================================================================================
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 JUNE 30, 1997
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM
_________________ TO _________________
COMMISSION FILE NUMBER 1-7884
MESA ROYALTY TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 74-6284806
(STATE OF INCORPORATION (I.R.S. EMPLOYER
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)
(713) 216-6369
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
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 August 8, 1997 -- 1,863,590 Units of Beneficial Interest in Mesa
Royalty Trust.
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<PAGE>
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MESA ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------- ----------------------------
1997 1996 1997 1996
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Royalty income....................... $ 1,648,915 $ 2,303,749 $ 5,511,830 $ 4,258,312
Interest income...................... 15,915 28,087 49,678 50,240
General and administrative expense... (12,190) (13,145) (11,565) (23,230)
------------- ------------- ------------- -------------
Distributable income............ $ 1,652,640 $ 2,318,691 $ 5,549,943 $ 4,285,322
============= ============= ============= =============
Distributable income per unit... $ .8868 $ 1.2442 $ 2.9780 $ 2.2995
============= ============= ============= =============
</TABLE>
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
JUNE 30, DECEMBER 31,
1997 1996
------------ ------------
(UNAUDITED)
ASSETS
Cash and short-term investments...... $ 1,636,725 $ 1,542,261
Interest receivable.................. 15,915 19,137
Net overriding royalty interest in
oil and gas properties............. 42,498,034 42,498,034
Accumulated amortization............. (26,101,548) (25,083,497)
------------ ------------
$ 18,049,126 $ 18,975,935
============ ============
LIABILITIES AND TRUST CORPUS
Distributions payable................ $ 1,652,640 $ 1,561,398
Trust corpus (1,863,590 units of
beneficial interest
authorized and outstanding)........ 16,396,486 17,414,537
------------ ------------
$ 18,049,126 $ 18,975,935
============ ============
(The accompanying notes are an integral part of these financial statements.)
1
<PAGE>
MESA ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------ ------------------------------
1997 1996 1997 1996
-------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Trust corpus, beginning of period.... $ 16,876,898 $ 19,031,596 $ 17,414,537 $ 19,626,839
Distributable income............ 1,652,640 2,318,691 5,549,943 4,285,322
Distributions to unitholders.... (1,652,640) (2,318,691) (5,549,943) (4,285,322)
Amortization of net overriding
royalty interest............. (480,412) (591,918) (1,018,051) (1,187,161)
-------------- -------------- -------------- --------------
Trust corpus, end of period.......... $ 16,396,486 $ 18,439,678 $ 16,396,486 $ 18,439,678
============== ============== ============== ==============
</TABLE>
(The accompanying notes are an integral part of these financial statements.)
2
<PAGE>
MESA ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 -- TRUST ORGANIZATION
The Mesa Royalty Trust (the "Trust") was created on November 1, 1979 when
Mesa Petroleum Co. conveyed to the Trust a 90% net profits overriding royalty
interest (the "Royalty") in certain producing oil and gas properties located in
the Hugoton field of Kansas, the San Juan Basin field of New Mexico and Colorado
and the Yellow Creek field of Wyoming (collectively, the "Royalty Properties").
Mesa Petroleum Co. was the predecessor to Mesa Limited Partnership ("MLP"), the
predecessor to MESA Inc. On April 30, 1991, MLP sold its interests in the
Royalty Properties located in the San Juan Basin field to Conoco Inc.
("Conoco"), a wholly-owned subsidiary of E. I. duPont de Nemours & Company.
Conoco sold the portion of its interests in the San Juan Basin Royalty
Properties located in Colorado to MarkWest Energy Partners, Ltd. (effective
January 1, 1993) and Red Willow Production Company (effective April 1, 1992). On
October 26, 1994, MarkWest Energy Partners, Ltd. sold substantially all of its
interest in the Colorado San Juan Basin Royalty Properties to Amoco Production
Company ("Amoco"), a subsidiary of Amoco Corp. Until August 7, 1997, MESA Inc.
