CROSS TIMBERS OIL CO, S-1/A, 1999-11-12

CROSS TIMBERS OIL CO
S-1/A, 1999-11-12
CRUDE PETROLEUM & NATURAL GAS

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<PAGE>

As filed with the Securities and Exchange Commission on November 12, 1999.

Registration No. 333-85777
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

--------------

AMENDMENT NO. 1 TO
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
on
Form S-1 -------------- Form S-3

TEXAS PERMIAN TRUST CROSS TIMBERS OIL COMPANY
(Exact name of co-registrant as (Exact name of co-registrant as
specified in its charter) specified in its charter)

A Delaware business trust to be formed Delaware
(State or other jurisdiction of (State or other jurisdiction of
incorporation or organization) incorporation or organization)

1311 75-2347769
(Primary standard industrial (I.R.S. Employer Identification No.)
classification code number)
810 Houston Street, Suite 2000
Fort Worth, Texas 76102
75-6550482 (817) 870-2800
(I.R.S. Employer Identification No.) (Address, including zip code, and
telephone
number, including area code, of
810 Houston Street, Suite 2000 registrant's principal executive
Fort Worth, Texas 76102 offices)
(817) 870-2800
(Address, including zip code, and Bob R. Simpson
telephone 810 Houston Street, Suite 2000
number, including area code, of Fort Worth, Texas 76102
registrant's principal executive (817) 870-2800
offices) (Name, address, including zip code, and
telephone number, including area code,
Frank G. McDonald, Esq. of agent for service)
810 Houston Street, Suite 2000
Fort Worth, Texas 76102
(817) 870-2800
(Name, address, including zip code, and
telephone number, including area code,
of agent for service)

--------------
Copies to:
F. Richard Bernasek, Esq. James M. Prince, Esq.
Kelly, Hart & Hallman, P.C. Andrews & Kurth L.L.P.
201 Main Street, Suite 2500 600 Travis, Suite 4200
Fort Worth, Texas 76102 Houston, Texas 77002
(817) 332-2500 (713) 220-4300
--------------
Approximate date of commencement of proposed sale to the public: As soon as
practicable after this Registration Statement becomes effective.
If the only securities being registered on this form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box. [_]
If any of the securities being registered on this Form are to be offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or
interest reinvestment plans, check the following box. [_]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following
box and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [_]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [_]
--------------
CALCULATION OF REGISTRATION FEE
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

<TABLE>
<CAPTION>
Title of Each Class of Proposed Maximum Amount of
Securities to Be Registered Aggregate Offering Price(1) Registration Fee (2)
- -------------------------------------------------------------------------------
<S> <C> <C>
Units of Beneficial Interest
in Texas Permian Trust...... $126,500,000 $35,167
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
</TABLE>
(1) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457(o).

(2) Previously paid
The Registrant hereby amends this Registration Statement on such date or
dates as may be necessary to delay its effective date until the Registrant
shall file a further amendment which specifically states that this Registration
Statement shall thereafter become effective in accordance with Section 8(a) of
the Securities Act of 1933 or until this Registration Statement shall become
effective on such date as the Commission, acting pursuant to said Section 8(a),
may determine.

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>

++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
+The information in this preliminary prospectus is not complete and may be +
+changed. These securities may not be sold until the registration statement +
+filed with the Securities and Exchange Commission is effective. This +
+preliminary prospectus is not an offer to sell nor does it seek an offer to +
+buy these securities in any jurisdiction where the offer or sale is not +
+permitted. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++

Subject to Completion. Dated November 12, 1999.

Texas Permian Trust

10,000,000 Trust Units

-----------

This is an initial public offering of units of beneficial interest in the
Texas Permian Trust. Cross Timbers Oil Company has formed the trust and is
offering all of the trust units to be sold in this offering, and Cross Timbers
will receive all proceeds from the offering. The trust will not receive any
proceeds from the offering.

There is currently no public market for the trust units. Cross Timbers
expects that the public offering price will be between $ and $ per trust
unit. Cross Timbers will apply to list the trust units on the New York Stock
Exchange under the symbol "TPT".

The Trust Units. Trust units are units of beneficial ownership of the trust
and represent undivided interests in the trust. They do not represent any
interest in Cross Timbers.

The Trust. The trust owns net profits interests in oil and natural gas
producing properties primarily located in the Permian Basin of Texas and New
Mexico. The net profits interests entitle the trust to receive 80% of the
net proceeds from the sale of production from these oil and natural gas
properties owned by Cross Timbers.

The Trust Unitholders. As a trust unitholder, you will receive monthly
distributions of cash that the trust receives for its net profits interests
from the sale of oil and natural gas produced from the underlying
properties.

See "Risk Factors" beginning on page 11 to read about certain information you
should consider before purchasing trust units.

-----------

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY BODY
HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ACCURACY OR
ADEQUACY OF THIS PROSPECTUS. aNY REPRESENTATION TO THE CONTRARY IS A CRIMINAL
OFFENSE.

-----------

<TABLE>
<CAPTION>
Per
Trust
Unit Total
----- ------
<S> <C> <C>
Initial public offering price..................................... $ $
Underwriting discount............................................. $ $
Proceeds, before expenses, to Cross Timbers....................... $ $
</TABLE>

The underwriters may, under certain circumstances, purchase from Cross
Timbers up to an additional 1,500,000 trust units at the initial public
offering price less the underwriting discount.

-----------

The underwriters expect to deliver the trust units against payment in New
York, New York on , 1999.

Goldman, Sachs & Co.
Lehman Brothers
Banc of America Securities LLC
Dain Rauscher Wessels
a division of Dain Rauscher Incorporated
Salomon Smith Barney

-----------

Prospectus dated , 1999.
<PAGE>

MAP
[Map showing general location of the underlying properties appears here]

2
<PAGE>

PROSPECTUS SUMMARY

This summary may not contain all of the information that is important to
you. To understand this offering fully, you should read the entire prospectus
carefully, including the risk factors and the financial statements and notes to
those statements. You will find definitions for terms relating to the oil and
natural gas business in "Glossary of Certain Oil and Natural Gas Terms." Miller
and Lents, Ltd., an independent engineering firm, provided the estimates of
proved oil and natural gas reserves at June 30, 1999 included in this
prospectus. These estimates are contained in summaries by Miller and Lents of
the reserve reports as of June 30, 1999, for the underlying properties
described below and for the net profits interests in the underlying properties
held by the trust. These summaries are located at the back of this prospectus
as Exhibits A and B and are referred to in the prospectus as the reserve
report.

Texas Permian Trust

Texas Permian Trust was formed as of September 1999 by Cross Timbers Oil
Company. Cross Timbers transferred to the trust net profits interests in oil
and natural gas producing properties located primarily in Texas. We refer to
Cross Timbers' interests in these properties as the underlying properties.

The net profits interests entitle the trust to receive 80% of net proceeds
from the sale of oil and natural gas from the underlying properties. Each month
Cross Timbers will collect cash received from the sale of production and deduct
property and production taxes, development and production costs and overhead.

Net proceeds payable to the trust depend upon production quantities, sales
prices of oil and natural gas and costs to develop and produce the oil and
natural gas. If at any time costs should exceed gross proceeds, neither the
trust nor the trust unitholders would be liable for the excess costs. However,
the trust would not receive any net proceeds until future net proceeds exceed
the total of those excess costs, plus interest at the prime rate.

Cross Timbers calculates the net proceeds from the underlying properties
separately for Texas and New Mexico. Any excess costs for underlying properties
in one state will not reduce net proceeds calculated for properties in the
other state.

Cross Timbers does not expect future production costs for the underlying
properties to change significantly as compared to recent historical costs. It
expects the level of development costs to decline significantly from recent
historical amounts.

The trust will make monthly distributions of substantially all of its income
to holders of its trust units. On your federal income tax returns, you will be
required to include your proportionate share of trust income. In addition, you
will be entitled to claim deductions for depletion relating to production from
the underlying properties and for your share of trust administrative expense.
The deductions will permit you to defer taxes on a significant portion of the
income you receive from the trust.

Cross Timbers' Ownership Interests in the Trust and the Underlying Properties

Cross Timbers' interests in the underlying properties are predominantly
"working interests," which require it to bear the costs of exploration,
production and development.

3
<PAGE>

Cross Timbers' retained interest in the underlying properties entitles it to
retain all proceeds from production after deducting the 80% of net proceeds
payable to the trust. Effectively, this entitles Cross Timbers to 20% of the
net proceeds from production. Cross Timbers believes that a 20% ownership
interest will provide incentive to operate and develop the underlying
properties in an efficient and cost-effective manner. Cross Timbers is under no
obligation to continue to own the underlying properties, but currently intends
to do so.

Cross Timbers may, at any time prior to November 30, 1999, transfer
additional net profits interests to the trust in exchange for additional trust
units. Any additional net profits interests transferred must relate to
additional working interests acquired by Cross Timbers in the same oil and
natural gas properties as the underlying properties. The number of trust units
issued will be based on the amount of discounted future net revenues from
proved reserves added to the trust's net profits interests as the result of the
transfer. Cross Timbers could acquire a maximum of 3,000,000 additional trust
units in exchange for additional net profits interests.

The following chart shows the relationship of Cross Timbers, the trust and
the public trust unitholders after this offering, assuming no exercise of the
underwriters' over-allotment option and no issuance of additional trust units.
Cross Timbers in the future may sell some or all of its retained trust units or
its interests in the underlying properties.

[FLOW CHART SHOWING THE RELATIONSHIP AMONG CROSS TIMBERS, THE TRUST AND THE
PUBLIC TRUST UNITHOLDERS APPEARS HERE]

Management of Cross Timbers has been involved in the formation of four
publicly traded royalty trusts. The trusts are the Hugoton Royalty Trust formed
in 1998, the Cross Timbers Royalty Trust formed in 1991 and the Permian Basin
Royalty Trust and the San Juan Basin Royalty Trust both formed in 1980. Cross
Timbers may form additional trusts with other properties. It also may in the
future dispose of some or all of the trust units of the Texas Permian Trust or
any of the other trusts. See "Risk Factors--Cross Timbers' Disposal of Its
Remaining Trust Units May Temporarily Reduce the Trust Unit Market Price."

The Underlying Properties

The underlying properties are primarily located in the Permian Basin, one of
the best known and most prolific oil and natural gas producing areas in the
United States. As of June 30, 1999, proved reserves of the underlying
properties were estimated at approximately 55 million BOE in the reserve

4
<PAGE>

report. Approximately 90% of the proved reserves are located in West Texas, and
10% are located in eastern New Mexico. The underlying properties include
substantially all of Cross Timbers' working interests in the Permian Basin
other than those properties that are subject to net profits interests
transferred to another trust in 1991. There are four major oil producing areas
and one major natural gas producing area in the underlying properties. These
areas are characterized by wells with low rates of annual decline in production
and low production costs. Wells in these areas have been producing for many
years, in some cases since the 1920s. Reserve estimates for properties with
long production histories are generally more reliable than estimates for
properties with short histories.

Producing Area

The underlying properties are predominantly oil producing properties located
in the Permian Basin of West Texas and eastern New Mexico. Most of the oil
production associated with these properties is in Andrews, Gaines, Terry and
Yoakum counties, four contiguous Texas counties on the New Mexico border.
Additional significant properties are located directly across the border in Lea
County, New Mexico. Most of the natural gas production is in Crockett County,
Texas, in the southwest portion of the Permian Basin.

The Permian Basin covers over 100,000 square miles. Oil was first discovered
there in 1921. More than 4,000 oil deposits and about 1,000 natural gas
deposits have been discovered there with total cumulative production of 39
billion BOE, making it one of the largest oil producing regions in the U.S.

Most of the large oil reservoirs in the Permian Basin are being
waterflooded, a secondary recovery technique that introduces water into the
producing reservoir to help push more oil from the reservoir. The Basin has
also been a major area for other advanced discovery and recovery techniques
such as 3-D seismic, horizontal drilling and carbon dioxide flooding. The
underlying properties in the Permian Basin generally produce from depths from
5,000 feet to 11,000 feet. The geology of the Basin is complex, with many
layered reservoirs. Some of the more prolific producing formations in the Basin
include the Glorieta, Clearfork, Pennsylvania, Wolfcamp, Devonian and San
Andres.

Long Life of Properties

The average productive life of proved reserves of the underlying properties
is relatively long compared to the average life of domestic proved reserves.
The productive lives of producing oil and natural gas properties are often
compared using their reserve-to-production index. This index is calculated by
dividing total estimated proved reserves of the property by annual production
for the prior 12 months. The reserve-to-production index for the underlying
properties at June 30, 1999 was 14 years. This compares favorably to an average
index of 9.2 years for U.S. oil and natural gas properties of publicly
reporting companies at year-end 1997. Because production rates naturally
decline over time, the index is not a useful estimate of how long properties
should economically produce. Based on the reserve report, economic production
from the underlying properties is expected for at least 35 more years.

High Percentage of Proved Developed Reserves

Proved developed reserves are the most valuable and lowest risk category of
reserves because their production requires no significant future development
costs. Proved developed reserves represent approximately 81% of the discounted
present value of estimated future net revenues from the underlying properties.

5
<PAGE>

Control of Operations

The right to operate an oil and natural gas lease is important because the
operator controls the timing and amount of discretionary expenditures for
operational and development activities. Cross Timbers operates approximately
80% of the underlying properties, based on the discounted present value of
estimated future net revenues.

History of Low Cost Reserve Additions

Cross Timbers has a record of successfully adding reserves to the underlying
properties through development at costs substantially below the industry
average. Over the three and one-half years ended June 30, 1999, 22.8 million
BOE of proved reserves were added, or 170% of production, at a cost of $3.09
per BOE. For publicly reporting companies in the United States, the average
industry cost of finding and developing oil and natural gas reserves from 1995
through 1997 was $6.90 per BOE. Cross Timbers intends to reduce development
expenditures for the underlying properties to an average of approximately $8
million per year for the next four years, compared to an average of $22.5
million per year for the three years ended December 31, 1998. Therefore, Cross
Timbers expects that reserve additions over the next four years will decline.
It believes, however, that its historical cost per BOE of reserves added to the
underlying properties should be a good indicator of its ability to add reserves
at low costs in the future.

