------------- ----------------
Trust corpus, end of year...................................... $ 1,067,160 $ 1,527,797 $ 3,208,542
-------------- -------------- ----------------
-------------- -------------- ----------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
24
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 $149,000, $177,500 and $207,000 for the years
1995, 1994 and 1993, 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 plans to drill up to five wells from
the existing "A" platform on the South Marsh Island 155 block during 1996.
Mesa has advised the Trust that no royalty income will be paid to the Trust
until MESA Inc. recovers the drilling costs along with any additional
completion costs required if the drilling is successful. In addition, if
payments of royalty income to the Trust are resumed, distributions to
unitholders may be further delayed to allow the Trust to recover
administrative expenses paid during the period that royalty income was not
paid to the Trust.
25
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 December 31, 1995, reserve report prepared
for the Partnership indicates that the recovery of costs associated with the
Matagorda Island 624 and South Marsh Island 155 and 156 development drilling
programs will cause the Trust to be in a deficit for 1996. As such, 1996 could
be the first of three successive years of below threshold income, resulting in
the termination of the Trust as early as the end of 1998. If drilling is
successful, the effect on royalty income and Trust reserves will depend on the
quality and quantity of reserves found.
In addition, MESA Inc. has advised the Trust that its independent public
accountants included a going concern paragraph in their report on its 1995
financial statements. The going concern paragraph refers to Mesa Inc.'s
current financial forecasts, which indicate that Mesa Inc. will be unable to
fund required debt principal and interest obligations due in June 1996 with
cash flows from operating activities, available cash, and investment balances.
In an effort to address its liquidity issues, in July 1995 MESA Inc.'s Board
of Directors approved and implemented a proposal solicitation process which
expanded its exploration of strategic alternatives from the selling of the
Hugoton field to include consideration of the sale of MESA Inc., a
stock-for-stock merger, joint ventures, asset sales, equity infusions, and
refinancing transactions. On February 28, 1996, MESA Inc. signed a letter of
intent with Rainwater, Inc. (Rainwater), an independent investment company
owned by Ft. Worth, Texas, investor Richard Rainwater, to raise $265 million
of equity in connection with a refinancing of MESA Inc.'s debt. The proposed
transaction is subject to certain conditions, including negotiation and
execution of definitive agreements, arrangement of the new debt financing, due
diligence by Rainwater and MESA Inc. stockholder approval. There can be no
assurance that this transaction will be completed, what the final terms or
timing thereof will be. Further, there can be no assurance regarding the
availability or terms of any refinancing debt.
If the Rainwater transaction is not completed, MESA Inc. has advised the
Trust it will pursue other alternatives to address its liquidity issues and
financial condition, including other potential transactions arising from the
proposal solicitation process, the possibility of seeking to restructure its
balance sheet by negotiating with its current debt holders or seeking
protection from its creditors under the Federal Bankruptcy Code.
No assurance can be given by the Trust regarding MESA Inc.'s financial
condition. An event of bankruptcy of MESA Inc. that includes the Managing
General Partner would cause a dissolution of the Partnership which could cause
a termination of the Trust as described above. An event of bankruptcy of MESA
Inc. could also result in a delay in receipt of royalty payments by the Trust,
increased administrative expenses of the Trust and other effects which cannot
be predicted or quantified at this time.
(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
26
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
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.
(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, 1995 and 1994, 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
27
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
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 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.
28
MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS--CONTINUED
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, 1992............... 702,762 11,992,230
Revisions of previous
estimates.............. (277,918) (1,148,045)
Production................ (219,494) (4,772,862)
------------ -------------
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
============ =============
Proved Developed Reserves:
December 31, 1993............... 205,350 6,071,323
============ =============
December 31, 1994............... 144,702 3,080,069
============ =============
December 31, 1995............... 116,623 1,621,034
============ =============
- ------------
(See Notes on following page.)
