================================================================================
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE TRANSITION PERIOD FROM _____________________ TO
______________________
COMMISSION FILE NUMBER: 0-6910
------------------------
TEL OFFSHORE TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-6004064
(STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER
OF INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
TEXAS COMMERCE BANK
NATIONAL ASSOCIATION
CORPORATE TRUST DIVISION
712 MAIN STREET
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL (ZIP CODE)
EXECUTIVE OFFICES)
Registrant's Telephone Number, Including Area Code: (713) 216-5712
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 the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
As of November 1, 1996 -- 4,751,510 Units of Beneficial Interest in TEL
Offshore Trust.
================================================================================
<PAGE>
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-Q 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-Q are forward-looking
statements. Although the Working Interest Owners have advised the Trust that
they believe that the expectations reflected in the forward-looking statements
contained herein are reasonable, no assurance can be given that such
expectations will prove to have been correct. Important factors that could cause
actual results to differ materially from expectations ("Cautionary
Statements") are disclosed in this Form 10-Q, including without limitation in
conjunction with the forward-looking statements included in this Form 10-Q. All
subsequent written and oral forward-looking statements attributable to the Trust
or persons acting on its behalf are expressly qualified in their entirety by the
Cautionary Statements.
<PAGE>
PART I -- FINANCIAL INFORMATION
ITEM 1 -- FINANCIAL STATEMENTS
TEL OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------- ------------------------
1996 1995 1996 1995
------------ ------------ ---------- ------------
<S> <C> <C> <C> <C>
Royalty income....................... $ 785,708 $ 468,689 $ 785,708 $ 1,109,052
Interest income...................... 4,709 8,406 22,018 22,110
------------ ------------ ---------- ------------
790,417 477,095 807,726 1,131,162
Decrease (increase) in reserve for
future Trust expenses.............. (99,536) (128,169) 185,381 (289,525)
General and administrative
expenses........................... (100,464) (71,831) (402,690) (310,475)
------------ ------------ ---------- ------------
Distributable income................. $ 590,417 $ 277,095 $ 590,417 $ 531,162
============ ============ ========== ============
Distributions per Unit (4,751,510
Units)............................. $ .124258 $ .058317 $ .124258 $ .111787
============ ============ ========== ============
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
SEPTEMBER 30, DECEMBER 31,
1996 1995
---------- ----------
(UNAUDITED)
ASSETS
Cash and cash equivalents .................... $1,582,968 $1,261,606
Net overriding royalty interest in producing
oil and gas properties net of accumulated
amortization of $27,329,066 and
$27,196,037, respectively .................. 938,589 1,071,618
---------- ----------
Total assets ................................. $2,521,557 $2,333,224
========== ==========
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit holders ......... $ 590,417 $ 83,674
Reserve for future Trust expenses ............ 992,551 1,177,932
Commitments and contingencies (Note 7)
Trust corpus (4,751,510 Units of beneficial
interest authorized and outstanding) ....... 938,589 1,071,618
---------- ----------
Total liabilities and Trust corpus ........... $2,521,557 $2,333,224
========== ==========
The accompanying notes are an integral part of these financial statements.
1
<PAGE>
TEL OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------- --------------------------
1996 1995 1996 1995
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Trust corpus, beginning of period.... $ 1,071,618 $ 1,232,357 $ 1,071,618 $ 1,343,475
Distributable income................. 590,417 277,095 590,417 531,162
Distributions payable to Unit
holders............................ (590,417) (277,095) (590,417) (531,162)
Amortization of net overriding
royalty interest................... (133,029) (101,018) (133,029) (212,136)
------------ ------------ ------------ ------------
Trust corpus, end of period.......... $ 938,589 $ 1,131,339 $ 938,589 $ 1,131,339
============ ============ ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
2
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 -- TRUST ORGANIZATION
Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL
Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of
Dissolution ("Plan") approved by Tenneco Offshore's stockholders on December
22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership
("Partnership") was formed in which the Trust owns a 99.99% interest and
Tenneco Oil Company ("Tenneco") initially owned a .01% interest. In general,
the Plan was effected by transferring an overriding royalty interest
("Royalty") equivalent to a 25% net profits interest in the oil and gas
properties (the "Royalty Properties") of Tenneco Exploration, Ltd.
("Exploration I") located offshore Louisiana to the Partnership and issuing
certificates evidencing units of beneficial interest in the Trust ("Units") in
liquidation and cancellation of Tenneco Offshore's common stock.
On October 31, 1986, Exploration I was dissolved and the oil and gas
properties of Exploration I were distributed to Tenneco subject to the Royalty.
Tenneco, who was then serving as the Managing General Partner of the
Partnership, assumed the obligations of Exploration I, including its obligations
under the instrument conveying the Royalty to the Partnership (the
"Conveyance"). The dissolution of Exploration I had no impact on future cash
distributions to Unit holders.
On November 18, 1988, Chevron U.S.A. Inc. ("Chevron") acquired most of
the Gulf of Mexico offshore oil and gas properties of Tenneco, including all the
Royalty Properties. As a result of the acquisition, Chevron replaced Tenneco as
the Working Interest Owner and Managing General Partner of the Partnership.
Chevron also assumed Tenneco's obligations under the Conveyance.
On October 30, 1992, Pennzoil Company ("Pennzoil") acquired certain oil
and gas producing properties from Chevron, including four of the Royalty
Properties. The four Royalty Properties acquired by Pennzoil were East Cameron
354, Eugene Island 348, Eugene Island 367 and Eugene Island 208. As a result of
such acquisition, Pennzoil replaced Chevron as the Working Interest Owner of
such properties on October 30, 1992. Pennzoil also assumed Chevron's obligations
under the Conveyance with respect to such properties.