Over the last three and one-half years, proved reserve additions on existing
wells on the underlying properties included net upward revisions of 3.3 million
BOE. These upward revisions were due to better than projected production
performance and development results, reduced production costs, increased oil
and natural gas prices in some years, gathering system improvements and
improved technology. Cross Timbers believes that the underlying properties will
experience reserve additions in the future, but cannot assure you that this
will occur.

Effect of Planned Development Program

The underlying properties are Cross Timbers' undivided interests in oil and
natural gas leases and the production from existing and future wells on those
leases. If Cross Timbers successfully drills additional wells on acreage
covered by these leases or successfully conducts other development activities,
those activities will enhance production from the underlying properties. The
trust will benefit from increased production, net of 80% of the related
development costs which will be deducted from net proceeds as they are paid.

Without development projects, the underlying properties would typically
experience a 9% to 10% annual decline in production. The planned development
expenditures included in the reserve report are expected to reduce the natural
rate of decline in production to approximately 3% to 4% per year.

Additional Development Opportunities

Cross Timbers believes that the underlying properties will offer economic
development projects that are not included in existing proved reserves. These
additional development opportunities could significantly increase production
and proved reserves and offset the normal rate of decline.

Costs per BOE associated with reserves added through additional development
projects are expected to be in line with historical costs. Costs will be
deducted from the net profits interests as they are paid and will lower monthly
distributions. Cross Timbers expects production from these projects to increase
subsequent distributions.

Additional development opportunities on the underlying properties include:

. performing mechanical and chemical treatments to stimulate production
rates;

6
<PAGE>

. opening new producing zones in existing wells;

. deepening existing wells to new producing zones; and

. drilling additional wells, including horizontal wells.

Cross Timbers believes that these additional development opportunities will
be implemented on the underlying properties over a period of years. Cross
Timbers expects annual development costs will continue to average approximately
$8 million for the four years beginning in 2000. Actual development costs
incurred during that period and subsequent years, however, will depend on
results of ongoing development activities, oil and natural gas prices and
expected rates of return.

Cross Timbers may face conflicts of interest in allocating its resources
between additional development of the underlying properties and development of
other oil and natural gas properties that it now owns or may own in the future.
Cross Timbers allocates resources for development based on expected rates of
return. The underlying properties have historically provided attractive rates
of return on development projects compared to Cross Timbers' other properties
and are expected to continue to do so in the future.

Proved Reserves

Based on the reserve report as of June 30, 1999, estimated proved reserves
of the underlying properties are approximately 69% oil and 31% natural gas on a
BOE basis. The following table provides estimated proved oil and natural gas
reserves, and undiscounted and discounted estimated future net revenues, for
the underlying properties and the net profits interests. Proved reserves in the
table are based on oil and natural gas prices realized by Cross Timbers as of
June 30, 1999, which were $17.95 per Bbl of oil and $2.24 per Mcf of natural
gas. Oil equivalents in the table are the sum of the Bbls of oil and the BOE of
the stated Mcf of natural gas, calculated on the basis that one Bbl of oil is
the energy equivalent of six Mcf of natural gas. The amounts of estimated
future net revenues from proved reserves shown in the table are before income
taxes. Discounted future net revenues are based on a discount rate of 10%,
which is the rate required by the Securities and Exchange Commission. Reserve
estimates are subject to revision.
<TABLE>
<CAPTION>
Estimated Future
Net Revenues from
Proved Reserves Proved Reserves
--------------------------- -----------------------
Natural Oil
Oil Gas Equivalents
(MBbls) (MMcf) (MBOE) Undiscounted Discounted
------- ------- ----------- ------------ ----------
(in thousands, except
per unit data)
<S> <C> <C> <C> <C> <C>
Underlying properties
(100%):
Texas................... 35,103 87,741 49,727 $444,285 $225,971
New Mexico.............. 2,993 13,321 5,213 47,778 25,625
------ ------- ------ -------- --------
Total................. 38,096 101,062 54,940 $492,063 $251,596
====== ======= ====== ======== ========
Underlying properties
(80%).................... 30,477 80,850 43,952 $393,650 $201,277
====== ======= ====== ======== ========
Net profits interests(a).. 17,569 46,633 25,341 $393,650 $201,277
====== ======= ====== ======== ========
Per trust unit............ -- -- -- $ 15.75 $ 8.05
====== ======= ====== ======== ========
</TABLE>
- --------
(a) Proved reserves for the net profits interests owned by the trust are
calculated by subtracting from 80% of proved reserves of the underlying
properties, reserve quantities of a sufficient value to pay 80% of the
future estimated costs, before overhead and trust administrative expenses,
that are deducted in calculating net proceeds. Overhead was $3.9 million in
1998, and trust administrative expenses are expected to be approximately
$300,000 per year. Accordingly, proved reserves for the net profits
interests reflect quantities that are calculated after reductions for
future costs and expenses based on price and cost assumptions used in the
reserve estimates.

7
<PAGE>

Historical Results from the Underlying Properties

The following table provides oil and natural gas sales volumes, average
sales prices, revenues, direct operating expenses, development costs and
overhead relating to the underlying properties for 1996, 1997 and 1998 and for
each of the six month periods ended June 30, 1998 and 1999. The complete
statements of revenues and direct operating expenses of the underlying
properties for the years ended December 31, 1996, 1997 and 1998 (audited) and
for each of the six month periods ended June 30, 1998 and 1999 (unaudited) are
included in this prospectus beginning on page F-2.

<TABLE>
<CAPTION>
Six Months
Ended June 30
---------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
(in thousands, except per unit data)
<S> <C> <C> <C> <C> <C>
Sales Volumes:
Oil (Bbls)........................... 2,404 2,827 2,859 1,530 1,386
Natural gas (Mcf).................... 5,964 6,503 7,656 3,831 3,478
BOE.................................. 3,398 3,911 4,135 2,169 1,965
Average Prices:
Oil (per Bbl)........................ $ 19.83 $ 18.31 $ 12.35 $ 13.01 $ 13.64
Natural gas (per Mcf)................ $ 2.38 $ 2.62 $ 2.05 $ 2.12 $ 1.93
Revenues:
Oil sales............................ $47,663 $51,783 $35,316 $19,901 $18,898
Natural gas sales.................... 14,168 17,016 15,726 8,139 6,702
------- ------- ------- ------- -------
Total.............................. 61,831 68,799 51,042 28,040 25,600
------- ------- ------- ------- -------
Direct Operating Expenses:
Production and property taxes and
transportation...................... 4,652 4,997 4,292 2,281 1,853
Production expenses.................. 15,377 15,597 15,842 7,159 7,018
------- ------- ------- ------- -------
Total.............................. 20,029 20,594 20,134 9,440 8,871
------- ------- ------- ------- -------
Excess of Revenues over Direct
Operating Expenses.................... $41,802 $48,205 $30,908 $18,600 $16,729
======= ======= ======= ======= =======
Development costs...................... $13,612 $36,494 $17,403 $ 9,596 $ 2,899
Overhead............................... $ 3,127 $ 3,344 $ 3,852 $ 1,877 $ 1,952
</TABLE>

8
<PAGE>

Projected Distributable Income For 12 Months Ending September 30, 2000

The following table provides a projection of trust distributable income for
the 12 months ending September 30, 2000. This projection assumes oil and
natural gas sales volumes and development and production costs based upon the
reserve report. The calculations assume realized prices of $18.65 per Bbl of
oil and $2.50 per Mcf of natural gas, which equate to NYMEX prices of $20.00
per Bbl and $2.50 per Mcf. Cross Timbers' management selected these prices as a
reasonable representation of current prices. Cross Timbers can give no
assurance that these prices will be realized, and the distribution table is
strictly an example of management's approximation of how the distribution would
likely be calculated given certain assumptions. Overhead is based upon
estimates by Cross Timbers. The projection was prepared by Cross Timbers as its
reasonable estimate of distributable income for the 12 months ending September
30, 2000, on an accrual or production basis, based on these pricing assumptions
and other assumptions that are described in "Projected Cash Distributions--
Significant Assumptions Used to Prepare the Projected Distributable Income."
The projection assumes Cross Timbers will not convey additional net profits
interests to the trust in exchange for additional trust units. If the maximum
3,000,000 additional trust units were issued to Cross Timbers in exchange for
additional net profits interests, the total cash distributions per trust unit
would not significantly change from the amount shown in the projection. Because
the projection is prepared on an accrual or production basis for the 12 months
ending September 30, 2000, the projection represents an estimate of cash
distributable income for December 1999 through November 2000. The projection
and the assumptions on which they are based are subject to significant
uncertainties, many of which are beyond the control of Cross Timbers or the
trust. ACTUAL COMPARABLE DISTRIBUTABLE INCOME, THEREFORE, COULD VARY
SIGNIFICANTLY BASED UPON CHANGES IN ANY OF THESE ASSUMPTIONS. Distributable
income is particularly sensitive to oil and natural gas prices. See "Projected
Cash Distributions--Sensitivity of Projected Cash Distributions to Oil and
Natural Gas Prices" which shows estimated effects to distributable income from
changes in oil and natural gas prices. As a result of typical production
declines for oil and natural gas properties, production estimates generally
decrease from year to year. ACCORDINGLY, THE PROJECTED CASH DISTRIBUTIONS ARE
NOT NECESSARILY INDICATIVE OF DISTRIBUTIONS FOR FUTURE PERIODS. Because
payments to the trust will be generated by depleting assets, a portion of each
distribution may represent a return of your original investment. See "Risk
Factors--Trust Assets Are Depleting Assets. "
<TABLE>
<CAPTION>
(in thousands,
except per unit data)
---------------------
<S> <C>
Underlying Properties
Sales Volumes:
Oil (Bbls)............................................... 2,758
Natural gas (Mcf)........................................ 6,566
Assumed Realized Sales Price:
Oil (per Bbl)............................................ $ 18.65
Natural gas (per Mcf).................................... $ 2.50
Calculation of Distributable Income
Revenues:
Oil sales................................................ $51,430
Natural gas sales........................................ 16,415
-------
Total.................................................. 67,845
-------
Costs:
Production and property taxes and transportation......... 5,362
Production expenses...................................... 14,371
Development costs........................................ 8,223
Overhead................................................. 4,300
-------
Total.................................................. 32,256
-------
Net proceeds.............................................. 35,589
Net profits percentage.................................... 80%
-------
Trust royalty income...................................... 28,471
Trust administrative expense.............................. 300
-------
Trust distributable income................................ $28,171
=======
</TABLE>

<TABLE>
<CAPTION>
Cash Distribution
as a Percentage of
Amount $ Trust Unit Price
------ -------------------
<S> <C> <C>
Per Trust Unit (25,000,000 Trust Units):
Total cash distributions.......................... $1.13
Cost depletion tax deduction......................
-----
Taxable income....................................
Income tax rate................................... 39.6%
-----
Income tax expense................................
=====
Total cash distributions after tax................
=====
</TABLE>

9
<PAGE>

The Offering

Trust units offered by Cross
Timbers............................. 10,000,000

Trust units outstanding.......... 25,000,000, of which 15,000,000 will be
owned by Cross Timbers if the
underwriters do not exercise their over-
allotment option. Up to 3,000,000
additional trust units may be issued
prior to November 30, 1999 if Cross
Timbers conveys additional net profits
interests to the trust.

Use of proceeds.................. Cross Timbers will receive all net
proceeds from this offering, which will
be used to repay indebtedness under its
revolving credit facility.

NYSE symbol...................... TPT

Investing in Trust Units

Investing in these trust units differs from investing in corporate stock
in the following ways:

. trust unitholders are not owed a fiduciary duty by Cross Timbers or,
except as provided in the trust agreement, by the trustee;

. trust unitholders have limited voting rights;

. trust unitholders are taxed directly on their proportionate share of
trust net income;

. trust unitholders are entitled to federal income tax depletion and
trust administrative expense deductions;

. substantially all trust income must be distributed to trust
unitholders; and

. trust assets are limited to the net profits interests which have a
finite economic life.

10
<PAGE>

RISK FACTORS

Trust Distributions Will Be Sensitive to Changing Oil and Natural Gas Prices

The trust's monthly cash distributions are highly dependent upon the prices
realized from the sale of oil and, to a lesser extent, natural gas. Oil and
natural gas prices can fluctuate widely on a month-to-month basis in response
to a variety of factors that are beyond the control of the trust and Cross
Timbers. These factors include, among others:

. political conditions in the Middle East;

. worldwide economic conditions;

. weather conditions;

. the supply and price of foreign oil and natural gas;

. the level of consumer demand;

. the price and availability of alternative fuels;

. the proximity to, and capacity of, transportation facilities; and

. the effect of worldwide energy conservation measures.

Moreover, government regulations, such as regulation of natural gas
transportation and price controls, can affect product prices in the long term.

Lower oil and natural gas prices may reduce the amount of oil and natural
gas that is economic to produce and will reduce net profits available to the
trust. The volatility of energy prices reduces the accuracy of estimates of
future cash distributions to trust unitholders.

Oil prices were depressed in 1998 because of reduced demand created by the
Asian economic downturn without a corresponding decrease in oil production. In
the first half of 1999, oil prices began a recovery as OPEC member countries
curtailed production. The timing of an increase in oil demand and the ability
of OPEC to continue lower export levels are uncertain.

Trust Distributions Are Affected by Production and Development Costs

Production and development costs on the underlying properties are deducted
in the calculation of the trust's share of net proceeds. Accordingly, higher or
lower production and development costs, without concurrent increases in
revenues, will directly decrease or increase the amount received by the trust
for its net profits interests. For a summary of these costs for the last three
and one-half years, see "The Underlying Properties--Historical Results from the
Underlying Properties."

If development and production costs of underlying properties located in a
particular state exceed the proceeds of production from the properties, the
trust will not receive net proceeds for those properties until future proceeds
from production in that state exceed the total of the excess costs plus accrued
interest during the deficit period. Development activities may not generate
sufficient additional revenue to repay the costs.