operated the Hugoton Royalty Properties through Mesa Operating Co. ("Mesa"), a
subsidiary of MESA Inc. On August 7, 1997, MESA Inc. merged with and into
Pioneer Natural Resources Company ("Pioneer") and Parker & Parsley Petroleum
Company merged with and into Pioneer Natural Resources USA, Inc. (formerly Mesa
Operating Co.), a wholly owned subsidiary of Pioneer ("PNR")(collectively, the
mergers are referred to herein as the "Merger"). Subsequent to the Merger, the
Hugoton Royalty Properties are operated by PNR. The San Juan Basin Royalty
Properties located in New Mexico are operated by Conoco. The San Juan Basin
Royalty Properties located in Colorado are operated by Amoco. As used in this
report, PNR refers to the operator of the Hugoton Royalty Properties, Conoco
refers to the operator of the San Juan Basin Royalty Properties, other than the
portion of such properties located in Colorado, and Amoco refers to the operator
of the Colorado San Juan Basin Royalty Properties unless otherwise indicated.
The terms "working interest owner" and "working interest owners" generally refer
to the operators of the Royalty Properties as described above, unless the
context in which such terms are used indicates otherwise.
NOTE 2 -- BASIS OF PRESENTATION
The accompanying unaudited financial information has been prepared by Texas
Commerce Bank National Association ("Trustee") in accordance with the
instructions to Form 10-Q, and the Trustee believes such information includes
all the disclosures necessary to make the information presented not misleading.
The information furnished reflects all adjustments which are, in the opinion of
the Trustee, 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 1996 Annual
Report on Form 10-K.
The Mesa Royalty Trust Indenture was amended in 1985, the effect of which
was an overall reduction of approximately 88.56% in the size of the Trust;
therefore, the Trust is now entitled each month to receive 90% of 11.44% of the
net proceeds for the preceding month. Generally, net proceeds means the excess
of the amounts received by the working interest owners from sales of oil and gas
from the Royalty Properties over operating and capital costs incurred.
3
<PAGE>
The financial statements of the Trust are prepared on the following basis:
(a) Royalty income recorded for a month is the amount computed and
paid by the working interest owners to the Trustee for such month rather
than either the value of a portion of the oil and gas produced by the
working interest owners for such month or the amount subsequently
determined to be the Trust's proportionate share of the net proceeds for
such month;
(b) Interest income, interest receivable, and distributions payable
to unitholders include interest to be earned from the balance sheet date
through the next distribution date;
(c) Trust general and administrative expenses, net of reimbursements,
are recorded in the month they accrue;
(d) Amortization of the net overriding royalty interests, which is
calculated on a unit-of-production basis, is charged directly to trust
corpus since such amount does not affect distributable income; and
(e) Distributions payable are determined on a monthly basis and are
payable to unitholders of record as of the last business day of each month
or such other day as the Trustee determines is required to comply with
legal or stock exchange requirements. However, cash distributions are made
quarterly in January, April, July and October, and include interest earned
from the monthly record dates to the date of distribution.
This basis for reporting royalty income is thought to be the most
meaningful because distributions to the unitholders for a month are based on net
cash receipts for such month. However, these statements differ from financial
statements prepared in accordance with generally accepted accounting principles
in several respects. Under such principles, royalty income for a month would be
based on net proceeds for such month without regard to when calculated or
received and interest income would include interest earned during the period
covered by the financial statements and would exclude interest from the period
end to the date of distribution.
4
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
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, including without
limitation the statements under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" 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 and in the Trust's Form 10-K, 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.
5
<PAGE>
SUMMARY OF ROYALTY INCOME AND AVERAGE PRICES
(UNAUDITED)
Royalty income is computed after deducting the Trust's proportionate share
of capital costs, operating costs and interest on any cost carryforward from the
Trust's proportionate share of "Gross Proceeds," as defined in the Royalty
conveyance. The following unaudited summary illustrates the net effect of the
components of the actual Royalty computation for the periods indicated.