On December 1, 1994, Texaco Exploration and Production Inc. ("Texaco")
acquired three of the Royalty Properties from Chevron. The Royalty Properties
acquired by Texaco were West Cameron 643, East Cameron 370 and East Cameron 371.
As a result of such acquisition, Texaco replaced Chevron as the Working Interest
Owner of such properties on December 1, 1994. Texaco also assumed Chevron's
obligations under the Conveyance with respect to such properties.
On October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East
Cameron 354 property from Pennzoil. In addition, on October 1, 1995, Amoco
Production Company ("Amoco") acquired the Eugene Island 367 property from
Pennzoil. As a result of such acquisitions, SONAT and Amoco have replaced
Pennzoil as the Working Interest Owners of the East Cameron 354 and Eugene
Island 367 properties, respectively, and also have assumed Pennzoil's
obligations under the Conveyance with respect to such properties.
Chevron remains the Managing General Partner of the Partnership. All of the
Royalty Properties continue to be subject to the Royalty, and the Trust and the
Partnership, in general, continue to operate as if the above-described sales of
the Royalty Properties had not occurred.
Unless the context in which such terms are used indicates otherwise, in
these Notes the terms "Working Interest Owner" and "Working Interest Owners"
generally refer to the owner or owners of the
3
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
Royalty Properties (Exploration I through October 31, 1986; Tenneco for periods
from October 31, 1986 until November 18, 1988; Chevron with respect to all
Royalty Properties for periods from November 18, 1988 until October 30, 1992 and
with respect to all Royalty Properties except East Cameron 354, Eugene Island
348, Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992
until December 1, 1994 and with respect to the same properties except West
Cameron 643, East Cameron 370 and East Cameron 371 thereafter; Pennzoil with
respect to East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene
Island 208 for periods from October 30, 1992 until October 1, 1995 and with
respect to Eugene Island 348 and Eugene Island 208 thereafter; Texaco with
respect to West Cameron 643, East Cameron 370 and East Cameron 371 for periods
beginning on or after December 1, 1994; SONAT with respect to East Cameron 354
for periods beginning on or after October 1, 1995; and Amoco with respect to
Eugene Island 367 for periods beginning on or after October 1, 1995).
NOTE 2 -- BASIS OF ACCOUNTING
The accompanying unaudited financial information has been prepared by Texas
Commerce Bank National Association ("Corporate Trustee") in accordance with
the instructions to Form 10-Q and does not include all of the information
required by generally accepted accounting principles for complete financial
statements, although the Corporate Trustee and the individual trustees
(collectively, the "Trustees") believe that the disclosures are adequate to
make the information presented not misleading. The information furnished
reflects all adjustments which are, in the opinion of the Trustees, necessary
for a fair presentation of the results for the interim periods presented. The
financial information should be read in conjunction with the financial
statements and notes thereto included in the Trust's Annual Report on Form 10-K
for the year ended December 31, 1995.
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income is recorded when received by the Corporate Trustee
on the last business day of each calendar quarter; and
(b) Trust general and administrative expenses are recorded when paid,
except for the cash reserved for future general and
administrative expenses, as discussed in Note 6.
This manner of reporting income and expenses is considered to be the most
meaningful because the quarterly distributions to Unit holders are based on net
cash receipts received from the Working Interest Owners. The financial
statements of the Trust differ from financial statements prepared in accordance
with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would
be recognized on an accrual basis. In addition, amortization of the overriding
royalty interest, which is calculated based on units-of-production, is charged
directly to Trust corpus since such amount does not affect distributable income.
Cash and cash equivalents include all highly liquid short term investments
with original maturities of three months or less.
Effective January 1, 1996, the Trust adopted Statement of Financial
Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The adoption of
SFAS 121 did not have a material impact on the financial position or
distributable income of the Trust.
4
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
NOTE 3 -- OVERRIDING ROYALTY INTEREST
The Royalty entitles the Trust to its share (99.99%) of 25% of the Net
Proceeds attributable to the Royalty Properties. The Conveyance, dated January
1, 1983, provides that the Working Interest Owners will calculate, for each
period of three months commencing the first day of February, May, August and
November, an amount equal to 25% of the Net Proceeds from their oil and gas
properties for the period. Generally, Net Proceeds are the amounts received by
the Working Interest Owners from the sale of minerals from the Royalty
Properties less operating and capital costs incurred, management fees and
expense reimbursements owing the Managing General Partner of the Partnership,
applicable taxes other than income taxes, and cash escrows. Cash escrows are for
the future costs to be incurred to plug and abandon wells, dismantle and remove
platforms, pipelines and other production facilities, and for the estimated
amount of future capital expenditures on the Royalty Properties. Net Proceeds do
not include amounts received by the Working Interest Owners as advance gas
payments, "take-or-pay" payments or similar payments unless and until such
payments are extinguished or repaid through the future delivery of gas.
NOTE 4 -- DISTRIBUTIONS TO UNIT HOLDERS
In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. The
amounts distributed are determined on a quarterly basis and are payable to Unit
holders of record as of the last business day of each calendar quarter. However,
cash distributions are made in January, April, July and October and include
interest earned from the quarterly record date to the date of distribution.
NOTE 5 -- SPECIAL COST ESCROW ACCOUNT
The Conveyance provides for reserving funds for estimated future "Special
Costs" of plugging and abandoning wells, dismantling platforms and other costs
of abandoning the Royalty Properties, as well as for the estimated amount of
future drilling projects and other capital expenditures on the Royal Properties.
As provided in the Conveyance, the amount of funds to be reserved is determined
based on factors including estimates of aggregate future production costs,
aggregate future Special Costs, aggregate future net revenues and actual current
net proceeds. Deposits into this account reduce current distributions and are
placed in an escrow account and invested in short-term certificates of deposit.
Such account is herein referred to as the "Special Cost Escrow Account."