Trust Reserve Estimates Are Uncertain

The value of the trust units will depend upon, among other things, the
reserves attributable to the trust's net profits interests. Estimating reserves
is inherently uncertain. Ultimately, actual production, revenues and
expenditures for the underlying properties will vary from estimates and those
variations could be material. Petroleum engineers consider many factors and
make assumptions in estimating reserves. Those factors and assumptions include:

. historical production from the area compared with production rates from
similar producing areas;

. the assumed effect of governmental regulation; and

. assumptions about future commodity prices, production and development
costs, severance and excise taxes, and capital expenditures.

11
<PAGE>

Changes in these assumptions can materially change reserve estimates.

The trust's reserve quantities and revenues are based on estimates of
reserves and revenues for the underlying properties. The method of allocating a
portion of those reserves to the trust is complicated because the trust holds
an interest in net profits and does not own a specific percentage of the oil
and natural gas reserves. See "The Underlying Properties--Oil and Natural Gas
Reserves" for a discussion of the method of allocating proved reserves to the
trust.

Production Risks Can Adversely Affect Trust Distributions

The occurrence of drilling, production or transportation accidents at any of
the underlying properties will reduce trust distributions by the amount of
uninsured costs. These accidents may result in personal injuries, property
damage, damage to productive formations or equipment and environmental damages.
Any uninsured costs would be deducted as a production cost in calculating net
proceeds payable to the trust.

The Trust Does Not Control Operations and Development

Neither the trustee nor the trust unitholders can influence or control the
operation or future development of the underlying properties. Cross Timbers is
unable to significantly influence the operations or future development of the
underlying properties that it does not operate.

The current operators of the underlying properties, including Cross Timbers,
are under no obligation to continue operating the properties. Cross Timbers can
sell any of the underlying properties that it operates and relinquish the
ability to control or influence operations. Neither the trustee nor trust
unitholders have the right to replace an operator.

Cross Timbers May Transfer or Abandon Underlying Properties

Cross Timbers may at any time transfer all or part of the underlying
properties. You will not be entitled to vote on any transfer, and the trust
will not receive any proceeds of the transfer. Following any significant
transfer, the underlying properties will continue to be subject to the net
profits interests of the trust, but the net proceeds from the transferred
property would be calculated separately and paid by the transferee. The
transferee would be responsible for all of Cross Timbers' obligations relating
to calculating, reporting and paying to the trust 80% of net profits on that
portion of the underlying properties, and Cross Timbers would have no
continuing obligation to the trust for those properties.

Cross Timbers or any transferee may abandon any well or property if it
reasonably believes that the well or property can no longer produce in
commercially economic quantities. This could result in termination of the net
profits interest relating to the abandoned well.

Net Profits Interests Can Be Sold or the Trust May Be Terminated

The trustee must sell the net profits interests if the holders of 80% or
more of the trust units approve the sale or vote to dissolve the trust. The
trustee must also sell the net profits interests if the annual gross proceeds
from the underlying properties are less than $1 million for each of two
consecutive years after 2000. Sale of all the net profits interests will
dissolve the trust. The net proceeds of any sale will be distributed to the
trust unitholders.

12
<PAGE>

Cross Timbers' Disposal of Trust Units May Temporarily Reduce the Trust Unit
Market Price

Cross Timbers currently owns 25,000,000 (100%) of the trust units and will
sell 10,000,000 (40%) of the trust units in this offering, or 11,500,000 (46%)
if the underwriters' over-allotment option is exercised in full. In addition,
Cross Timbers has the right, prior to November 30, 1999, to acquire up to
3,000,000 additional trust units in exchange for its conveying additional net
profits interests to the trust. Cross Timbers has granted options to its
executive officers to purchase a maximum of $12 million of its retained trust
units at the initial public offering price. It may use some or all of the
remaining trust units it owns for a number of corporate purposes, including:

. selling them for cash; and

. exchanging them for interests in oil and natural gas properties or
securities of oil and natural gas companies.

If Cross Timbers sells additional trust units or exchanges trust units in
connection with acquisitions or if Cross Timbers executives acquire trust units
upon exercise of options, then additional trust units will be available for
sale in the market. Although Cross Timbers expects these additional trust units
will increase market liquidity, the sale of additional trust units may also
temporarily reduce the market price of the trust units. See "Selling Trust
Unitholder."

Cross Timbers May Enter Into Contracts that Are Not Negotiated in Arm's-Length
Transactions

Cross Timbers and some of its affiliates receive payments under existing
contracts for services relating to the underlying properties. These payments to
Cross Timbers and its affiliates will be deducted in determining net proceeds
payable to the trust and will reduce the amounts available for distribution to
the trust unitholders. These payments will include:

. reimbursements to Cross Timbers for production and development costs to
operate wells;

. payments to Cross Timbers affiliates for marketing services, from which
Cross Timbers expects to net approximately $100,000 in 2000; and

. overhead fees to operate the underlying properties, including
engineering, accounting and administrative functions, which Cross
Timbers expects will be approximately $4.3 million in 2000.

In addition to providing services, Cross Timbers affiliates purchase
production from the underlying properties. Approximately 56% of natural gas
production from the underlying properties for 1998 was sold to Cross Timbers
affiliates.

Cross Timbers believes that the terms of these contracts are competitive
with those that could be obtained from unrelated third parties. Cross Timbers
is permitted under the conveyances creating the net profits interests to enter
into new marketing contracts without any negotiations or other involvement by
independent third parties. Provisions in the conveyances, however, require
that:

. future contracts with affiliates relating to marketing of oil and
natural gas cannot materially exceed charges prevailing in the area for
similar services; and

. future oil and natural gas sales contracts with affiliates must provide
that the affiliates retain not more than 2% of the proceeds from the
sale of production by the affiliates.

Cross Timbers May Have Interests That Are Different From Yours

Because Cross Timbers has interests in oil and natural gas properties not
included in the trust, Cross Timbers may have interests that are different from
yours. For example,

. in setting budgets for development and production expenditures for Cross
Timbers' properties, including the underlying properties, Cross Timbers
may make decisions that

13
<PAGE>

could adversely affect future production from the underlying properties;
these decisions could include reducing development expenditures on
underlying properties, which could cause oil and natural gas production
to decline at a faster rate and result in lower future trust
distributions;

. Cross Timbers could continue to operate an underlying property and
continue to earn an overhead fee even though abandonment of the property
might result in more net profits being available to trust unitholders;
and

. Cross Timbers could decide to sell or abandon some or all of the
underlying properties, and that decision may not be in the best
interests of the trust unitholders; for example, Cross Timbers might
sell some or all of the underlying properties to a third party who could
reduce development expenditures on those properties, or Cross Timbers
might abandon a marginal well that otherwise would continue to produce a
net profit to the trust.

Except for specified matters that require approval of the trust unitholders
described in "Description of the Trust Agreement," the documents governing the
trust do not provide a mechanism for resolving these conflicting interests.

Trust Unitholders Will Have Limited Voting Rights

Your voting rights as a trust unitholder are more limited than those of
stockholders of most public corporations. For example, there is no requirement
for annual meetings of trust unitholders or for an annual or other periodic re-
election of the trustee.

Additionally, trust unitholders have no voting rights in Cross Timbers and
therefore will have no ability to influence its operations of the underlying
properties.

Trust Unitholders Will Have Limited Ability to Enforce Rights

The trust agreement and related trust law permit the trustee and the trust
to sue Cross Timbers or any other future owner of the underlying properties to
compel it to fulfill the terms of the net profits interests. If the trustee
does not take appropriate action to enforce provisions of the net profits
interests, your recourse as a trust unitholder would likely be limited to
bringing a lawsuit against the trustee to compel the trustee to take specified
actions. You probably would not be able to sue Cross Timbers or any future
owner of the underlying properties.

Limited Liability of Trust Unitholders Is Uncertain

Under Delaware law and under the trust agreement, trust unitholders have the
same limitation on personal liability as provided to stockholders of a Delaware
corporation for profit. A number of old Texas court cases have not recognized
limited liability for unitholders of business trusts, and, therefore, it is
unclear whether a Texas court would give effect to this limitation. If the
limitation is not given effect, a Texas court could hold a trust unitholder
personally liable for the trust's liabilities if those liabilities exceeded the
value of the trust's assets.

Cross Timbers believes, however, that it is highly unlikely the trust would
incur such excess liabilities. As a royalty interest, the trust's net profit
interest is generally not subject to operational and environmental liabilities
and obligations. The trust conducts no active business that would give rise to
other business liabilities. The trustee has limited ability to incur
obligations on behalf of the trust. The trustee must ensure that all
contractual liabilities of the trust are limited to claims against the assets
of the trust. The trustee will be liable for its failure to do so.

14
<PAGE>

Cross Timbers' Liability to the Trust Is Limited

The net profits interests provide that Cross Timbers will not be liable to
the trust for performing its duties in operating the underlying properties as
long as it acts in good faith.

Trust Assets Are Depleting Assets

The net proceeds payable to the trust are derived from the sale of depleting
assets. Accordingly, the portion of the distributions to trust unitholders
attributable to depletion may be considered a return of capital. The reduction
in proved reserve quantities is a common measure of the depletion. Future
maintenance and development projects on the underlying properties will affect
the quantity of proved reserves. The timing and size of these projects will
depend on the market prices of oil and natural gas. If operators of the
properties do not implement additional maintenance and development projects,
the future rate of production decline of proved reserves may be higher than the
rate currently expected by Cross Timbers. For federal income tax purposes,
depletion is reflected as a deduction, which is anticipated to be $ per trust
unit in 2000, based on a trust unit purchase price of $ . See "Federal Income
Tax Consequences--Royalty Income and Depletion."

FORWARD-LOOKING STATEMENTS

Some statements made by Cross Timbers in this prospectus under "Projected
Cash Distributions," statements pertaining to future development activities and
costs, and other statements contained in this prospectus are prospective and
constitute forward-looking statements. These forward-looking statements involve
known and unknown risks, uncertainties and other factors that could cause
actual results to differ materially from future results expressed or implied by
the forward-looking statements. The most significant risks, uncertainties and
other factors are discussed under "Risk Factors" above.

USE OF PROCEEDS

The trust will not receive any proceeds from the sale of the trust units.
Cross Timbers will receive all proceeds from the sale of trust units after
deducting underwriting discounts and costs of the offering paid by Cross
Timbers. The net proceeds will be approximately $ million and will increase
to $ million if the underwriters exercise their over-allotment option in
full. Cross Timbers intends to apply the net proceeds from the offering either
to acquire oil and natural gas properties or repay outstanding indebtedness
under its bank revolving credit facility. The additional oil and natural gas
properties may include the purchase from an affiliate of Lehman Brothers Inc.
of the 50% interest not owned by Cross Timbers in properties located in the
Arkoma Basin. Cross Timbers' revolving credit facility bears interest at a
floating rate, currently 6.9%, and matures on June 30, 2003. Cross Timbers
incurred its bank debt to finance recent acquisitions of oil and natural gas
producing properties, purchases of equity securities of other energy companies,
repurchases of Cross Timbers common stock, and development expenditures.

CROSS TIMBERS

Cross Timbers Oil Company is a leading United States independent energy
company. It engages in the acquisition, development and exploration of oil and
natural gas properties, and in the production, processing, marketing and
transportation of oil and natural gas in the United States. Cross Timbers
organized the trust in September 1999 and conveyed the net profits interests to
the trust effective September 1, 1999 in exchange for all of the trust units.
Cross Timbers continues to own the underlying properties from which the net
profits interests were transferred.

15
<PAGE>

formed in 1980. Cross Timbers may form additional trusts with other properties.
It may in the future dispose of some or all of the trust units of the Texas
Permian Trust or any of the other trusts. See "Risk Factors--Cross Timbers'
Disposal of Its Remaining Trust Units May Temporarily Reduce the Trust Unit
Market Price." Cross Timbers has granted to its executive officers, subject to
approval by its stockholders, options to purchase up to $12 million of its
retained trust units at the initial public offering price. The executive
officers will not be entitled to receive any trust distributions until their
options are exercised.

THE TRUST

The trust was formed as of September 1, 1999. It is a statutory business
trust created under the Delaware Business Trust Act. The trust has two
trustees: Bank One, Texas, N.A., which is the trustee that administers the
trust, and Bank One Delaware, Inc., which is the Delaware resident trustee as
required by Delaware law. The Delaware trustee has no significant duties. In
connection with the formation of the trust, Cross Timbers transferred to the
trust the net profits interests covering the underlying properties in exchange
for all 25,000,000 of the trust units effective September 1, 1999.

The trustee can authorize the trust to borrow money to pay trust
administrative or incidental expenses that exceed cash held by the trust. The
trustee may authorize the trust to borrow from the trustee as a lender. Because
the trustee is a fiduciary, the terms of the loan must be fair to the trust
unitholders. The trustee may also deposit funds awaiting distribution in an
account with itself, if the interest paid to the trust at least equals amounts
paid by the trustee on similar deposits.

The trust will pay the trustees a fee of approximately $25,000 per year and
a fee of $7,500 for services to terminate the trust. The trust will also incur
legal, accounting and engineering fees, printing costs and other expenses that
are deducted from the 80% of net proceeds received by the trust before
distributions are made to trust unitholders.

PROJECTED CASH DISTRIBUTIONS

Cross Timbers created the net profits interests through separate conveyances
to the trust of 80% net profits interests carved from Cross Timbers' interests
in properties in Texas and New Mexico. The net profits interests entitle the
trust to receive 80% of the net proceeds from the sale of oil and natural gas
attributable to the underlying properties. Net proceeds equal the gross
proceeds received by Cross Timbers from the sale of production less property
and production taxes, overhead fees and production and development costs. For a
more detailed description of net proceeds, see "Computation of Net Proceeds."

The amount of trust revenues and cash distributions to trust unitholders
will depend on:

. oil prices and, to a lesser extent, natural gas prices;

. the volume of oil and natural gas produced and sold; and

. production, development and other costs.