<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30,
-----------------------------------------------------------
1997 1996
---------------------------- ----------------------------
OIL, OIL,
CONDENSATE CONDENSATE
NATURAL AND NATURAL NATURAL AND NATURAL
GAS GAS LIQUIDS GAS GAS LIQUIDS
------------- ------------ ------------- ------------
<S> <C> <C> <C> <C>
The Trust's proportionate share of
Gross Proceeds(1).................. $ 1,991,448 $ 621,214 $ 2,495,294 $ 712,930
Less the Trust's proportionate share
of:
Capital costs recovered(2)...... (72,594) -- (48,519) --
Operating costs................. (843,368) (38,938) (802,203) (44,906)
Interest on cost carryforward... (8,847) -- (8,847) --
------------- ------------ ------------- ------------
Royalty income....................... 1,066,639 582,276 $ 1,635,725 $ 668,024
============= ============ ============= ============
Average sales price.................. $ 1.77 $ 13.89 $ 2.09 $ 13.22
============= ============ ============= ============
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 602,621 41,935 781,743 50,519
============= ============ ============= ============
</TABLE>
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
-----------------------------------------------------------
1997 1996
---------------------------- ----------------------------
OIL, OIL,
CONDENSATE CONDENSATE
NATURAL AND NATURAL NATURAL AND NATURAL
GAS GAS LIQUIDS GAS GAS LIQUIDS
------------- ------------ ------------- ------------
<S> <C> <C> <C> <C>
The Trust's proportionate share of
Gross Proceeds(1).................. $ 6,032,327 $ 1,576,696 $ 4,692,463 $ 1,391,590
Less the Trust's proportionate share
of:
Capital costs recovered(2)...... (141,027) -- (152,938) --
Operating costs................. (1,858,659) (79,813) (1,572,415) (82,694)
Interest on cost carryforward... (17,694) -- (17,694) --
------------- ------------ ------------- ------------
Royalty income....................... $ 4,014,947 $ 1,496,883 $ 2,949,416 $ 1,308,896
============= ============ ============= ============
Average sales price.................. $ 2.53 $ 17.22 $ 1.89 $ 12.59
============= ============ ============= ============
(Mcf) (Bbls) (Mcf) (Bbls)
Net production volumes attributable
to the Royalty..................... 1,581,289 86,921 1,559,315 104,000
============= ============ ============= ============
</TABLE>
- ------------
(1) Gross Proceeds attributable to natural gas liquids for the Hugoton and San
Juan Basin Royalty Properties are net of a volumetric in-kind processing fee
retained by PNR and Conoco, respectively.
(2) Capital costs recovered represents capital costs incurred during the current
or prior periods to the extent that such costs have been recovered by the
working interest owners from current period Gross Proceeds. Cost
carryforward represents capital costs incurred during the current or prior
periods which will be recovered from future period Gross Proceeds. The cost
carryforward resulting from the Fruitland Coal drilling program was $455,725
and $496,008 at June 30, 1997 and June 30, 1996, respectively. The cost
carryforward at June 30, 1997 and June 30, 1996 relate solely to the San
Juan Basin Colorado properties.
6
<PAGE>
THREE MONTHS ENDED JUNE 30, 1997 AND 1996
The distributable income of the Trust includes the royalty income received
from the working interest owners during such period, plus interest income earned
to the date of distribution. Trust administration expenses are deducted in the
computation of distributable income. Distributable income for the quarter ended
June 30, 1997 was $1,652,640, representing $.8868 per unit, compared to
$2,318,691, representing $1.2442 per unit, for the quarter ended June 30, 1996.
Based on 1,863,590 units outstanding for the quarters ended June 30, 1997 and
1996, respectively, the per unit distributions were as follows:
1997 1996
--------- ---------
April................................ $ .3958 $ .4488
May.................................. .2219 .4350
June................................. .2691 .3604
--------- ---------
$ .8868 $ 1.2442
========= =========
HUGOTON FIELD
PNR has advised the Trust that since June 1, 1995 natural gas produced from
the Hugoton field has generally been sold under short-term contracts at market
clearing prices to multiple purchasers including Western Resources, Inc.
("WRI"), Westar Gas Marketing, Inc., Missouri Gas Energy, Amoco and Noram Energy
Services, Inc. PNR expects to continue to market gas production from the Hugoton
field under short-term and multi-month contracts. Overall market prices received
for natural gas from the Hugoton Royalty Properties were lower in the second
quarter of 1997 compared to the second quarter of 1996.
In June 1994, PNR entered into a Gas Transportation Agreement with WRI
("Gas Transportation Agreement") for a primary term of five years commencing
June 1, 1995 and ending June 1, 2000, but which may be continued in effect
year-to-year thereafter. Pursuant to the Gas Transportation Agreement, WRI has
agreed to compress and transport up to 160 MMcf per day of gas and redeliver
such gas to PNR at the inlet of PNR's Satanta Plant. PNR has agreed to pay WRI a
fee of $0.06 per Mcf escalating 4% annually as of June 1, 1996.