Deposits to the Special Cost Escrow Account will generally be made when the
balance in the Special Cost Escrow Account is less than 125% of future Special
Costs and there is a Net Revenues Shortfall (a calculation of the excess of
estimated future costs over estimated future net revenues pursuant to a formula
contained in the Conveyance). When there is not a Net Revenues Shortfall,
amounts in the Special Cost Escrow Account will generally be released, to the
extent that Special Costs have been incurred. Amounts in the Special Cost Escrow
Account generally will also be released when the balance in such account exceeds
125% of future Special Costs. In the first nine months of 1995, a net deposit of
approximately $95,300 was made by the Trust into the Special Cost Escrow
Account. The deposit was primarily a result of an increase in the estimates of
projected capital expenditures on the Royalty Properties. In the first nine
months of 1996, there was also a deposit of funds into the Special Cost Escrow
Account. The Trust's share of the funds deposited was approximately $1,493,500.
The deposit was primarily a result of an increase in the current estimates of
projected capital expenditures, production costs
5
<PAGE>
TEL OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(UNAUDITED)
and abandonment costs in connection with the Ship Shoal 182/183 drilling. As of
September 30, 1996, approximately $4,065,500 remained in the Special Cost Escrow
Account.
Capital expenditures and drilling programs by the Working Interest Owners,
such as those discussed under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" in this Form 10-Q can have a
significant impact on the amount of deposits into the Special Cost Escrow
Account. Such deposits can result in a significant reduction in royalty income
in the periods in which such deposits are made, including the possibility that
no royalty income would be received in such periods.
NOTE 6 -- EXPENSE RESERVE
At December 31, 1991, a cash reserve of $120,000 had been established for
future Trust general and administrative expenses. During 1992 and 1993, in
anticipation of future periods when the cash received from the Royalty may not
be sufficient for payment of Trust expenses, the reserve for future Trust
general and administrative expenses was increased each quarter by an amount
equal to the difference between $150,000 and the amount of the Trust's general
and administrative expenses for such quarter. In March 1994, the Trust
determined, in accordance with the Trust Agreement, to begin further increasing
the Trust's cash reserve each quarter by an amount equal to the difference
between $200,000 and the amount of the Trust's general and administrative
expenses for such quarter. During the first six months of 1996, the Trust
received no royalty income and used approximately $284,900 from the Trust's cash
reserve account to pay the Trust's general and administrative expenses for such
period. In the third quarter of 1996, payments of royalty income to the Trust
resumed and general and administrative expenses of the Trust were approximately
$100,500. Accordingly, the Trust's cash reserve was increased by approximately
$99,500 in such quarter, bringing the total amount of the Trust's cash reserves
at September 30, 1996 to $992,551.
NOTE 7 -- COMMITMENTS AND CONTINGENCIES
During 1994, Pennzoil, the Working Interest Owner on the Eugene Island 348
property, settled a gas imbalance on that property for approximately $2,696,000.
The Trust's share of this settlement amount was approximately $674,000, of which
approximately $160,200 has been recovered from the Trust by the Working Interest
Owner through the third quarter of 1996, and the remainder will be subject to
recovery from the Trust in future periods, in accordance with the Conveyance.
The Working Interest Owner has advised the Trust that future Royalty income
attributable to all of the Royalty Properties owned by Pennzoil will be used to
offset the Trust's share of such settlement amounts. Based on current
production, prices and expenses for the Royalty Properties owned by Pennzoil, it
is estimated that Royalty income attributable to such properties will be
retained by Pennzoil for the remaining life of the Trust. The Trust does not
anticipate that retention of such Royalty income by Pennzoil will have a
material effect on the Trust's Royalty income as a whole.
The Working Interest Owners have advised the Trust that, although they
believe that they are in general compliance with applicable health, safety and
environmental laws and regulations that have taken effect at the federal, state
and local levels, costs may be incurred to comply with current and proposed
environmental legislation which could result in increased operating expenses on
the Royalty Properties.
6
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FINANCIAL REVIEW
THREE MONTHS ENDED SEPTEMBER 30, 1996 AND 1995
Distributions to Unit holders for the three months ended September 30, 1996
amounted to $590,417 or $.124258 per Unit as compared to $277,095 or $.058317
per Unit for the same period in 1995. The increase in distributable income for
the third quarter of 1996 was primarily due to a signficant increase in natural
gas revenues in the third quarter of 1996, as compared to the third quarter of
1995.
Gas revenues increased approximately 636% in the third quarter of 1996
compared to the third quarter of 1995 primarily due to a 401% increase in gas
volumes, which was primarily attributable to production from three new wells on
the West Cameron 643 property. In addition, there was a 49% increase in the
average price received for natural gas from $1.66 per Mcf in the third quarter
of 1995 to $2.48 per Mcf in the third quarter of 1996. Crude oil and condensate
revenues increased approximately 10% in the third quarter of 1996 in comparison
to the same period in 1995 primarily due to an 11% increase in the average price
received from $16.38 per barrel in the third quarter of 1995 to $18.24 per
barrel in the third quarter of 1996. The increase in average price was slightly
offset by a 2% decrease in crude oil and condensate volumes from the 1995 third
quarter to the 1996 third quarter. The Trust's share of capital expenditures
increased by approximately $528,300 in the third quarter of 1996 as compared to
the same period in 1995 due primarily to expenses incurred on the B-11, B-12 and
F-2 wells drilled on the Ship Shoal 182/183 property in the first and second
quarters of 1996. The Trust's share of operating expenses increased by
approximately $77,800 in the third quarter of 1996 as compared to the same
period in 1995 due primarily to expenses incurred in the third quarter of 1996
in connection with the A-10 well workover on the West Cameron 643 property.
For the third quarter of 1996, the Trust had undistributed net income of
approximately $77,200. Undistributed net income represents positive Net Proceeds
generated during the period that were applied to an existing loss carryforward.