16
<PAGE>

Projected Distributable Income For 12 Months Ending September 30, 2000

The following table provides a projection of trust distributable income for
the 12 months ending September 30, 2000. This projection assumes oil and
natural gas sales volumes and development and production costs based upon the
reserve report. The calculations assume realized prices of $18.65 per Bbl of
oil and $2.50 per Mcf of natural gas, which equate to NYMEX prices of $20.00
per Bbl and $2.50 per Mcf. Cross Timbers' management selected these prices as a
reasonable representation of current prices. Cross Timbers can give no
assurance that these prices will be realized, and the distribution table is
strictly an example of management's approximation of how the distribution would
likely be calculated given certain assumptions. Overhead is based upon
estimates by Cross Timbers. The projection was prepared by Cross Timbers as its
reasonable estimate of distributable income for the 12 months ending September
30, 2000, on an accrual or production basis, based on these pricing assumptions
and other assumptions that are described in "Projected Cash Distributions--
Significant Assumptions Used to Prepare the Projected Distributable Income."
The projection assumes Cross Timbers will not convey additional net profits
interests to the trust in exchange for additional trust units. If the maximum
3,000,000 additional trust units were issued to Cross Timbers in exchange for
additional net profits interests, the total cash distributions per trust unit
would not significantly change from the amount shown in the projection. Because
the projection is prepared on an accrual or production basis for the 12 months
ending September 30, 2000, the projection represents an estimate of cash
distributable income for December 1999 through November 2000. The projection
and the assumptions on which they are based are subject to significant
uncertainties, many of which are beyond the control of Cross Timbers or the
trust. ACTUAL COMPARABLE DISTRIBUTABLE INCOME, THEREFORE, COULD VARY
SIGNIFICANTLY BASED UPON CHANGES IN ANY OF THESE ASSUMPTIONS. Distributable
income is particularly sensitive to oil and natural gas prices. See "Projected
Cash Distributions--Sensitivity of Projected Cash Distributions to Oil and
Natural Gas Prices" which shows estimated effects to distributable income from
changes in oil and natural gas prices. As a result of typical production
declines for oil and natural gas properties, production estimates generally
decrease from year to year. ACCORDINGLY, THE PROJECTED CASH DISTRIBUTIONS ARE
NOT NECESSARILY INDICATIVE OF DISTRIBUTIONS FOR FUTURE PERIODS. Because
payments to the trust will be generated by depleting assets, a portion of each
distribution may represent a return of your original investment. See "Risk
Factors--Trust Assets Are Depleting Assets."
<TABLE>
<CAPTION>
(in thousands,
except per unit
data)
<S> <C>
Underlying Properties
Sales Volumes:
Oil (Bbls).................................................. 2,758
Natural gas (Mcf)........................................... 6,566
Assumed Realized Sales Price:
Oil (per Bbl)............................................... $ 18.65
Natural gas (per Mcf)....................................... $ 2.50
Calculation of Distributable Income
Revenues:
Oil sales................................................... $51,430
Natural gas sales........................................... 16,415
-------
Total..................................................... 67,845
-------
Costs:
Production and property taxes and transportation............ 5,362
Production expenses......................................... 14,371
Development costs........................................... 8,223
Overhead.................................................... 4,300
-------
Total..................................................... 32,256
-------
Net proceeds.................................................... 35,589
Net profits percentage.......................................... 80%
-------
Trust royalty income............................................ 28,471
Trust administrative expense.................................... 300
-------
Trust distributable income...................................... $28,171
=======
</TABLE>

17
<PAGE>

<TABLE>
<CAPTION>
Cash Distribution
as a Percentage of
Amount $ Trust Unit Price
------ --------------------
<S> <C> <C>
Per Trust Unit (25,000,000 Trust Units):
Total cash distributions....................... $1.13
Cost depletion tax deduction...................
-----
Taxable income.................................
Income tax rate................................ 39.6%
-----
Income tax expense.............................
-----
Total cash distributions after tax.............
=====
</TABLE>

Sensitivity of Projected Cash Distributions to Oil and Natural Gas Prices

Cross Timbers prepared the following unaudited tables, which demonstrate the
estimated effect that changes in the prices for oil and natural gas could have
on trust distributions. The following tables show:

. the projected cash distributions per trust unit for the 12 months ending
September 2000 on the accrual or production basis;

. the resulting projected cash distributions per trust unit as a
percentage of the purchase price of the trust unit; and

. the resulting projected cash distributions per trust unit as a
percentage of the purchase price of the trust unit, after payment of all
federal income tax, net of available deductions, at the highest
individual tax rate of 39.6%.

See "Computation of Net Proceeds--Net Profits Interests."

THE TABLES ARE NOT A PROJECTION OR FORECAST OF THE ACTUAL OR ESTIMATED
RESULTS FROM AN INVESTMENT IN THE TRUST UNITS. THE PURPOSE OF THE TABLES IS TO
ILLUSTRATE THE SENSITIVITY OF CASH DISTRIBUTIONS AND CASH DISTRIBUTIONS AS A
PERCENTAGE OF TRUST UNIT PURCHASE PRICE TO CHANGES IN THE PRICES OF OIL AND
NATURAL GAS. tHERE IS NO ASSURANCE THAT THE ASSUMPTIONS DESCRIBED BELOW WILL
ACTUALLY OCCUR OR THAT THE PRICES OF OIL OR NATURAL GAS WILL NOT CHANGE BY
AMOUNTS DIFFERENT FROM THOSE SHOWN IN THE TABLES.

Due to the seasonal demand for oil and natural gas, the amount of monthly
cash distributions from the trust is expected to vary during the year. Month-
to-month distributions will also vary based on the timing of development
expenditures and the net proceeds, if any, generated by development projects.

Sensitivity of Projected Twelve Months Cash Distributions Per Trust Unit

<TABLE>
<CAPTION>
NYMEX and Realized
Natural Gas Price per Mcf
NYMEX Oil Price Realized Oil Price -----------------------------
per Bbl per Bbl $1.50 $2.00 $2.50 $3.00 $3.50
--------------- ------------------ ----- ----- ----- ----- -----
<C> <S> <C> <C> <C> <C> <C>
$10.00 $ 8.65 ...................... $0.09 $0.19 $0.29 $0.38 $0.48
15.00 13.65 ...................... 0.51 0.61 0.71 0.80 0.90
20.00 18.65 ...................... 0.93 1.03 1.13 1.22 1.32
25.00 23.65 ...................... 1.35 1.45 1.55 1.64 1.74
30.00 28.65 ...................... 1.77 1.87 1.97 2.06 2.16
</TABLE>

18
<PAGE>

Sensitivity of Projected Pre-Tax Cash Distributions as a Percentage
of Trust Unit Price of $

<TABLE>
<CAPTION>
NYMEX and Realized
Natural Gas Price per Mcf
-----------------------------
NYMEX Oil Price Realized Oil Price
per Bbl per Bbl $1.50 $2.00 $2.50 $3.00 $3.50
--------------- ------------------ ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
$10.00 $ 8.65 ..
15.00 13.65 ..
20.00 18.65 ..
25.00 23.65 ..
30.00 28.65 ..
</TABLE>

Sensitivity of Projected After-Tax Cash Distributions as a Percentage
of Trust Unit Price of $

<TABLE>
<CAPTION>
NYMEX and Realized Natural Gas Price per Mcf
------------------------------------------------
NYMEX Oil Price Realized Oil Price
per Bbl per Bbl $1.50 $2.00 $2.50 $3.00 $3.50
--------------- ------------------ -------- -------- -------- -------- --------
<C> <S> <C> <C> <C> <C> <C>
$10.00 $ 8.65 ................
15.00 13.65 ...............
20.00 18.65 ...............
25.00 23.65 ...............
30.00 28.65 ...............
</TABLE>

Significant Assumptions Used to Prepare the Projected Distributable Income

Timing of Actual Distributions. In preparing the projected distributable
income and sensitivity tables above, the revenues and expenses of the trust
were calculated based on the terms of the conveyances creating the trust's net
profits interests. These calculations are described under "Computation of Net
Proceeds," except that amounts for the projection and tables were calculated on
an accrual or production basis rather than the cash basis prescribed by the
conveyances. As a result, the proceeds for production for the final two months
of 1999, and reflected in the projection and tables, will actually enter into
the calculation of net proceeds to be received by the trust in 2000.
Accordingly, the cash distributions attributable to estimated production
represent projected cash distributable income from the trust for the period
December 1999 through November 2000.

Although the conveyance is effective September 1, 1999, no expenses incurred
in September, other than production and property taxes and transportation
costs, will be deducted in computing net proceeds.

Production Estimates. Production estimates are based on the June 30, 1999
reserve report. Production from the underlying properties for the twelve months
ending September 30, 2000 is estimated to be 2,758,000 Bbls of oil and
6,566,000 Mcf of natural gas. See "--Oil and Natural Gas Prices" below for a
description of changes in production due to price variations. Differing levels
of production will result in different levels of distributions and cash
returns.

Oil and Natural Gas Prices. Oil prices assumed in the projected
distributable income estimate and shown in the tables are based on NYMEX oil
prices. NYMEX prices are based upon West Texas Intermediate crude, a light,
sweet oil of a particular gravity. These prices differ from the realized price
received for production from the underlying properties, which takes into
account gravity, quality and transportation and marketing costs. Differentials
between NYMEX oil prices and the prices actually received for the oil
production may vary significantly due to market conditions. In the above
tables,

19
<PAGE>

$1.35 per barrel is subtracted from the NYMEX oil price for these adjustments.
This deduction is based on the recent historical difference between the NYMEX
oil price and the price received for production from the underlying properties.

Natural gas prices assumed in the projected distributable income estimate
and shown in the tables are based on NYMEX and realized prices for natural gas.
The realized price is the price received for natural gas and natural gas
liquids before deductions for transportation, marketing and gathering. The
recent historical difference between the NYMEX natural gas price and the
average gas price for production from the underlying properties has ranged from
a $.21 decrement in 1996 to a $.03 increment in 1997. There is no discernable
trend in the variation between the NYMEX price and the average natural gas
price received for production. Because of its access to natural gas pipelines
for production from the underlying properties, Cross Timbers can market natural
gas in many different geographic regions of the U.S. Cross Timbers believes
that this access to pipelines has moderated location differentials and will
continue to do so in the future.

The adjustments to NYMEX oil prices applied in the above tables are based
upon an analysis by Cross Timbers of the historical price differentials for
production from the underlying properties with consideration given to gravity,
quality and transportation and marketing costs that may affect these
differentials in the future. There is no assurance that these assumed
differentials will recur. Cross Timbers markets a substantial portion of oil
and natural gas production through its marketing subsidiary. See "The
Underlying Properties--Marketing." Any future changes in the marketing
agreements with the marketing subsidiary are not expected to result in
significant changes to net proceeds.

When oil and natural gas prices decline, the operators of the underlying
properties may elect to reduce or completely suspend production. No adjustments
have been made to estimated production for the twelve months ending September
30, 2000 to reflect potential reductions or suspensions of production.

Production Expenses, Development Costs and Overhead. For the projected 12
months, Cross Timbers estimates production expenses to be $14.4 million,
development costs to be $8.2 million and overhead to be $4.3 million. Overhead
is the estimated fee for all properties operated by Cross Timbers that is
deducted by Cross Timbers in calculating net proceeds. For a description of
production expenses, development costs and overhead, see "Computation of Net
Proceeds--Net Profits Interests."

Administrative Expense. Trust administrative expense for the projected
twelve months is assumed to be $300,000 ($0.012 per trust unit). See "The
Trust."

Projected After-Tax Cash Distributions as a Percentage of Trust Unit Price
of $ . The monthly distribution includes two components, one being the return
of your initial capital investment from this depleting asset and the other
being the actual return on your investment. The portion that would be
considered a return of original investment is not determinable until the trust
unit is sold by a trust unitholder. For a discussion of alternative ways of
measuring the depletion of oil and natural gas assets, see "Risk Factors--Trust
Assets Are Depleting Assets."

The Projected After-Tax Cash Distributions as a Percentage of Trust Unit
Price of $ were computed by:

. determining the amount of federal income tax that would be paid on the
cash distributions at the highest individual tax rate for 1999 of 39.6%,
taking into account a cost depletion tax deduction of $ per trust unit;
and

20
<PAGE>

. subtracting this income tax amount from the annual cash distributions;
and

. dividing the result by $ per trust unit.

For federal income tax purposes, cost depletion is calculated by multiplying
the assumed trust unit purchase price of $ by the cost depletion rate of 7.4%.
This rate was estimated by dividing estimated production for the twelve months
ending September 30, 2000 by proved reserves estimated in the reserve report.
Cost depletion is recaptured upon sale of the trust units, which results in the
taxation of any gain on sale as ordinary income, as opposed to capital gain, up
to the amount of cost depletion previously deducted.

When the distributions are less than $ per trust unit, the Projected After-
Tax Cash Distributions as a Percentage of Trust Unit Price of $ would be the
same or greater than the Projected Pre-Tax Cash Distributions as a Percentage
of Trust Unit Price because of cost depletion. In all instances, each trust
unitholder is assumed to have a regular federal income tax liability sufficient
to utilize the depletion deduction. Alternative minimum tax implications have
not been considered. The effect of state income taxes has not been taken into
account in computing the Projected After-Tax Cash Distributions as a Percentage
of Trust Unit Price of $ . See "State Tax Considerations."

21
<PAGE>

THE UNDERLYING PROPERTIES

Cross Timbers owns the underlying properties, subject to the net profits
interests conveyed to the trust. Cross Timbers may, at any time, sell all or
any portion of the underlying properties, subject to the net profits interests.
It has no present intention to do so.

The underlying properties include Cross Timbers' undivided interests in
specified oil and natural gas leases and the production from existing and
future wells on those leases. Cross Timbers' interests cover the leased acreage
and wells drilled on that acreage. Any production resulting from additional
wells drilled on the underlying properties, or any deepening or opening of new
producing zones in existing wells will be attributable to the underlying
properties. Accordingly, those activities, if successful, will increase or
replace production from the underlying properties and increase revenues subject
to the trust's net profits interest.

Cross Timbers' interest comprising substantially all of the underlying
properties is referred to in the oil and natural gas industry as a "working
interest." A working interest is an interest of an oil and natural gas lease
entitling its owner to receive a specified percentage of production, but
requiring the owner to bear the cost of exploring for, developing and producing
oil and natural gas from the property.