Royalty income attributable to the Hugoton Royalty decreased to $1,059,859
in the second quarter of 1997, as compared to $1,949,736 in the second quarter
of 1996 primarily due to increased 1996 production from compression added in
1995 in the Hugoton field. Production in 1996 was higher because of this added
compression and is now declining naturally. The average price received in the
second quarter of 1997 for natural gas sold from the Hugoton field was $1.77 per
Mcf, compared to $2.36 per Mcf during the same period in 1996. In addition, net
production attributable to the Hugoton Royalty decreased to 347,723 Mcf of
natural gas and 32,086 barrels of natural gas liquids in the second quarter of
1997 compared to 604,465 Mcf of natural gas and 40,092 barrels of natural gas
liquids in the second quarter of 1996. The decrease in natural gas production
was partially attributable to higher than normal rates in 1996 resulting from
the added compression.
Allowable rates of production in the Hugoton field are set by the Kansas
Corporation Commission (the "KCC") based on the level of market demand. The
KCC has set the Hugoton field allowable for the period April 1, 1997 through
September 30, 1997, at 223 billion cubic feet of gas, compared with 238 billion
cubic feet of gas during the same period last year.
On August 7, 1997, MESA Inc. and Parker & Parsley Petroleum Company merged
to create Pioneer Natural Resources Company, the third largest independent oil
and gas exploration and production company in the United States. Pioneer has
advised the Trust that this merger should have
7
<PAGE>
no significant effects on the Trust, although the precise nature of any effects
cannot be predicted or quantified at this time.
SAN JUAN BASIN
Royalty income from the San Juan Basin Royalty Properties is calculated and
paid to the Trust on a state-by-state basis. The Royalty income from the San
Juan Basin Royalty Properties located in the state of New Mexico was $589,056
during the second quarter of 1997 as compared with $354,013 in the second
quarter of 1996. No royalty income was received from the San Juan Basin Royalty
Properties located in Colorado for the second quarter of 1997 or 1996, as costs
associated with the Fruitland Coal drilling on such properties have not been
fully recovered. Net production attributable to the San Juan Basin Royalty was
254,898 Mcf of natural gas and 9,849 barrels of natural gas liquids in the
second quarter of 1997 as compared to 177,278 Mcf of natural gas and 10,427
barrels of natural gas liquids in the second quarter of 1996. The average price
received in the second quarter of 1997 for natural gas sold from the San Juan
Basin was $1.77 per Mcf, compared to $1.18 per Mcf during the same period in
1996.
The Trust's interest in the San Juan Basin was conveyed from PNR's working
interest in 31,328 net producing acres in northwestern New Mexico and
southwestern Colorado. The San Juan Basin New Mexico reserves represent
approximately 35% of the Trust's reserves. PNR completed the sale of its
underlying interest in the San Juan Basin Royalty Properties to Conoco on April
30, 1991. Conoco subsequently sold its underlying interest in the Colorado
portion of the San Juan Basin Royalty Properties to MarkWest Energy Partners,
Ltd. (effective January 1, 1993) and Red Willow Production Company (effective
April 1, 1992). On October 26, 1994, MarkWest Energy Partners, Ltd. sold
substantially all of its interest in the Colorado San Juan Basin Royalty
Properties to Amoco. The San Juan Basin Royalty Properties located in Colorado
account for less than 5% of the Trust's reserves.
SIX MONTHS ENDED JUNE 30, 1997 AND 1996
Distributable income increased to $5,511,830 for the six months ended June
30, 1997 from $4,285,322 for the same period in 1996.
HUGOTON FIELD
Royalty income attributable to the Hugoton Royalty Properties decreased to
$3,529,988 for the six months ended June 30, 1997 from $3,556,325 for the same
period in 1996 primarily due to lower natural gas sales volumes sold at higher
prices and lower NGL sales volumes offset by higher prices from the Hugoton
Royalty Properties. The average price received in the first six months of 1997
for natural gas sold from the Hugoton field was $2.66 per Mcf, compared to $2.09
per Mcf during the same period in 1996.