The undistributed net income for the third quarter of 1996 was primarily related
to a loss carryforward associated with six well workovers on the West Cameron
643 property conducted in the first quarter of 1996. As of September 30, 1996,
the loss carryforward was $2,154,332 ($538,583 net to the Trust). This loss
carryforward relates primarily to the Eugene Island 348 gas imbalance settlement
in 1994. See Note 7 in the Notes to Financial Statements for information
regarding such settlement.
In the third quarter of 1996, there was a deposit of funds into the Special
Cost Escrow Account. The Trust's share of the funds deposited was approximately
$172,500, compared to a release of funds from the Special Cost Escrow Account of
$1,875 net to the Trust in the third quarter of 1995. The Special Cost Escrow is
set aside for estimated abandonment costs and future capital expenditures as
provided for in the Conveyance. For additional information relating to the
Special Cost Escrow see "Special Cost Escrow Account" below.
NINE MONTHS ENDED SEPTEMBER 30, 1996 AND 1995
Distributions to Unit holders for the nine months ended September 30, 1996
amounted to $590,417 or $.124258 per Unit as compared to $531,162 or $.111787
per Unit for the same period in 1995. The increase in distributable income for
the first nine months of 1996 was primarily due to an increase in natural gas
revenues in the first nine months of 1996, as compared to the first nine months
of 1995.
Gas revenues increased approximately 266% in the first nine months of 1996
as compared to the first nine months of 1995 primarily due to a 148% increase in
gas volumes, which increase was primarily
7
<PAGE>
attributable to production from three new wells on the West Cameron 643
property. In addition, there was a 51% increase in the average price received
for natural gas from $1.68 per Mcf in the first nine months of 1995 to $2.53 per
Mcf in the first nine months of 1996. Crude oil and condensate revenues
increased approximately 72% in the first nine months of 1996 as compared to the
same period in 1995 primarily due to a 66% increase in crude oil and condensate
volumes. The increase in volumes was primarily attributable to a well adjustment
of 187,000 barrels on the B-13 well on the Eugene Island 339 property in the
first quarter of 1996. In addition, there was an increase in the average price
received from $16.22 per barrel in the first nine months of 1995 to $16.88 per
barrel in the first nine months of 1996. The Trust's share of capital
expenditures increased by approximately $1,449,000 in the first nine months of
1996 as compared to the same period in 1995 due primarily to six workovers on
the West Cameron 643 property and to drilling the F-2, B-11 and B-12 wells on
the Ship Shoal 182/183 property in the first nine months of 1996. The Trust's
share of operating expenses increased by approximately $172,200 in the first
nine months of 1996 as compared to the same period in 1995 due primarily to a
compressor repair on the Ship Shoal 182/183 property in the first quarter of
1996 and expenses incurred in connection with the A-10 well workover on the West
Cameron 643 property in the third quarter of 1996.
For the first nine months of 1996, the Trust had undistributed net income
of approximately $4,100. The undistributed net income in the first nine months
of 1996 was primarily related to a loss carryforward associated with six well
workovers on the West Cameron 643 property in the first quarter of 1996.
In the first nine months of 1996 there was a net deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $1,493,500. During the first nine months of 1995, there was a
deposit of funds into the Special Cost Escrow Account. The Trust's share of the
funds deposited was approximately $95,300. For additional information relating
to the Special Cost Escrow see "Special Cost Escrow Account" below.
RESERVE FOR FUTURE TRUST EXPENSES
In accordance with the provisions of the Trust Agreement, generally all Net
Proceeds received by the Trust, net of Trust general and administrative expenses
and any cash reserves established for the payment of contingent or future
obligations of the Trust, are distributed currently to the Unit holders. During
1992 and 1993, in anticipation of future periods when the cash received from the
Royalty may not be sufficient for payment of Trust expenses, the reserve for
future Trust general and administrative expenses was increased each quarter by
an amount equal to the difference between $150,000 and the amount of the Trust's
general and administrative expenses for such quarter. In March 1994, the Trust
determined, in accordance with the Trust Agreement, to begin further increasing
the Trust's cash reserve each quarter by an amount equal to the difference
between $200,000 and the amount of the Trust's general and administrative
expenses for such quarter. During the first six months of 1996, the Trust
received no royalty income and used approximately $284,900 from the Trust's cash
reserve account to pay the Trust's general and administrative expenses for such
period. In the third quarter of 1996, payments of royalty income to the Trust
resumed and general and administrative expenses of the Trust were approximately
$100,500. Accordingly, the Trust's cash reserve was increased by approximately
$99,500 in such quarter, bringing the total amount of the Trust's cash reserve
at September 30, 1996 to $992,551.
OTHER
The amount of cash distributed by the Trust is dependent on, among other
things, the sales prices and quantities of oil and gas produced from the Royalty
Properties. It should be noted that substantial uncertainties exist with regard
to future oil and gas prices, which are subject to material fluctuations due to
changes in production levels and pricing and other actions taken by major
petroleum producing nations, as
8
<PAGE>
well as the regional supply and demand for oil and gas, weather, industrial
growth, conservation measures, competition and other variables.
On October 22, 1996, the Trust Units were delisted from the Nasdaq SmallCap
Market. The delisting was a result of a determination by Nasdaq that the Trust
would not be able to sustain long-term compliance with Nasdaq continued listing
standards. The Trust has been advised by Nasdaq that the Trust Units are being
traded on the OTC Bulletin Board. The Trust Units may also be traded on pink
sheets.
OPERATIONAL REVIEW
THREE MONTHS ENDED SEPTEMBER 30, 1996 AND 1995
VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED BY
THE WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.