Where the working interest is held by a number of persons on a single lease,
a working interest owner is designated the lease operator by agreement. Cross
Timbers operates approximately 80% of the underlying properties based on
relative value, and major oil companies and established independent producers
operate the rest. A lease operator has significant influence on operations of
the lease, including the timing and amount of discretionary expenditures for
operational and development activities. For that reason it is desirable to
operate properties, and it is important that the operator be qualified and
experienced.

Historical Results from the Underlying Properties

The following table provides oil and natural gas sales volumes, average
sales prices, revenues, direct operating expenses, development costs and
overhead relating to the underlying properties for 1996, 1997 and 1998 and the
six-month periods ended June 30, 1998 and 1999. The complete statements of
revenues and direct operating expenses of the underlying properties for the
years ended December 31, 1996, 1997 and 1998 (audited) and for each of the six-
month periods ended June 30, 1998 and 1999 (unaudited) are included in this
prospectus beginning on page F-2.

22
<PAGE>

Discussion and Analysis of Historical Results from the Underlying Properties

General

Revenues vary based on changes in volume and price. The largest causes of
volume fluctuations are natural depletion and the level of development and
remedial projects. The timing of these projects is generally based on product
prices and other factors. Oil prices fluctuate with global supply and demand,
while natural gas prices fluctuate with North American supply and demand.
Natural gas is heavily used for electrical power generation and as a heating
fuel, and its demand and price tend to be weather influenced.

Taxes on production and property tend to be based on total revenue and vary
accordingly. Production expenses include both fixed and variable portions.
Costs of labor, fuel and chemicals are generally fixed in nature, while costs
such as subsurface remediation, surface maintenance and workovers are variable
because they are more elective. As product prices decline, the production
expense per barrel could eventually begin to increase because of curtailment of
development and workover costs and declines in volume. Similarly, as product
prices rise, production expense per barrel tends to decline as a result of
increased development and production volume.

Production and expenses are also affected by enhanced recovery techniques.
Many larger oil fields that have the necessary geology and other conditions are
eventually waterflooded after the primary phase of oil production.
Waterflooding is an engineering technique in which wells are drilled or
converted to water injection wells. Water is injected at high pressure and
tends to push the oil in place toward producing wells. The produced water is
separated from the oil and reinjected. Among other properties, the University
Block 9 Wolfcamp, the Prentice Northeast Unit, the Russell Unit and the Cornell
Unit are all being waterflooded. Waterflooding is not considered a high cost
recovery technique. Carbon dioxide flooding is a third stage recovery technique
in which carbon dioxide is injected and acts as a solvent to help recover
further incremental oil. It is a more expensive than waterflooding because of
the cost of obtaining and transporting large amounts of carbon dioxide, as well
as the initial capital investment required to handle related injection and
compression. None of the underlying properties is currently undergoing carbon
dioxide flooding, but there is the potential for its use depending on oil
prices.

Cross Timbers' technical staff routinely reviews existing waterflood
projects for possible improvement that could increase production or lower
expenses. The staff also studies properties that are not now waterflooded for
the possibility of instituting such projects. The ultimate effects of future
waterflood projects on distributions to trust unitholders cannot be predicted.

For the Years 1996, 1997 and 1998

Excess of revenues over direct operating expenses from the underlying
properties was $41,802,000 for 1996, $48,205,000 for 1997 and $30,908,000 for
1998. The changes in excess of revenues over direct operating expenses were
primarily related to changes in volumes and realized prices. Oil sales were 74%
of total revenues for the three-year period ended December 31, 1998.

Volumes. Oil sales volumes from the underlying properties increased 18% from
1996 to 1997, and 1% from 1997 to 1998. Natural gas sales volumes from the
underlying properties increased 9% from 1996 to 1997, and 18% from 1997 to
1998. The increases were primarily attributable to development projects.

Prices. The average oil price decreased 8% from $19.83 per Bbl in 1996 to
$18.31 in 1997, and decreased 33% from 1997 to $12.35 in 1998. The lower 1998
oil prices were caused by decreased global consumption without a corresponding
decrease in production. The average natural gas price increased 10% from $2.38
per Mcf in 1996 to $2.62 in 1997, and decreased 22% from 1997 to $2.05 in 1998.
The 1996 prices were at the beginning of an upturn in natural gas prices that
lasted through the summer of 1998.

23
<PAGE>

Direct operating expenses. Direct operating expenses increased 3% from
$20,029,000 in 1996 to $20,594,000 in 1997, followed by a 2% decrease to
$20,134,000 in 1998. The primary reason for the fluctuation among the three
years was the change in production taxes associated with oil and natural gas
revenue fluctuations, and the timing of maintenance work.

Production expenses increased 1% from $15,377,000 in 1996 to $15,597,000 in
1997, and increased 2% to $15,842,000 from 1997 to 1998. Most of the
fluctuations were related to the timing of major remedial projects such as
workovers and subsurface maintenance and to increases in production volumes.
The scheduling of most major remedial projects depends on product prices and
the availability of vendors needed to supply equipment and services. Regular
routine maintenance is generally performed on an ongoing basis and is not
significantly affected by these factors. On a per BOE basis, production costs
declined from $4.53 in 1996 to $3.83 in 1998. Production expenses per barrel
were higher in 1996 because the increased production volumes that resulted from
the 1997 development program allowed fixed production costs to be divided among
higher volumes. Production and property taxes and transportation generally
fluctuate with volumes and prices and, consequently, have varied with revenue
levels.

Development costs. Many of the underlying properties were purchased by Cross
Timbers in 1996 and 1997, leading to large development expenditures in 1997.
Development costs rose 168% from $13,612,000 in 1996 to $36,494,000 in 1997,
and decreased 52% to $17,403,000 in 1998 as major development projects were
completed. When owners begin considering the sale of producing properties, they
often curtail development and elective maintenance of the properties. As a
result, production frequently declines until the new owner performs necessary
maintenance and institutes development. Cross Timbers expects development costs
to average $8,000,000 per year for the next four years. Cross Timbers' strategy
is to locate properties for acquisition in areas where its technical staff has
operating experience and there is an existing concentration of its operated
properties to achieve economies of scale. Cross Timbers also seeks properties
with attractive development opportunities.

The Crockett County properties, which include most of the natural gas
production from the underlying properties, were acquired in late 1996. Cross
Timbers acquired significant additional interests in its University properties
in Andrews County in 1997, representing about 4% of 1996 oil production.
Additional interests in the Cornell Unit, which represent about 6% of the total
1998 oil production from underlying properties, were purchased in mid-1999.

Cross Timbers incurred significant development costs in the three years
ended 1998, primarily to drill new wells in producing properties acquired in
Crockett County, to develop the newly acquired University properties and to
continue development of the Prentice Field. These were major projects requiring
large initial outlays. Cross Timbers plans to limit development costs to an
average of $8 million per year for the next four years. It will maintain
production by extending the development projects performed during the three
years ended 1998 and by undertaking economical new projects. After the initial
four years, Cross Timbers will set its development budget based on the then
current product pricing environment. Cross Timbers' development decisions will
take into account both the need for further development to increase production
and the effect of development projects on current distribution levels. Cross
Timbers anticipates that the development cost would increase with higher
product prices and decrease with lower product prices, but cannot predict the
amount of those development costs.

Overhead. Overhead charged to the underlying properties by Cross Timbers was
$3,127,000 for 1996, $3,344,000 for 1997 and $3,852,000 for 1998. Fluctuations
resulted from changes in the number of active operated wells, which increased
with the development program, and the increase in overhead rates per well
caused by the annual contractual escalation.

24
<PAGE>

Overhead charged to the underlying properties is based on a monthly rate per
active well. The rate on jointly owned wells is provided in the applicable
operating agreement, which was negotiated among the owners and the operator.
The transfer documents creating the net profits interests provide a rate of
$504 per well per month for wells not covered by an operating agreement. This
rate is subject to change each year based on a published oilfield index. The
adjustments were increases of 4.1% in 1996, 2% in 1997, 10.3% in 1998 and 5.8%
in 1999. The overhead charge applies only to actively operated wells. Wells
that do not produce quantities sufficient to pay overhead charges would
generally be considered for abandonment. Total overhead charges vary based on
the active well count and rate escalations.

For the Six Month Periods Ended June 30, 1998 and 1999

Excess of revenues over direct operating expenses from the underlying
properties was $18,600,000 for the six-month period ended June 30, 1998, and
$16,729,000 for the six months ended June 30, 1999. The changes in excess of
revenues over direct operating expenses were primarily related to changes in
volumes and prices.

Volumes. Oil and natural gas sales volumes from the underlying properties
decreased 9% from the first half of 1998 to the first half of 1999. This
decrease was primarily attributable to natural decline of prior development
projects. Cross Timbers did not initiate comparable numbers of new projects in
the first half of 1998 because of low product prices. In general, new
development projects are initiated as product prices improve, as has occurred
after the first quarter of 1999.

Prices. The average oil price increased 5% from $13.01 per Bbl in the six-
month period ended June 30, 1998 to $13.64 in 1999. The higher 1999 oil price
was caused by decreased global production without a corresponding decrease in
consumption. The average natural gas price decreased 9% from $2.12 per Mcf in
1998 to $1.93 in 1999. The 1998 prices were at the beginning of an upturn in
natural gas prices that lasted through the summer of 1998.

Direct operating expenses. Direct operating expenses decreased 6% from
$9,440,000 in the six-month period of 1998 to $8,871,000 in 1999. The primary
reason for the fluctuation among the two six-month periods was the change in
production taxes associated with oil and gas revenue fluctuations.

Production expenses declined 2% from $7,159,000 in the first six months of
1998 to $7,018,000 in 1999. Most of the fluctuation was related to the timing
of major remedial projects such as workovers and subsurface maintenance and to
increases in production volumes. On a per BOE basis, production costs rose from
$3.30 in the 1998 period to $3.57 in the 1999 period. Production and property
taxes and transportation costs generally fluctuated in relation to revenue
levels.

Development costs. Many of the underlying properties were purchased by Cross
Timbers in 1996 and 1997, leading to large development expenditures in 1997 and
1998. Development costs decreased 70% from $9,596,000 in the 1998 period to
$2,899,000 in the 1999 period as major development projects were completed.

Overhead. Overhead charged to the underlying properties by Cross Timbers was
$1,877,000 for the first six months of 1998 and $1,952,000 for the first six
months of 1999. Fluctuations resulted from changes in the number of active
operated wells, which increased with the development program, and the increase
in overhead rates per well caused by the annual contractual escalation.

Producing Acres and Well Counts

For the following data, "gross" refers to the total wells or acres in which
Cross Timbers owns a working interest and "net" refers to gross wells or acres
multiplied by the percentage working interest

25
<PAGE>

owned by Cross Timbers. Although many of Cross Timbers' wells produce both oil
and natural gas, a well is categorized as an oil well or a natural gas well
based upon the ratio of oil to natural gas production.

The underlying properties are interests in developed properties located
primarily in the Permian Basin of Texas and New Mexico. The following is a
summary of the approximate producing acreage of the underlying properties at
December 31, 1998.

<TABLE>
<CAPTION>
Gross Net
------ ------
<S> <C> <C>
Texas.......................................................... 72,683 36,394
New Mexico..................................................... 8,038 4,751
------ ------
Total........................................................ 80,721 41,145
====== ======
</TABLE>

The only undeveloped acreage in the underlying properties are 5,233 gross
(3,529 net) acres in Crockett County, Texas. All leases expire in December 1999
with the exception of leases covering 418 acres which expire in April 2000.

The following is a summary of the producing wells on the underlying
properties as of December 31, 1998:

<TABLE>
<CAPTION>
Non-
Operated Operated
Wells Wells Total
----------- ----------- -----------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Oil...................................... 384 358.4 390 67.7 774 426.1
Natural gas.............................. 139 86.4 152 32.7 291 119.1
--- ----- --- ----- ----- -----
Total.................................. 523 444.8 542 100.4 1,065 545.2
=== ===== === ===== ===== =====
</TABLE>

The following is a summary of the number of wells drilled by Cross Timbers
on the underlying properties during the last three years. Unless otherwise
indicated, all wells drilled are developmental.

<TABLE>
<CAPTION>
Year Ended December 31
--------------------------------
1996 1997 1998
---------- ---------- ----------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Completed:
Oil wells (a).............................. 48 40.7 60 47.6 22 12.0
Natural gas wells.......................... 18 2.8 32 16.5 26 13.2
Non-productive.............................. -- -- 1 0.6 1 0.1
--- ---- --- ---- --- ----
Total (b)................................. 66 43.5 93 64.7 49 25.3
=== ==== === ==== === ====
</TABLE>
- --------
(a) Excludes 7 gross (4.6 net) in 1996, 2 gross (0.1 net) in 1997 and 2 gross
(1.0 net) in 1998 water injection wells.
(b) Includes 22 gross (1.8 net) in 1996, 20 gross (2.1 net) in 1997 and 17
gross (1.9 net) in 1998 wells drilled on non-operated interests.

26
<PAGE>

Oil and Natural Gas Sales Prices and Production Costs

The following table shows the average sales prices per Bbl of oil and Mcf of
natural gas produced and the production costs, production and property taxes
and transportation costs per BOE for the underlying properties:

<TABLE>
<CAPTION>
Six Months Ended
Year Ended December 31 June 30
----------------------- -----------------
1996 1997 1998 1998 1999
------- ------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
Sales prices:
Oil (per Bbl)................... $ 19.83 $ 18.31 $ 12.35 $ 13.01 $ 13.64
Natural gas (per Mcf)........... 2.38 2.62 2.05 2.12 1.93
Production costs (per BOE)....... 4.53 3.99 3.83 3.30 3.57
Production and property taxes and
transportation costs (per BOE).. 1.37 1.28 1.04 1.05 0.94
</TABLE>

Major Producing Areas

Each of the major areas discussed below includes various opportunities for
further development work. Cross Timbers' engineers have estimated that $8
million per year in development will keep production relatively stable for each
of the next four years, with estimated declines of 3% to 4% per year. The exact
projects and development procedures will continue to evolve as each area is
further developed, as product prices change and as technology improves. The
effect of development projects on trust distributions cannot currently be
determined.