SAN JUAN BASIN
Royalty income attributable to the New Mexico San Juan Basin Royalty
Properties increased to $1,981,842 for the first six months of 1997 compared to
$701,987 in the first six months of 1996 primarily as a result of increased
natural gas prices. The average price received in the first six months of 1997
for natural gas sold from the San Juan Basin was $2.38 per Mcf, compared to
$1.24 per Mcf during the same period in 1996. No royalty income was received
from San Juan Basin Royalty Properties located in Colorado for the six months
ended June 30, 1997 and 1996, as costs associated with Fruitland Coal drilling
on such properties have not been fully recovered.
The gas that is currently being produced from the San Juan Basin Royalty
Properties is being sold primarily on the spot market. Conoco has advised the
Trust that it will also consider selling some of the gas produced from these
wells pursuant to longer term contracts at spot market prices.
8
<PAGE>
No distributions related to the Colorado portion of the San Juan Basin
Royalty have been made since 1990, as the costs of the Fruitland Coal drilling
in Colorado have not yet been recovered. The San Juan Basin development drilling
program has no effect on Royalty income or distributions relating to the Hugoton
Royalty.
Conoco has informed the Trust that it believes the production from the
Fruitland Coal formation will generally qualify for the tax credits provided
under Section 29 of the Internal Revenue Code of 1986, as amended. Thus,
unitholders are potentially eligible to claim their share of the tax credit
attributable to this qualifying production. Each unitholder should consult his
tax advisor regarding the limitations and requirements for claiming this tax
credit.
9
<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> <S> <C> <C>
4(a) *Mesa Royalty Trust Indenture between Mesa Petroleum Co. and Texas
Commerce Bank National Association, as Trustee, dated November 1,
1979.................................................................... 2-65217 1(a)
4(b) *Overriding Royalty Conveyance between Mesa Petroleum Co. and Texas
Commerce Bank, as Trustee, dated November 1, 1979....................... 2-65217 1(b)
4(c) *First Amendment to the Mesa Royalty Trust Indenture dated as of March
14, 1985 (Exhibit 4(c) to Form 10-K for year ended December 31, 1984 of
Mesa Royalty Trust)..................................................... 1-7884 4(c)
4(d) *Form of Assignment of Overriding Royalty Interest, effective April 1,
1985, from Texas Commerce Bank National Association, as Trustee, to MTR
Holding Co. (Exhibit 4(d) to Form 10-K for year ended December 31, 1984
of Mesa Royalty Trust).................................................. 1-7884 4(d)
4(e) *Purchase and Sale Agreement, dated March 25, 1991, by and among Mesa
Limited Partnership, Mesa Operating Limited Partnership and Conoco, as
amended on April 30, 1991 (Exhibit 4(e) to Form 10-K for year ended
December 31, 1991 of Mesa Royalty Trust)................................ 1-7884 4(e)
27 Financial Data Schedule
</TABLE>
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust during the second quarter of 1997.
10
<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.
MESA ROYALTY TRUST
TEXAS COMMERCE BANK
By NATIONAL ASSOCIATION
TRUSTEE
By /s/ PETE FOSTER
PETE FOSTER
SENIOR VICE PRESIDENT & TRUST
OFFICER
Date: August 13, 1997
The Registrant, Mesa Royalty Trust, has no principal executive officer,
principal financial officer, board of directors or persons performing similar
functions. Accordingly, no additional signatures are available and none have
been provided.
11
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM MESA ROYALTY
TRUST 1997 SECOND QUARTER REPORT AND FORM 10-Q AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH 1997 SECOND QUARTER REPORT AND FORM 10-Q.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1997
<CASH> 0
<SECURITIES> 1,636,725
<RECEIVABLES> 15,915
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,652,640
<PP&E> 42,498,034
<DEPRECIATION> 26,101,548
<TOTAL-ASSETS> 18,049,126
<CURRENT-LIABILITIES> 1,652,640
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 16,396,486
<TOTAL-LIABILITY-AND-EQUITY> 18,049,126
<SALES> 5,511,830
<TOTAL-REVENUES> 5,568,521
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 18,578
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 5,549,943
<INCOME-TAX> 0
<INCOME-CONTINUING> 5,549,943
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 5,549,943
<EPS-PRIMARY> 2.978
<EPS-DILUTED> 2.978
</TABLE>