Ship Shoal 182/183 gas revenues increased from $119,527 in the third
quarter of 1995 to $123,463 in the third quarter of 1996, primarily due to an
increase in the average natural gas sales price for Ship Shoal 182/183 from
$1.94 per Mcf in the third quarter of 1995 to $2.55 per Mcf in the same period
of 1996. The increase in sales price was offset by a decrease in gas volumes.
Gas volumes decreased from 60,447 Mcf in the third quarter of 1995 to 49,448 Mcf
in the third quarter of 1996 due primarily to a compressor shut down for six
weeks in the third quarter of 1996 for repairs and a continued natural
production decline on this property. The majority of the gas from this property
is being purchased by Tennessee Gas Pipeline Company ("Tennessee Gas") at a
calculated monthly price based on the spot market rate. In addition, the Working
Interest Owner has advised the Trust that approximately 52,500 Mcf have been
overtaken by the Working Interest Owner from this property as of July 31, 1996.
The Trust's share of this overtake position is approximately 13,125 Mcf.
Accordingly, gas revenues from this property may be reduced in future periods
while underproduced parties recover their share of the gas imbalance. A decrease
in crude oil production from 62,930 barrels in the third quarter of 1995 to
55,916 barrels in the third quarter of 1996 and an increase in the average crude
oil price from $16.40 per barrel in the third quarter of 1995 to $18.60 per
barrel for the same period in 1996 resulted in an increase in crude oil revenues
from $1,032,141 in the third quarter of 1995 to $1,040,053 in the third quarter
of 1996. The decrease in crude oil production was primarily due to a continued
natural production decline on this property. Operating expenses increased from
$409,364 in the third quarter of 1995 to $432,793 in the third quarter of 1996.
Capital expenditures increased $1,507,218 in the third quarter of 1996 compared
to the third quarter of 1995 due primarily to the drilling of the F-2
delineation gas well and the B-11 and B-12 developmental oil wells in the first
nine months of 1996. The Working Interest Owner has advised the Trust that the
B-13 well drilling was begun in the third quarter of 1996. The estimated cost of
drilling the four wells and the related platform improvements on this property
is $10.5 million ($2.625 million net to the Trust). Production on the B-11, B-12
and B-13 wells is scheduled to begin in the fourth quarter of 1996.
Eugene Island 339 gas revenues increased from $148,123 in the third quarter
of 1995 to $214,286 in the third quarter of 1996 due primarily to an increase in
the average price received for natural gas from $1.60 per Mcf in the third
quarter of 1995 to $2.68 per Mcf in the third quarter of 1996. The increase in
average price was partially offset by a decrease in gas volumes from 87,650 Mcf
in the third quarter of 1995 to 79,230 Mcf for the same period in 1996. The
decrease in gas volumes was primarily due to the shut down of a booster pumping
station and a continued natural production decline on this property. The Working
Interest Owner has advised the Trust that there is an overtake imbalance
position of approximately 325,500 Mcf on this property as of July 31, 1996. The
Trust's share of this overtake position is approximately 81,375 Mcf.
Accordingly, gas revenues from this property may be reduced in future periods
while underproduced parties recoup their share of the gas imbalance. The gas
from this property is currently committed to Tennessee Gas pursuant to an
agreement providing for gas to be purchased at a calculated
9
<PAGE>
monthly price based on the spot market rate. Crude oil and condensate revenues
increased from $1,340,167 in the third quarter of 1995 to $1,596,404 in the
third quarter of 1996 due primarily to an increase in the average price received
for crude oil and condensate from $16.37 per barrel in the third quarter of 1995
to $18.00 per barrel in the third quarter of 1996. In addition, there was an
increase in volumes from 81,878 barrels in the third quarter of 1995 to 88,684
barrels for the same period of 1996. The increase in 1996 volumes was primarily
due to volumes on the B-13 well being understated in 1995. The B-13 well
adjustment was made in the first quarter of 1996. Operating expenses decreased
from $340,575 in the third quarter of 1995 to $229,038 in the third quarter of
1996 due primarily to a service facilities credit of approximately $77,000
($19,250 net to the Trust) in the third quarter of 1996. The Working Interest
Owner has advised the Trust that it intends to pursue drilling on this property
in 1997 if drilling on nearby non-Trust properties in 1996 is successful.
West Cameron 643 gas revenues increased from $290,666 in the third quarter
of 1995 to $4,889,460 in the third quarter of 1996 due primarily to an increase
in gas volumes. Gas volumes increased from 185,172 Mcf in the third quarter of
1995 to 1,976,704 Mcf in the third quarter of 1996 primarily due to the
successful B-5, B-8 and B-9 wells drilled on this property in the second quarter
of 1996. In addition, there was an increase in the average price received for
natural gas from $1.57 per Mcf in the third quarter of 1995 to $2.47 per Mcf for
the same period in 1996. Operating expenses increased from $79,275 in the third
quarter of 1995 to $319,993 in the third quarter of 1996 due primarily to
expenses incurred in the third quarter of 1996 in connection with the workover
on the A-10 well. Capital expenditures increased from $358,691 in the third
quarter of 1995 to $861,982 in the third quarter of 1996 due primarily to costs
associated with workovers on the A-2 and A-9 wells on this property in the first
quarter of 1996. The Working Interest Owner advised the Trust that as a result
of the successful drilling of the B-5, B-8 and B-9 wells, its estimates of
proved reserves on this property have increased by approximately 12,000 barrels
of crude oil and condensate (3,000 barrels net to the Trust) and 9,600,000 Mcf
of natural gas (2,400,000 Mcf net to the Trust). The Working Interest Owner has
advised the Trust that some of the future income from production on the B-5,
B-8, and B-9 wells may be offset significantly by drilling expenses and Special
Cost Escrow deposits related to such wells. The Working Interest Owner has
advised the Trust that it expects the costs of drilling the B-5 and B-9 wells of
approximately $4.35 million ($1.0875 million net to the Trust) to affect Trust
expenses in the fourth quarter of 1996.