University Block 9

The University Block 9 Field is located in Andrews County, Texas and was
discovered in 1953. Productive zones are of Wolfcamp (at 8,400 feet),
Pennsylvanian (at 8,700 feet) and Devonian age (at 10,400 feet). There are 64
gross producing wells (63.0 net). Cross Timbers operates the Wolfcamp Unit,
Penn Unit and 33 of the 34 active Devonian wells. A unit typically means that a
group of producing leases has been combined under an agreement providing for
consolidated ownership. The purpose is to provide for efficiency of operation.
The Wolfcamp Unit is undergoing waterflooding. Development potential includes
opening new producing zones, infill drilling and improved water injection
techniques.

This field was Cross Timbers' most active oil development area during 1998.
Cross Timbers completed eight horizontal and vertical wells during 1998 and at
year-end had three wells in process of completion. It also opened four Devonian
wells into the Pennsylvanian horizon. During 1999, Cross Timbers plans to drill
up to six wells or horizontal sidetracks and has identified four wells that it
intends to open for additional productive zones in the Pennsylvanian horizon.
Cross Timbers has identified 30 to 40 additional potential locations for future
development by either drilling or directional drilling through existing
wellbores.

The University Block 9 properties averaged 2,500 Bbls of oil per day for the
first six months of 1999 net to the underlying properties.

Prentice Field

The Prentice Field is located in Terry and Yoakum counties, Texas. In 1993
and 1994, Cross Timbers acquired its 91.5% working interest in the 178-well
Prentice Northeast Unit in four separate transactions and assumed operation of
the Unit. Cross Timbers also owns an interest in 80 gross (1.7 net) non-
operated wells.

Discovered in 1950, the Prentice Field produces from carbonate reservoirs in
the Clear Fork and Glorieta formations at depths ranging from 6,000 to 7,000
feet. The Prentice Field is separated into

27
<PAGE>

several waterflood units for secondary recovery operations. The Prentice
Northeast Unit was formed in 1964 with waterflood operations commencing a year
later. Development potential exists through infill drilling and improvement of
water injection well placement. Additional recovery potential also exists
through carbon dioxide flooding.

During 1998, Cross Timbers drilled 1 gross (0.91 net) horizontal sidetrack
in the Prentice Northeast Unit that currently produces an average of 35 Bbls
per day. Cross Timbers is currently studying additional areas in the Prentice
Northeast Unit for future possible development, including:

. using horizontal drilling technology to drill two or three wells in the
last half of 1999;

. drilling five wells on 10-acre spacing in the last half of 1999 based on
the successful 31 infill well program in 1997; and

. evaluating the deeper formation intervals in the eastern portion of the
field.

Cross Timbers has identified 60-70 additional locations for possible future
development. The Prentice Northeast Unit's average production was 2,450 Bbls of
oil per day for the first six months of 1999 net to the underlying properties.

Crockett County

Cross Timbers acquired its Crockett County, Texas property interests in
December 1996. The properties produce from Pennsylvanian-aged Canyon sands and
Strawn carbonates from 6,400 to 9,200 feet. These formations are characterized
by multiple producing zones. Cross Timbers currently owns an interest in 269
wells, 125 of which it operates.

The properties are located in four major fields that Cross Timbers
operates--Henderson/Angus, Ozona, Davidson Ranch and Hunt-Baggett/Thomason. The
fields were discovered in the mid-1970s and developed in 640-acre spacing.
Drilling on 320 and 160-acre spacing occurred in the mid-1980s in the Canyon
Sands. Drilling in the 1990s occurred on 80 and 40 acres.

Since acquiring the properties Cross Timbers has drilled 39 wells and
participated in 22 non-operated wells. Gross production from Cross Timbers
operated wells has increased from 11,000 Mcf to 20,000 Mcf per day. Cross
Timbers has also improved the gathering system in the Henderson Field. Cross
Timbers plans to drill 40 to 60 remaining locations on the Crockett County
underlying properties.

These properties produced an average of 11,300 Mcf per day in the first six
months of 1999 net to the underlying properties.

Russell Field

The Russell Field is located in Gaines County, Texas. In 1993, Cross Timbers
acquired its interest in 23 operated wells and a 26% interest in the non-
operated Russell Clearfork 7000 Unit and 50% interests in two other non-
operated leases (42 wells net).

Discovered in 1943, the Russell Field produces from the San Andres,
Glorieta, Middle Clearfork, and Devonian formations at depths ranging from
4,800 to 10,800 feet. Since acquiring its interest, Cross Timbers has drilled
four wells and performed 15 workovers. Additional development potential
includes restimulations, recompletions, infill drilling, and implementing
secondary recovery projects in the Middle Clearfork and San Andres formations.
Cross Timbers has identified more than 25 additional locations that could be
drilled or recompleted in the Russell Field.

The Russell Field had average production of 800 Bbls of oil per day in the
first six months of 1999 net to the underlying properties.

28
<PAGE>

Cornell Unit

The Cornell Unit is located in Yoakum County, Texas. Cross Timbers owns a
68.3% working interest in 62 gross (42.3 net) wells, which includes an
additional working interest in this Unit purchased in July 1999.

The Cornell Unit is located in the center of the Wasson Field, which was
discovered in 1936. The field has produced over two billion barrels of oil to
date, approximately 90% of which has come from the San Andres formation at
depths of 4,800 to 5,300 feet.

The 1,923 acre Cornell Unit was formed in 1965, when waterflood operations
were commenced in the San Andres. The unit was infill drilled to 20-acre
spacing from 1977 to 1981. In 1985, tertiary recovery operations were initiated
with carbon dioxide injection. Carbon dioxide injections were scaled back in
1996 due to economic considerations, and full-scale waterflood operations were
restored.

Potential exists for 10-acre infill drilling, which has been successfully
implemented in the contiguous Denver and Willard Units. Additionally, the Texas
Railroad Commission has recently approved limited development of the large
natural gas reservoir that exists in upper productive intervals of the San
Andres.

Including the portion Cross Timbers purchased in July 1999, the Cornell Unit
produced an average of 780 Bbls of oil per day in the first six months of 1999
net to the underlying properties.

Oil and Natural Gas Reserves

Miller and Lents estimated oil and natural gas reserves attributable to the
underlying properties as of December 31, 1998. Miller and Lents updated its
reserve estimate from December 31, 1998 to June 30, 1999 by deducting estimated
production and net revenues for the period January 1, 1999 through June 30,
1999, and adjusting for the effects of changes in oil and natural gas prices,
and the timing of development projects. The June 30, 1999 reserve estimate also
includes an additional interest in the Cornell Unit that was acquired in July
1999. Numerous uncertainties are inherent in estimating reserve volumes and
values, and the estimates are subject to change as additional information
becomes available. The reserves actually recovered and the timing of production
of the reserves may vary significantly from the original estimates.

Miller and Lents calculated reserve quantities and revenues for the net
profits interests from projections of reserves and revenues attributable to the
combined interests of the trust and Cross Timbers in the underlying properties.
Because the trust owns net profits interests and not a specific ownership
percentage of the oil and natural gas reserve quantities, proved reserves for
the trust's net profits interests are calculated by subtracting from 80% of
proved reserves of the underlying properties, reserve quantities of a
sufficient value to pay 80% of the future estimated production and development
costs, excluding overhead. Accordingly, proved reserves for the net profits
interests reflect quantities that are calculated after reductions for future
costs and expenses based on the price and cost assumptions used in the reserve
estimates.

The standardized measure of discounted future net cash flows and changes in
discounted cash flows presented below were prepared using assumptions required
by the Financial Accounting Standards Board. These assumptions include the use
of June 30, 1999 prices for oil and natural gas and June 30, 1999 costs for
estimated future development and production expenditures to produce the proved
reserves.

Because natural gas prices are influenced by seasonal demand, use of June
30, 1999 prices, as required by the Financial Accounting Standards Board, may
not be the most accurate basis for estimating future revenues or reserve data.
Future net cash flows are discounted at an annual rate of 10%. There is no
provision for federal income taxes because future net revenues are not subject
to taxation at the trust level.

29
<PAGE>

Oil prices used to determine the standardized measure at June 30, 1999 were
based on NYMEX crude prices of $19.29 ($17.95 realized) per Bbl. The weighted
average June 30, 1999 realized natural gas price used to determine the
standardized measure was $2.24 per Mcf.

During 1999, Cross Timbers filed estimates of oil and natural gas reserves
as of December 31, 1998 with the U.S. Department of Energy on Form EIA-23.
These estimates are consistent with the reserves reported in this prospectus
for the underlying properties as of December 31, 1998, with the exception that
Form EIA-23 includes only reserves from properties that had been acquired and
were operated by Cross Timbers at that date. Neither Cross Timbers nor the
trust has reported reserves for the net profits interests with any Federal
authority or agency prior to the filing of this prospectus.

Proved Reserves

The following table shows proved reserves, proved developed reserves, future
net revenues and discounted present value of future net revenues at June 30,
1999 for the underlying properties, 80% of the underlying properties and the
net profits interests.

<TABLE>
<CAPTION>
80% of
Underlying Underlying Net Profits
Properties Properties Interests
---------- ---------- -----------
(in thousands)
<S> <C> <C> <C>
Proved reserves
Oil (Bbls)................................. 38,096 30,477 17,569
Natural gas (Mcf).......................... 101,062 80,850 46,633
Barrel of Oil Equivalents (BOE)............ 54,940 43,952 25,341
Proved developed reserves
Oil (Bbls)................................. 26,129 20,903 12,358
Natural gas (Mcf).......................... 63,853 51,082 30,374
Barrel of Oil Equivalents (BOE)............ 36,771 29,417 17,420
Future net revenues.......................... $492,063 $393,650 $393,650
Present value discounted at 10% per annum.... $251,596 $201,277 $201,277
</TABLE>

30
<PAGE>

The following table summarizes the changes in estimated proved reserves of
the underlying properties for the periods indicated. The data is presented
assuming the underlying properties were acquired prior to December 31, 1995.
Reserve estimates for underlying properties that Cross Timbers acquired between
1996 and 1999 are not available prior to the date acquired. For purposes of
calculating quantities of estimated proved reserves of these properties as of
December 31, 1995, 1996, 1997 and 1998, proved reserves are assumed to equal
reserves at the acquisition date plus production between December 31, 1995,
1996, 1997 or 1998 and the acquisition date.

<TABLE>
<CAPTION>
Underlying Properties
----------------------------
Oil
Oil Gas Equivalents
(Bbls) (Mcf) (BOE)
------ ------- -----------
(in thousands)
<S> <C> <C> <C>
Balance, December 31, 1995........................ 32,501 78,444 45,575
Revisions, extensions, discoveries and
additions...................................... 3,528 12,437 5,601
Production...................................... (2,404) (5,964) (3,398)
------ ------- ------
Balance, December 31, 1996........................ 33,625 84,917 47,778
Revisions, extensions, discoveries and
additions...................................... 8,883 27,266 13,427
Production...................................... (2,827) (6,503) (3,911)
------ ------- ------
Balance, December 31, 1997........................ 39,681 105,680 57,294
Revisions, extensions, discoveries and
additions...................................... (3,644) 2,147 (3,286)
Production...................................... (2,859) (7,656) (4,135)
------ ------- ------
Balance, December 31, 1998........................ 33,178 100,171 49,873
Revisions, extensions, discoveries and
additions...................................... 6,304 4,369 7,032
Production...................................... (1,386) (3,478) (1,965)
------ ------- ------
Balance, June 30, 1999............................ 38,096 101,062 54,940
====== ======= ======

Negative revisions of oil reserves during 1998 primarily resulted from lower
year-end oil prices that caused a portion of reserves not to be economically
recoverable.

Proved Developed Reserves
Balance, December 31, 1995........................ 22,296 65,826 33,267
====== ======= ======
Balance, December 31, 1996........................ 23,594 58,557 33,354
====== ======= ======
Balance, December 31, 1997........................ 26,173 66,889 37,322
====== ======= ======
Balance, December 31, 1998........................ 22,188 63,962 32,848
====== ======= ======
Balance, June 30, 1999............................ 26,129 63,853 36,771
====== ======= ======
</TABLE>

Cross Timbers expects to spend an average of $8 million per year for the
next four years to develop the underlying properties and expects that
development activities will moderate the rate of decline of proved reserves.

31
<PAGE>

Standardized Measure of Discounted Future Net Cash Flows from Proved
Reserves

The following table provides the summary calculation of the standardized
measure of discounted future net cash flows of the underlying properties, 80%
of the underlying properties and the net profits interests as of June 30, 1999.
Because the underlying properties and the trust are not taxable at the
underlying property level or trust level, no provision is included for income
taxes.

<TABLE>
<CAPTION>
80% of Net
Underlying Underlying Profits
Properties Properties Interests
---------- ---------- ---------
(in thousands)
<S> <C> <C> <C>
Future cash flows............................... $901,449 $721,159 $416,083
Future costs:
Production.................................... 343,966 275,173 22,433
Development................................... 65,420 52,336 --
-------- -------- --------
Future net cash flows........................... 492,063 393,650 393,650
10% discount factor............................. 240,467 192,373 192,373
-------- -------- --------
Standardized measure............................ $251,596 $201,277 $201,277
======== ======== ========
</TABLE>

Regulation

Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at market prices. The Federal Energy Regulatory
Commission implemented regulations on January 1, 1995, to establish an indexing
system for transportation rates for oil that could increase the cost of
transporting oil to the purchaser. Cross Timbers is not able to predict what
effect, if any, these regulations might have.

Oil and Natural Gas Regulation. The availability, terms and cost of
transportation significantly affect sales of natural gas. The interstate
transportation and sale for resale of natural gas is subject to federal
regulation, including transportation rates, storage tariffs and various other
matters, primarily by the Federal Energy Regulatory Commission. Federal and
state regulations govern the price and terms for access to natural gas pipeline
transportation. The Federal Energy Regulatory Commission's regulations for
interstate natural gas transmission in some circumstances may also affect the
intrastate transportation of natural gas.

While natural gas prices are currently unregulated, Congress historically
has been active in the area of natural gas regulation. Cross Timbers cannot
predict whether new legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the various state
legislatures, and what effect, if any, the proposals might have on the
operations of the underlying properties.