29
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
--------------------
1995 1994
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Ninety percent of future gross proceeds.................................................... $ 21,205 $ 17,686
Less ninety percent of --
Future operating costs................................................................ (8,740) (6,881)
Future capital costs, net of amounts previously accrued............................... (5,191) (2,529)
--------- ---------
Future royalty income...................................................................... 7,274 8,276
Discount at 10% per annum.................................................................. (1,635) (1,399)
--------- ---------
Standardized measure of future royalty
income from proved oil and gas reserves.................................................. $ 5,639 $ 6,877
========= =========
</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
---------------------------------
1995 1994 1993
--------- --------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure at beginning of year.................................... $ 6,877 $ 14,779 $ 31,419
--------- --------- -----------
Revisions of previous estimates......................................... (271) (570) (5,914)
Extensions, discoveries and other additions............................. 1,485 295 --
Royalty income.......................................................... (3,140) (9,105) (13,868)
Accretion of discount................................................... 688 1,478 3,142
--------- --------- -----------
Net changes in standardized measure..................................... (1,238) (7,902) (16,640)
--------- --------- -----------
Standardized measure at end of year.......................................... $ 5,639 $ 6,877 $ 14,779
========= ========= ===========
</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: 1995, 123,220 Bbls; 1994, 133,466 Bbls;
1993, 178,662 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, 1995 includes, in thousands, $9,076 of future abandonment costs net of
$8,335 previously accrued by Mesa.
30
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>
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
1994:
Royalty income.................................. $ 2,857,966 $ 2,812,772 $2,170,576 $ 1,263,301
Distributable income............................ $ 2,771,861 $ 2,680,882 $2,133,887 $ 1,197,081
Distributable income per unit................... $ .0385 $ .0372 $ .0296 $ .0167
</TABLE>
31
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, 1995 and 1994, and
the related statements of distributable income and changes in trust corpus for
each of the three years in the period ended December 31, 1995. These financial
statements are the responsibility of the Trustee. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
These financial statements were prepared on the basis of accounting
described in Note 3, which is a comprehensive basis of accounting other than
generally accepted accounting principles.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the assets, liabilities and trust corpus of
the Mesa Offshore Trust as of December 31, 1995 and 1994, and its
distributable income and changes in trust corpus for each of the three years
in the period ended December 31, 1995, on the basis of accounting described in
Note 3.
The accompanying financial statements have been prepared assuming that
the Trust will continue as a going concern. As set forth in Note 1, MESA Inc.
has advised the Trust that it intends to commence additional drilling on
certain Trust properties in 1996. After drilling commences, no royalty income
will be paid to the Trust until MESA Inc. recovers the drilling costs along
with any additional completion costs. Thus, it is possible that, as early as
1996, the Trust may commence a period of three successive years in which
annual net royalty income could be below the defined minimum threshold,
resulting in termination of the Trust as early as the end of 1998. Also, as
discussed further in Note 1, MESA Inc. has advised the Trust that the report
of its independent public accountants on its 1995 financial statements
includes a going concern paragraph, which discusses MESA Inc.'s inability to
meet its debt service requirements in 1996. These circumstances could have
significant effects on the Trust, which could include termination of the
Trust, although the precise nature of such effects cannot be predicted at this
time. These circumstances raise substantial doubt about the Trust's ability to
continue as a going concern. The financial statements do not include any
adjustments that might result from these circumstances.
ARTHUR ANDERSEN LLP
Houston, Texas
March 26, 1996
32
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.
PAGE IN THIS
FORM 10-K
------------
Statements of Distributable Income................................... 24
Statements of Assets, Liabilities and Trust Corpus................... 24
Statements of Changes in Trust Corpus................................ 24
Notes to Financial Statements........................................ 25
Report of Independent Public Accountants............................. 32
(a)(2) SCHEDULES
Schedules have been omitted because they are not required, not applicable
or the information required has been included elsewhere herein.
34
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/ MICHAEL J. ULRICH
Michael J. Ulrich
Senior Vice President
& Trust Officer
March 26, 1996
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.
35
EXHIBIT INDEX
<TABLE>
<CAPTION>
SEC FILE
OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------ -------
<S> <C> <C> <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) *Amendment to Partnership Agreement between Texas Commerce Bank
National 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>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 2,015,016
<SECURITIES> 0
<RECEIVABLES> 21,275
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 2,036,291
<PP&E> 380,905,000
<DEPRECIATION> 379,837,840
<TOTAL-ASSETS> 3,103,451
<CURRENT-LIABILITIES> 36,291
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 1,067,160
<TOTAL-LIABILITY-AND-EQUITY> 3,103,451
<SALES> 3,139,620
<TOTAL-REVENUES> 3,231,408
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 427,546
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 0
<INCOME-TAX> 0
<INCOME-CONTINUING> 2,803,862
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,803,862
<EPS-PRIMARY> .039
<EPS-DILUTED> .039
</TABLE>