The Working Interest Owner on the East Cameron 371 property has advised the
Trust that in June 1996, it drilled an exploratory well on a non-Trust property
adjacent to the East Cameron 371 property. The Trust has an interest in this
well pursuant to a pooling agreement between the Working Interest Owner and
Columbia Gas Development Corporation, the owner of East Cameron 381, the
adjacent non-Trust property. The pooling agreement covers reserves located in a
reservoir underlying the East Cameron 371 Trust property and East Cameron 381.
The East Cameron 381 exploratory well was successfully drilled at an estimated
cost of $637,500 ($159,375 net to the Trust). Another well is scheduled to be
drilled on East Cameron 371 in the fourth quarter of 1996 at an estimated cost
of $757,500 ($189,375 net to the Trust). If the fourth quarter drilling is
successful, the Working Interest Owner plans to build a platform in 1997 or 1998
at an estimated cost of $9 million ($2.25 million net to the Trust). Production
on these two wells cannot begin until the platform is built.
NINE MONTHS ENDED SEPTEMBER 30, 1996 AND 1995
VOLUMES AND DOLLAR AMOUNTS DISCUSSED BELOW REPRESENT AMOUNTS RECORDED BY
THE WORKING INTEREST OWNERS UNLESS OTHERWISE SPECIFIED.
Ship Shoal 182/183 gas revenues increased from $353,661 in the first nine
months of 1995 to $576,296 in the first nine months of 1996, primarily due to
the increase in the average natural gas sales price from $1.81 per Mcf in the
first nine months of 1995 to $2.77 per Mcf in the same period of 1996. In
addition,
10
<PAGE>
there was an increase in gas volumes from 194,030 Mcf in the first nine months
of 1995 to 214,885 Mcf in the first nine months of 1996 due primarily to the
C-10 well being watered out and the C-4 well being sanded in throughout the
second quarter of 1995. A decrease in crude oil production from 194,620 barrels
in the first nine months of 1995 to 163,912 barrels in the first nine months of
1996 and an increase in the average crude oil price from $16.30 per barrel in
the first nine months of 1995 to $17.76 per barrel for the same period in 1996
resulted in a decrease in crude oil revenues from $3,172,152 in the first nine
months of 1995 to $2,911,581 in the first nine months of 1996. The decrease in
crude oil production was primarily due to a continued natural production decline
on this property. Operating expenses increased from $1,023,607 in the first nine
months of 1995 to $1,223,387 in the first nine months of 1996 due primarily to a
compressor repair in the second quarter of 1996. Capital expenditures increased
from $35,388 in the first nine months of 1995 to $3,479,913 for the same period
in 1996 due primarily to the drilling of the F-2 delineation gas well and the
B-11 and B-12 developmental oil wells in the first nine months of 1996.
Eugene Island 339 gas revenues increased from $858,710 in the first nine
months of 1995 to $1,019,645 in the first nine months of 1996 due primarily to
an increase in the average price received for natural gas from $1.75 per Mcf in
the first nine months of 1995 to $2.72 per Mcf for the same period in 1996. The
increase in the average price received was partially offset by a decrease in gas
volumes from 468,932 Mcf in the first nine months of 1995 to 373,974 Mcf in the
first nine months of 1996. The decrease in gas volumes was due primarily to the
shut down of a booster pumping station in the third quarter of 1996 and a
continued natural production decline on this property. Crude oil and condensate
revenues increased from $2,788,859 in the first nine months of 1995 to
$7,507,069 in the first nine months of 1996 due primarily to an increase in
volumes from 172,704 barrels in the first nine months of 1995 to 453,206 barrels
in the first nine months of 1996. The increase in 1996 volumes was primarily
attributable to volumes being understated in 1995 on the B-13 well. The B-13
well adjustment was made in the first quarter of 1996. In addition, there was an
increase in the average price received for crude oil and condensate from $16.15
per barrel in the first nine months of 1995 to $16.56 per barrel for the same
period in 1996. Operating expenses decreased from $1,187,171 in the first nine
months of 1995 to $843,710 in the first nine months of 1996 due primarily to a
reduction in environmental compliance costs in the first quarter of 1996 and a
service facilities credit on this property in the first and third quarters of
1996.
West Cameron 643 gas revenues increased from $705,252 in the first nine
months of 1995 to $6,931,088 in the first nine months of 1996 primnarily due to
an increase in gas volumes. Gas volumes increased from 437,940 Mcf in the first
nine months of 1995 to 2,780,518 Mcf for the same period in 1996 primarily due
to the successful B-5, B-8 and B-9 wells drilled on this property in the second
quarter of 1996 and successful workovers on the A-2 and A-9 wells in the first
quarter of 1996. In addition, there was an increase in the average price
received for natural gas from $1.61 per Mcf in the first nine months of 1995 to
$2.49 per Mcf in the first nine months of 1996. Operating expenses increased
from $245,362 in the first nine months of 1995 to $623,224 in the first nine
months of 1996 due primarily to expenses incurred in the third quarter of 1996
in connection with the workover on the A-10 well. Capital expenditures increased
from $603,188 in the first nine months of 1995 to $2,813,874 for the same period
in 1996 due primarily to costs associated with workovers on the A-2, A-6, A-9,
A-10, A-16 and B-3 wells on this property in the first quarter of 1996.