Environmental Regulation. Companies that are engaged in the oil and gas
industry are affected by federal, state and local laws regulating the discharge
of materials into the environment. Those laws may impact operations of the
underlying properties. Cross Timbers believes that it is in substantial
compliance with the environmental laws and regulations that apply to the
operations of the underlying properties. Cross Timbers has not previously
incurred material expenses in complying with environmental laws and regulations
that affect its operations of the underlying properties. It does not currently
expect that future compliance will have a material adverse effect on the trust
or the monthly distributions.

State Regulation. The States of Texas and New Mexico regulate the production
and sale of oil and natural gas, including imposing requirements for obtaining
drilling permits, the method of developing new fields, the spacing and
operation of wells and the prevention of waste of oil and gas resources. The
states may regulate rates of production and may establish maximum daily
production allowables from both oil and natural gas wells based on market
demand or resource conservation, or both.

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<PAGE>

Other Regulation. The Mineral Management Service of the United States
Department of Interior is evaluating existing methods of settling royalties on
federal and Native American oil and natural gas leases. One percent of the net
acres of the underlying properties involve federal leases. The final rules
could cause an increase in the federal royalties to be paid on these properties
and, correspondingly, decrease the revenue to Cross Timbers and the trust from
these properties. Cross Timbers, however, does not believe that the proposed
rule changes will have a significant detrimental effect on the distributions
from the trust.

The petroleum industry is also subject to compliance with various other
federal, state and local regulations and laws. Some of those laws relate to
occupational safety, resource conservation and equal employment opportunity.
Cross Timbers does not believe that compliance with these laws will have a
material adverse effect upon the trust unitholders.

Title to Properties

Cross Timbers believes that its title to the underlying properties is, and
the trust's title to the net profits interest will be, good and defensible in
accordance with standards generally accepted in the oil and gas industry.

The underlying properties are typically subject, in one degree or another,
to one or more of the following:

. royalties, overriding royalties and other burdens, under oil and gas
leases;

. contractual obligations, including, in some cases, development
obligations, arising under operating agreements, farmout agreements,
production sales contracts and other agreements that may affect the
properties or their titles;

. liens that arise in the normal course of operations, such as those for
unpaid taxes, statutory liens securing unpaid suppliers and contractors
and contractual liens under operating agreements;

. pooling, unitization and commutation agreements, declarations and
orders; and

. easements, restrictions, rights-of-way and other matters that commonly
affect property.

To the extent that these burdens and obligations affect Cross Timbers'
rights to production and the value of production from the underlying
properties, they have been taken into account in calculating the trust's
interests and in estimating the size and the value of the reserves attributable
to the net profits interests. Cross Timbers believes that the burdens and
obligations affecting the underlying properties and the net profits interests
are conventional in the industry for similar properties. Cross Timbers also
believes that the burdens and obligations do not in the aggregate materially
interfere with the use of the underlying properties and will not materially
adversely affect the value of the net profits interests.

The net profits interests covering the underlying properties in Texas
constitute interests in real property under Texas law. Although the matter is
not entirely free from doubt, it is the opinion of New Mexico counsel, Hinkle,
Cox, Eaton, Coffield & Hensley, L.L.P. that the net profits interests covering
the underlying properties in New Mexico also constitute interests in real
property under New Mexico law. Cross Timbers will record the conveyances in the
appropriate real property records of Texas and New Mexico. If a determination
were made in a bankruptcy proceeding of Cross Timbers that a net profits
interest did not constitute a real property interest under applicable state
law, it could be designated an executory contract. An executory contract is a
term used, but not defined, in the federal bankruptcy code to refer to a
contract under which the obligations of both the debtor and the other party are
so unsatisfied that the failure of either to complete performance would
constitute a material breach excusing performance by the other. If a net
profits interest were designated an

33
<PAGE>

executory contract and rejected in the bankruptcy proceeding, Cross Timbers
would not be required to perform its obligations under the net profits interest
and the trust would seek damages as one of Cross Timbers' unsecured creditors.
Although no assurance can be given, Cross Timbers does not believe that the net
profits interests should be subject to rejection in a bankruptcy proceeding as
executory contracts.

Marketing

Cross Timbers typically sells its oil production from the underlying
properties at the wellhead to third parties in accordance with existing
contracts. The daily sales price for oil is related to the current NYMEX price
for light, sweet crude adjusted for the quality of crude produced and reduced
by transportation costs. The quality of crude is determined by its density,
which is called gravity in the oil industry, and its sulfur content. Crude oil
containing more than 0.5% sulfur is referred to as sour crude and generally
sells at a discount to sweet crude. This discount is determined daily in the
crude oil markets. Cross Timbers estimates that two-thirds of the oil being
currently produced from the underlying properties is sour crude. Recently, the
discount has ranged between $1.20 and $1.80 per Bbl.

More than half of natural gas production from the underlying properties is
from wells in Crockett County, and approximately 88% of this production is
processed by an unaffiliated third party under two separate contracts expiring
in April 2002 and March 2014. About 68% of the natural gas processed by the
third party is subject to a contract under which Cross Timbers receives, after
processing, natural gas with an energy content equivalent to the energy content
of the natural gas delivered prior to processing. Cross Timbers also receives
70% of the net profit from the sale by the processor of the natural gas liquids
extracted from the processed natural gas. The remaining 32% of the natural gas
processed by the third party is subject to another contract under which Cross
Timbers receives the processed natural gas net of all fuel and gas volumes
converted to liquids plus 30% of the proceeds from the sale of the extracted
natural gas liquids. In addition, Cross Timbers pays a fee of $0.015 per Mcf
for each stage of compression. After processing, Cross Timbers' marketing
subsidiary purchases the natural gas at a price, net of transportation costs,
based on either the Houston Ship Channel Index, less $0.05 per MMbtu, or the El
Paso Permian Pool Index. The marketing subsidiary then sells this natural gas,
which totaled approximately 4.2 million Mcf in 1998, for its own account into
various markets.

Cross Timbers sells the remaining natural gas from the underlying properties
to unaffiliated third parties under contracts of varying terms which provide
for Cross Timbers to receive 70% to 87% of the net proceeds from sales.

In the future, the marketing subsidiary may enter into new contracts with
Cross Timbers for the purchase of oil and natural gas as old contracts expire.
These contracts will provide that the sales proceeds to Cross Timbers may not
be less than 98% of the proceeds received by the marketing subsidiary from its
sales to unaffiliated third parties. The sales price obtained by the marketing
subsidiary from unaffiliated third parties will be adjusted for gravity and
quality and will be net of any deductions for transportation from the wellhead.
For example, as disclosed above, Cross Timbers' marketing subsidiary currently
purchases most of the Crockett County natural gas at a location-adjusted index
price and resells it for its own account at market-sensitive prices. If there
were any new contractual arrangements with the marketing subsidiary, it would
have to pay at least 98% of its ultimate net sales price to Cross Timbers,
which is the price that would be received by the net profits interests.
Accordingly, if the natural gas sales price received by the marketing
subsidiary were $2.50 per MMBtu, the price to be received by Cross Timbers and
the net profits interests would be at least $2.45 per MMBtu.

34
<PAGE>

Year 2000

"Year 2000," or the ability of computer systems to process dates with years
beyond 1999, affects almost all companies and organizations. Computer systems
that are not Year 2000 compliant by January 1, 2000 may cause material adverse
effects to companies and organizations that rely upon those systems. The
trust's timely receipt of royalty income and disbursement of distributable
income to trust unitholders will largely depend upon performance of computer
systems and computer-controlled equipment of Cross Timbers, the trust's
transfer agent and other third parties. These third parties include oil and
natural gas purchasers and significant service providers such as electric
utility companies and natural gas plant, pipeline and gathering system
operators. Because the trust will not use the trustee's computer systems to any
significant degree, the trustee's Year 2000 compliance should not significantly
affect the trust.

Cross Timbers is in the process of reviewing its computer systems and
computer-controlled field equipment and making the necessary modifications for
Year 2000 compliance. Cross Timbers has completed modifications and testing of
its primary accounting and land computer programs. The remaining computer
systems have been inventoried and assessed. Some of Cross Timbers' critical
field equipment, such as natural gas compressors, are partially controlled or
regulated by embedded computer chips. Remediation of these critical components
was completed in August 1999. Functional solutions and remediation of less
critical items is expected to be complete by the end of 1999. Less critical
items are components that are not critical for production, safety or sales.

Based on its review, remediation efforts and the results of testing to date,
Cross Timbers does not believe that timely modification of its computer systems
and computer-controlled equipment for Year 2000 compliance represents a
material risk to the trust. Cross Timbers estimates that total costs related to
Year 2000 compliance efforts will be less than $500,000 of which approximately
$155,000 has been incurred and expensed through September 1999. The trust will
not incur any of Cross Timbers' Year 2000 costs.

Cross Timbers has identified significant third parties whose Year 2000
compliance could affect Cross Timbers and is in the process of formally
inquiring about their Year 2000 status. Cross Timbers has received responses to
approximately 58% of its inquiries. Approximately 99% of respondents have
indicated that they will be Year 2000 compliant by January 1, 2000. Despite its
efforts to assure that such third parties are Year 2000 compliant, Cross
Timbers cannot provide assurance that all significant third parties will
achieve compliance in a timely manner. A third party's failure to achieve Year
2000 compliance could have a material adverse effect on Cross Timbers'
operations and cash flow, and therefore have a material adverse impact on
timely trust distributions to trust unitholders. For example a third party
might fail to deliver revenue related to the trust's net profits interest to
Cross Timbers. In this situation, the trustee would be unable to make
distributions of such amounts to trust unitholders on a timely basis. The
potential effect of Year 2000 non-compliance by third parties is currently
unknown.

Cross Timbers is currently identifying appropriate contingency plans in the
event of potential problems resulting from failure of Cross Timbers' or
significant third party computer systems on January 1, 2000. Year 2000
contingency plans will focus on computer, network and communications equipment,
electronic data interchange with business partners, and field operations
automated well control systems. Year 2000 testing of field equipment earlier in
1999 indicated other field operations may use existing emergency response plans
in the event of Year 2000 failure. Detailed Year 2000 contingency plans will be
completed by the end of November 1999.

Litigation

There is no material litigation involving the underlying properties.

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<PAGE>

COMPUTATION OF NET PROCEEDS

The provisions governing the computation of the net proceeds are detailed
and extensive. The following description of the net profits interests and the
computation of net proceeds is subject to and qualified by the more detailed
provisions of the conveyances of the net profits interests that are filed as
exhibits to the registration statement. See "Available Information."

Net Profits Interests

The net profits interests are defined net profits interests carved from the
underlying properties. Each net profits interest entitles the trust to receive
80% of the net proceeds from the sale of oil and natural gas produced from the
underlying properties.

The amounts paid to the trust for the net profits interests are based on the
definitions of "gross proceeds" and "net proceeds" contained in the conveyances
and described below. Under the conveyances, net proceeds are computed monthly.
Cross Timbers pays 80% of the aggregate net proceeds attributable to a
computation period to the trust on or before the last business day of the month
following the computation period. Cross Timbers will not pay to the trust
interest on the net proceeds held by Cross Timbers prior to payment to the
trust. The trustee makes distributions to trust unitholders monthly. See
"Description of the Trust Units--Distributions and Income Computations."

Net proceeds equal the excess of gross proceeds over production costs and
excess production costs attributable to a prior computation period. For royalty
and overriding royalty interests, production costs are zero.

Gross proceeds means an amount received by Cross Timbers from sales of oil
and natural gas produced from the underlying properties, after deducting:

. all general property (ad valorem), production, severance, sales,
gathering, excise and other taxes except income taxes, and gathering
costs; and

. any payment made to the owner of an underlying property for

-- natural gas not taken, but to the extent payments are allocated to
natural gas taken in the future, payments are included, without
interest, in gross proceeds when such natural gas is taken;

-- damages, other than drainage or reservoir injury;

-- rental for reservoir use; and

-- payments in connection with the drilling of any well.

Gross proceeds does not include consideration for the transfer or sale of
any underlying property by Cross Timbers or any subsequent owner to any new
owner. Gross proceeds also does not include any amount for oil and natural gas
lost in production or marketing or used by the owner of the underlying
properties in drilling, production and plant operations. Gross proceeds
includes payments for future production if they are not subject to repayment in
the event of insufficient subsequent production.

Production costs, on a cash basis, generally means the sum of:

. all payments to mineral or landowners, such as royalties or other
burdens against production, delay rentals, shut-in natural gas payments,
minimum royalty or other payments for drilling or deferring drilling;

. any taxes paid by the owner of an underlying property, other than income
taxes, to the extent not deducted or excluded in calculating gross
proceeds, including estimated and accrued ad valorem and other property
taxes;

. costs paid by the owner of an underlying property under any joint
operating agreement;

36
<PAGE>

. all other costs, expenses and liabilities of exploring for, drilling,
operating and producing oil and natural gas, including allocated
expenses such as labor, vehicle and travel costs and materials;

. costs or charges associated with gathering, treating and processing
natural gas;

. certain interest costs;

. any overhead charge;

. amounts previously included in gross proceeds but subsequently paid as a
refund, interest or penalty;

. costs and expenses for renewals or extensions of leases; and

. at the option of the owner of an underlying property, accruals for costs
approved under authorizations for expenditure.

As is customary in the oil and natural gas industry, Cross Timbers charges
an overhead fee to operate the underlying properties. The operating activities
include various engineering, accounting and administrative functions. This fee
totaled $3.9 million in 1998 for all underlying properties operated by Cross
Timbers. Overhead charged to the underlying properties is based on a monthly
rate per active well. The rate on jointly owned wells is provided in the
applicable operating agreement, which was negotiated among the owners and the
operator. The transfer documents creating the net profits interests provide a
rate of $504 per well per month for wells not covered by an operating
agreement. This rate is subject to change each year based on a published
oilfield index. The adjustments were increases of 4.1% in 1996, 2% in 1997,
10.3% in 1998 and 5.8% in 1999. The overhead charge applies only to actively
operated wells. Wells that do not produce quantities sufficient to pay overhead
charges would generally be considered for abandonment. Total overhead charges
vary based on the active well count and rate escalations.