FUTURE NET REVENUES AND TERMINATION OF THE TRUST
Based on a reserve study provided to the Trust by DeGolyer and MacNaughton,
independent petroleum engineers, it was estimated that as of October 31, 1995
future net revenues attributable to the Trust's royalty interests approximated
$7.7 million. Such reserve study also indicates that approximately 70% of the
future net revenues from the Royalty Properties are expected to be received by
the Trust during the next 4 years. In addition, because the Trust will terminate
in the event estimated future net revenues fall below $2 million, it
11
<PAGE>
would be possible for the Trust to terminate even though some or all of the
Royalty Properties continued to have remaining productive lives. Upon
termination of the Trust, the Trustees will sell for cash all of the assets held
in the Trust estate and make a final distribution to Unit holders of any funds
remaining after all Trust liabilities have been satisfied. The estimates of
future net revenues discussed above are subject to large variances from year to
year and should not be construed as exact. There are numerous uncertainties
present in estimating future net revenues for the Royalty Properties. The
estimate may vary depending on changes in market prices for crude oil and
natural gas, the recoverable reserves, annual production and costs assumed by
DeGolyer and MacNaughton. In addition, future economic and operating conditions
as well as results of future drilling plans may cause significant changes in
such estimate. The discussion set forth above is qualified in its entirety by
reference to the Trust's 1995 Annual Report on Form 10-K. The Form 10-K is
available upon request from the Corporate Trustee.
SPECIAL COST ESCROW ACCOUNT
The Conveyance provides for reserving funds for estimated future "Special
Costs" of plugging and abandoning wells, dismantling platforms and other costs
of abandoning the Royalty Properties, as well as for the estimated amount of
future drilling projects and other capital expenditures on the Royalty
Properties. As provided in the Conveyance, the amount of funds to be reserved is
determined based on factors including estimates of aggregate future production
costs, aggregate future Special Costs, aggregate future net revenues and actual
current net proceeds. Deposits into this account reduce current distributions
and are placed in an escrow account and invested in short-term certificates of
deposit. Such account is herein referred to as the "Special Cost Escrow
Account." The Trust's share of interest generated from the Special Cost Escrow
Account serves to reduce the Trust's share of allocated production costs.
Special Cost Escrow funds will generally be utilized to pay Special Costs to the
extent there are not adequate current net proceeds to pay such costs. Special
Costs that have been paid are no longer included in the Special Cost Escrow
calculation. Deposits to the Special Cost Escrow Account will generally be made
when the balance in the Special Cost Escrow Account is less than 125% of future
Special Costs and there is a Net Revenues Shortfall (a calculation of the excess
of estimated future costs over estimated future net revenues pursuant to a
formula contained in the Conveyance). When there is not a Net Revenues
Shortfall, amounts in the Special Cost Escrow Account will generally be
released, to the extent that Special Costs have been incurred. Amounts in the
Special Cost Escrow Account generally will also be released when the balance in
such account exceeds 125% of future Special Costs. In the first nine months of
1995, a net deposit of approximately $95,300 was made by the Trust into the
Special Cost Escrow Account. The deposit was primarily a result of an increase
in the estimates of projected capital expenditures on the Royalty Properties. In
the first nine months of 1996, there was also a deposit of funds into the
Special Cost Escrow Account. The Trust's share of the funds deposited was
approximately $1,493,500. The deposit was primarily a result of an increase in
the current estimates of projected capital expenditures, production costs and
abandonment costs in connection with the Ship Shoal 182/183 drilling. As of
September 30, 1996, approximately $4,065,500 remained in the Special Cost Escrow
Account.
Capital expenditures and drilling programs by the Working Interest Owners,
such as those discussed under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" in this Form 10-Q, can have a
significant impact on the amount of deposits into the Special Cost Escrow
account. Such deposits can result in a significant reduction in royalty income
in the periods in which such deposits are made, including the possibility that
no royalty income would be received in such periods.
OVERVIEW OF PRODUCTION, PRICES AND NET PROCEEDS
The following schedule provides a summary of the volumes and weighted
average prices for crude oil and condensate and natural gas recorded by the
Working Interest Owners for the Royalty Properties, as well
12
<PAGE>
as the Working Interest Owners' calculations of the net proceeds and the
royalties paid to the Trust during the periods indicated. Net proceeds due to
the Trust are calculated for each three month period commencing on the first day
of February, May, August and November.
ROYALTY PROPERTIES
THREE MONTHS ENDED
SEPTEMBER 30,(1)
------------------------------
1996 1995
-------------- --------------
Crude oil and condensate (bbls)......... 145,021 147,290
Natural gas and gas products (Mcf)...... 2,166,953 432,740
Crude oil and condensate average price,
per bbl............................... $ 18.24 $ 16.38
Natural gas average price, per Mcf
(excluding gas products).............. $ 2.48 $ 1.66
Crude oil and condensate revenues....... $ 2,644,626 $ 2,412,616
Natural gas and gas products revenues... 5,375,933 730,243
Production expenses..................... (1,396,962) (908,295)
Capital expenditures.................... (2,483,332) (370,150)
Undistributed Net Loss (Income)(2)...... (308,949) 3,030
(Provision for) Refund of escrowed
special costs......................... (688,168) 7,500
-------------- --------------
NET PROCEEDS............................ 3,143,148 1,874,944
Royalty interest........................ x25% x25%
-------------- --------------
Partnership share....................... 785,787 468,736
Trust interest.......................... x99.99% x99.99%
-------------- --------------
Trust share............................. $ 785,708 $ 468,689
============== ==============
- ------------
(1) The amounts for the three months ended September 30, 1996 and 1995 represent
actual production for the periods May 1996 through July 1996 and May 1995
through July 1995, respectively.
(2) Undistributed net loss represents negative Net Proceeds generated during the
respective period. An undistributed net loss is carried forward and offset,
in future periods, by positive Net Proceeds earned by the related Working
Interest Owner(s). Undistributed net income represents positive Net
Proceeds, generated during the respective period, that were applied to an
existing loss carryforward. As of September 30, 1996, the loss carryforward
was $2,154,332 ($538,583 net to the Trust).
13
<PAGE>
ROYALTY PROPERTIES
NINE MONTHS ENDED
SEPTEMBER 30,(1)
------------------------------
1996 1995
-------------- --------------
Crude oil and condensate (bbls)......... 619,096 373,902
Natural gas and gas products (Mcf)...... 3,557,012 1,431,927
Crude oil and condensate average price,
per bbl............................... $ 16.88 $ 16.22
Natural gas average price, per Mcf
(excluding gas products).............. $ 2.53 $ 1.68
Crude oil and condensate revenues....... $ 10,452,702 $ 6,066,428
Natural gas and gas products revenues... 8,983,822 2,457,231
Production expenses..................... (3,807,924) (2,675,762)
Capital expenditures.................... (6,494,923) (700,763)
Undistributed Net Loss (Income)(2)...... (16,381) (329,126)
(Provision for) Refund of escrowed
special costs......................... (5,974,148) (381,356)
-------------- --------------
NET PROCEEDS............................ 3,143,148 4,436,652
Royalty interest........................ x25% x25%
-------------- --------------
Partnership share....................... 785,787 1,109,163
Trust interest.......................... x99.99% x99.99%
-------------- --------------
Trust share............................. $ 785,708 $ 1,109,052
============== ==============
- ------------
(1) The amounts for the nine months ended September 30, 1996 and 1995 represent
actual production for the periods November 1995 through July 1996 and
November 1994 through July 1995, respectively.
(2) Undistributed net loss represents negative Net Proceeds generated during the
respective period. An undistributed net loss is carried forward and offset,
in future periods, by positive Net Proceeds earned by the related Working
Interest Owner(s). Undistributed net income represents positive Net
Proceeds, generated during the respective period, that were applied to an
existing loss carryforward. As of September 30, 1996, the loss carryforward
was $2,154,332 ($538,583 net to the Trust).
14
<PAGE>
PART II -- OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(A) EXHIBITS
(Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference.)
<TABLE>
<CAPTION>
SEC FILE OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------- -------
<C> <C> <S> <C> <C>
4(a)* -- Trust Agreement dated as of January 1, 1983, among Tenneco 0-6910 4(a)
Offshore Company, Inc., Texas Commerce Bank National
Association, as corporate trustee, and Horace C. Bailey, Joseph
C. Broadus and F. Arnold Daum, as individual trustees (Exhibit
4(a) to Form 10-K for the year ended December 31, 1992 of TEL
Offshore Trust)
4(b)* -- Agreement of General Partnership of TEL Offshore Trust 0-6910 4(b)
Partnership between Tenneco Oil Company and the TEL Offshore
Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for
year ended December 31, 1992 of TEL Offshore Trust)
4(c)* -- Conveyance of Overriding Royalty Interests from Exploration I 0-6910 4(c)
to the Partnership (Exhibit 4(c) to Form 10-K for year ended
December 31, 1992 of TEL Offshore Trust)
4(d)* -- Amendments to TEL Offshore Trust Trust Agreement, dated 0-6910 4(d)
December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended
December 31, 1992 of TEL Offshore Trust)
4(e)* -- Amendment to the Agreement of General Partnership of TEL 0-6910 4(e)
Offshore Trust Partnership, effective as of January 1, 1983
(Exhibit 4(e) to Form 10-K for year ended December 31, 1992 of
TEL Offshore Trust)
10(a)* -- Purchase Agreement, dated as of December 7, 1984 by and between 0-6910 10(a)
Tenneco Oil Company and Tenneco Offshore II Company (Exhibit
10(a) to Form 10-K for year ended December 31, 1992, of TEL
Offshore Trust)
10(b)* -- Consent Agreement, dated November 16, 1988, between TEL 0-6910 10(b)
Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form
10-K for year ended December 31, 1988 of TEL Offshore Trust)
10(c)* -- Assignment and Assumption Agreement, dated November 17, 1988, 0-6910 10(c)
between Tenneco Oil Company and TOC-Gulf of Mexico Inc.
(Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of
TEL Offshore Trust)
10(d)* -- Gas Purchase and Sales Agreement Effective September 1, 1993 0-6910 10(d)
between Tennessee Gas Pipeline Company and Chevron U.S.A.
Production Company (Exhibit 10(d) to Form 10-K for year ended
December 31, 1993 of TEL Offshore Trust)
27(a) -- Financial Data Schedule
</TABLE>
(B) REPORTS ON FORM 8-K
On October 28, 1996, the Trust filed a report on Form 8-K with the
Securities and Exchange Commission. The report related to the delisting of the
Trust Units from the Nasdaq SmallCap Market, as discussed above under
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
15
<PAGE>
SIGNATURES
Pursuant to the requirements 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.
TEL OFFSHORE TRUST
By: Texas Commerce Bank National
Association, Corporate Trustee
By: /s/ PETE FOSTER
PETE FOSTER
SENIOR VICE PRESIDENT
AND TRUST OFFICER
Date: November 5, 1996
The Registrant, TEL 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.
16
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHDULE CONTIANS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE STATEMENT
OF ASSETS, LIABILITIES AND TRUST CORPUS AS OF SEP-30-1996 AND THE STATEMENT OF
DISTRIBUTABLE INCOME FOR THE NINE MONTHS ENDED SEP-30-1996 AND IS QUALIFIED IN
ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> SEP-30-1996
<CASH> 1,582,968
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,582,968
<PP&E> 28,267,655
<DEPRECIATION> 27,329,066
<TOTAL-ASSETS> 2,521,557
<CURRENT-LIABILITIES> 590,417
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 938,589
<TOTAL-LIABILITY-AND-EQUITY> 2,521,557
<SALES> 0
<TOTAL-REVENUES> 807,726
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 217,309
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 590,417
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 590,417
<EPS-PRIMARY> .124
<EPS-DILUTED> .124
</TABLE>