Excess production costs are the excess of production costs over gross
proceeds, plus interest accrued at the prime rate. Therefore, if production
costs exceed gross proceeds for a computation period, the trust will receive no
payment for that period, and excess production costs will be carried over to
the following month as a production cost in determining the excess of gross
proceeds over production costs for that following month.

Gross proceeds and production costs are calculated on a cash basis, except
that certain costs, primarily ad valorem taxes and expenditures of a material
amount, may be determined on an accrual basis. For convenience in complying
with state tax laws, the net profits interests were created by two separate
transfers, one for each of Texas and New Mexico, the states in which the
underlying properties are located. Net proceeds are calculated separately for
the underlying properties covered by each transfer, so excess production costs
in one state do not reduce net proceeds from the other.

Although the transfer is effective September 1, 1999, no expenses incurred
in September, other than production and property taxes and transportation
costs, will be deducted in computing net proceeds.

Additional Provisions

If a controversy arises as to the sales price of any oil or natural gas,
then for purposes of determining gross proceeds:

. amounts withheld or placed in escrow by a purchaser are not considered
to be received by the owner of the underlying property until actually
collected;

. amounts received by the owner of the underlying property and promptly
deposited with a nonaffiliated escrow agent will not be considered to
have been received until disbursed to it by the escrow agent; and

37
<PAGE>

. amounts received by the owner of the underlying property and not
deposited with an escrow agent will be considered to have been received.

The trust is not liable to the owner of the underlying properties or the
operators for any production, operating, capital or other costs or liabilities
attributable to the underlying properties. The trustee is not obligated to
return any income received from the net profits interests. Any overpayments
made to the trust due to adjustments to prior calculations of net proceeds or
otherwise will reduce future amounts payable to the trust until Cross Timbers
recovers the overpayments plus interest at the prime rate.

The transfer documents permit Cross Timbers to transfer, without the consent
or approval of the trust unitholders, all or any part of the underlying
properties, subject to the net profits interests. The trust unitholders are not
entitled to any proceeds of a transfer. Following a transfer, the underlying
properties will continue to be subject to the net profits interests, and the
net proceeds attributable to the transferred property will be calculated
separately and paid by the transferee. As a result, any excess costs generated
from the transferred property will not reduce the net proceeds paid to the
trust from the underlying properties retained by Cross Timbers. The conveyances
have been recorded in the appropriate real property records to give notice of
the net profits interests to Cross Timbers' creditors and transferees.

As an operator of an underlying property, Cross Timbers may enter into
farmout, operating, participation, and other similar agreements covering the
property if Cross Timbers believes it to be advantageous to the working
interest owners of the property. The net profits interest held by the trust
would then be calculated using the gross proceeds and production costs
attributable to the interest retained by Cross Timbers under the agreement and
not on Cross Timbers' original interest before modification by the agreement.
Cross Timbers may enter into any of these agreements without the consent or
approval of the trustee or any trust unitholder. However, Cross Timbers'
interest in entering into any of these types of agreements should be parallel
with that of trust unitholders because of its retained interest in 20% of the
net proceeds from the underlying properties.

In addition, Cross Timbers may require the trust to sell for cash the net
profits interests that relate to underlying properties that Cross Timbers is
selling to an unaffiliated party. In this case, the properties sold to the
unaffiliated party would no longer be subject to the net profits interests, but
the trust would receive its pro rata share of the proceeds from the sale of the
properties. Furthermore, sales made under this provision may not exceed, in any
calendar year, 1% of the discounted present value of estimated future net
revenues for the proved reserves of the underlying properties allocated to the
trust's net profits interests, as contained in the most recent reserve report.
This provision is designed to allow Cross Timbers to dispose of marginal
properties that in most cases would not be contributing significant net
proceeds to the trust.

Cross Timbers' oil and natural gas leases require it to either abandon a
well or property that ceases to produce or is not capable of producing in
commercially paying quantities or further develop the property. Cross Timbers
will determine whether to abandon a well based on the well's history of costs
and revenues, projected future costs and revenues, and the economic feasibility
of increasing or establishing production from that property or reducing costs.
Upon termination of the lease, that portion of the net profits interests
relating to the abandoned property will be extinguished. If the property is
abandoned, neither Cross Timbers nor its affiliates will be able to reacquire
the property without repurchasing the interest from third parties or obtaining
a new lease.

Cross Timbers must maintain books and records sufficient to determine the
amounts payable for the net profits interests. Quarterly and annually, Cross
Timbers must deliver to the trustee a statement of the computation of the net
proceeds for each computation period. Cross Timbers will cause the annual
computation of net proceeds to be audited. The audit cost will be borne by the
trust.

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<PAGE>

FEDERAL INCOME TAX CONSEQUENCES

This section discusses all of the material federal income tax consequences
of the ownership and sale of trust units. Many aspects of federal income
taxation that may be relevant to a particular taxpayer or to certain types of
taxpayers subject to specific tax treatment are not addressed. In addition, the
tax laws can and do change regularly, and any future changes could have an
adverse effect on the ownership or sale of trust units. The trust will not
request advance rulings from the IRS with respect to the tax consequences of
ownership or sale of trust units. Instead the trust will rely on the opinion of
Butler & Binion, L.L.P. regarding the classification of the trust and certain
federal income tax consequences described below, which will be confirmed at the
time of the closing. Butler & Binion, L.L.P. believes that its opinion is in
accordance with the present position of the IRS regarding grantor trusts. The
tax opinion is not binding on the IRS or the courts, however, and no assurance
can be given that the IRS or the courts will agree with it.

The discussion contained in this section is based on current provisions of
the Internal Revenue Code, existing and proposed regulations, current
administrative rulings and court decisions, all of which are subject to changes
that may or may not be retroactively applied. Some of the applicable provisions
of the Internal Revenue Code have not been interpreted by the courts or the
IRS. Currently pending proposed federal tax legislation may also, under certain
circumstances, have a material effect on a trust unitholder.

AS A CONSEQUENCE, EACH PROSPECTIVE TRUST UNITHOLDER SHOULD CONSULT HIS OWN
TAX ADVISOR REGARDING HIS PARTICULAR CIRCUMSTANCES INCLUDING, PARTICULARLY, HIS
ALTERNATIVE MINIMUM TAX CIRCUMSTANCES.

Summary of Legal Opinions

Butler & Binion, L.L.P. is of the opinion that, for federal income tax
purposes:

. the trust will be treated as a grantor trust and not a business entity
taxable as a partnership or a corporation; and

. the income from the net profits interests will be royalty income subject
to an allowance for depletion.

Butler & Binion, L.L.P. advises that, unless noted otherwise, legal
conclusions stated in this section constitute its opinion.

Since no ruling is being requested from the IRS with respect to the trust or
trust unitholders, the IRS could challenge these opinions and statements, which
do not bind the IRS or the courts. The IRS could win in court if it did
challenge these matters.

Classification and Taxation of the Trust

In the opinion of Butler & Binion, L.L.P., under current law, the trust will
be taxable as a grantor trust and not as a business entity. As a grantor trust,
the trust will not be subject to tax at the trust level. For tax purposes, the
grantors, who in this case are the trust unitholders, will be considered to own
the trust's income and principal as though no trust were in existence. A
grantor trust simply files an information return, reporting all items of
income, credit or deduction which must be included in the tax returns of the
trust unitholders based on their respective accounting methods and taxable
years without regard to the accounting method and tax year of the trust. If,
contrary to the opinion of Butler & Binion, L.L.P., the trust was determined to
be a business entity, it would be taxable as a partnership unless it elected to
be taxed as a corporation. The principal tax consequence of the trust's being
treated as a partnership would be that it would report income on the accrual
method of accounting on a calendar year basis and all trust unitholders would
report their share of income from the trust in their tax year with which or
within which the tax year of the trust ends.

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<PAGE>

Direct Taxation of Trust Unitholders

Since the trust will be treated as a grantor trust for federal income tax
purposes, each trust unitholder will be taxed directly on his share of trust
income and will be entitled to claim his share of trust deductions. Each trust
unitholder will recognize taxable income when the trust receives or accrues it,
even if it is not distributed until later. Trust unitholders will report their
share of trust income and expenses consistent with their method of accounting
and their tax year.

Reporting of Trust Income and Expenses

The trustee intends to treat each royalty payment it receives as the taxable
income of the trust unitholders who own trust units on the day of receipt by
the trust. This will normally be the last business day of each calendar month.
Similarly, the trustee intends to pay expenses only on the day it receives a
royalty payment. All expenses paid on a royalty receipt day will be treated as
expenses of the trust unitholders who receive the distribution of that royalty
income. In most cases, therefore, the income and expenses of the trust for a
period will be reported as belonging to the trust unitholders who received a
distribution for that period. The amount of the distribution for a trust unit
will generally equal the net income allocated to that trust unit, determined
without regard to depletion. This correlation may not exist if, for example,
the trustee were to establish a cash reserve to pay estimated future expenses
or pay an expense with borrowed funds. Moreover, the IRS could attempt to
impute income to those persons who were trust unitholders when a royalty
payment on the net profits interests accrues. The IRS could also attempt to
disallow the deduction of administrative expenses to persons who were not trust
unitholders when the expenses were incurred. If the IRS were successful, trust
income might be taxed to trust unitholders other than those who received the
distribution relating to that income. Also, an accrual basis trust unitholder
might realize royalty income in a tax year earlier than that reported by the
trustee.

Royalty Income and Depletion

In the opinion of Butler & Binion, L.L.P., the income from the net profits
interests will be royalty income qualifying for an allowance for depletion. The
depletion allowance must be computed separately by each trust unitholder for
each oil or gas property, within the meaning of Section 614 of the Internal
Revenue Code. Butler & Binion, L.L.P. understands that the IRS is presently
taking the position that a net profits interest carved from multiple properties
is a single property for depletion purposes. Accordingly, the trust intends to
take the position that each net profits interest transferred to the trust by a
conveyance within each state is a single property for depletion purposes. It
will change this position if a different method were established by the IRS or
the courts.

The deduction for depletion is determined annually and is the greater of
cost depletion or, if allowable, percentage depletion. Royalty income from
production attributable to trust units owned by independent producers will
qualify for percentage depletion. In general, an individual or entity with
production of the equivalent of not more than 1,000 barrels of oil per day or
less is an independent producer. In general, percentage depletion is a
statutory allowance equal to 15% of the gross income from production from a
property. Percentage depletion is subject to a net income limitation of 100% of
the taxable income from the property, computed without regard to depletion
deductions and specified loss carrybacks. The depletion deduction attributable
to percentage depletion for a taxable year is limited to 65% of the taxpayer's
taxable income for the year before allowance of independent producers
percentage depletion and specified loss carrybacks. Unlike cost depletion,
percentage depletion is not limited to the adjusted tax basis of the property,
although, like cost depletion, it reduces the adjusted tax basis, but not below
zero.

Cross Timbers believes that trust unitholders who purchase trust units in
this offering will derive a substantially greater benefit from cost depletion
than from percentage depletion.

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<PAGE>

In computing cost depletion for each property for any year, the allowance
for the property is calculated by dividing the adjusted tax basis of the
property at the beginning of the year by the estimated total number of Bbls of
oil or Mcf of natural gas recoverable from the property. This amount is then
multiplied by the number of Bbls of oil or Mcf of natural gas produced and sold
from the property during the year. Cost depletion for a property cannot exceed
the adjusted tax basis of the property. Each trust unitholder will compute cost
depletion using his basis in his trust units. Information will be provided to
each trust unitholder reflecting how his basis should be allocated among each
property represented by his trust units. To the extent the depletion tax
deduction exceeds cash distributions per trust unit, that excess can be
deducted from the taxpayer's other sources of taxable income.

Other Income and Expenses

It is anticipated that the only other income of the trust will be interest
income earned on funds held as a reserve or pending distribution. Other
expenses of the trust will include any state and local taxes imposed on the
trust and administrative expenses of the trustee. Although the issue has not
been finally resolved, Butler & Binion, L.L.P. believes that all or
substantially all of those expenses are deductible in computing adjusted gross
income and, therefore, are not the type of miscellaneous itemized deductions
that are allowable only to the extent that they total more than 2% of adjusted
gross income.

Alternative Minimum Tax

All taxpayers are subject to an alternative minimum tax. Alternative minimum
taxable income is the taxpayer's taxable income recomputed with various
adjustments plus items of tax preference. In the case of persons other than
independent producers, tax preferences include the excess of percentage
depletion deductions for an oil or natural gas property over the adjusted tax
basis of the property. Alternative minimum tax is the excess of a taxpayer's
tentative minimum tax for a tax year over his regular tax for that year.

Non-Passive Activity Income and Loss

The income and expenses of the trust will not be taken into account in
computing the passive activity losses and income under Internal Revenue Code
Section 469 for a trust unitholder who acquires and holds trust units as an
investment.

Unrelated Business Taxable Income

Certain organizations that are generally exempt from tax under Internal
Revenue Code Section 501 are subject to tax on certain types of business income
defined in Section 512 as unrelated business income. In the opinion of Butler &
Binion, L.L.P., the income of the trust will not be unrelated business taxable
income so long as the trust units are not debt-financed property within the
meaning of Section 514(b). In general, a trust unit would be debt-financed if
the exempt organization incurs debt to acquire a trust unit or otherwise incurs
or maintains a debt that would not have been incurred or maintained if the
trust unit had not been acquired.

Sale of Trust Units; Depletable Basis

Generally, a trust unitholder will realize gain or loss on the sale or
exchange of his trust units measured by the difference between the amount
realized on the sale or exchange and his adjusted basis for such trust units. A
trust unitholder's basis in his trust units will be equal to the amount he paid
for the trust units, reduced by deductions for depletion claimed by the trust
unitholder, but not below zero. Except to the extent of the depletion recapture
amount explained below, gain or loss on

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<PAGE>

the sale of trust units by a trust unitholder who is an individual and who is
not a dealer in the trust units should be a long-term capital gain, taxable at
a maximum rate of 20%, if the trust units have been held for more than 12
months. Upon the sale of the trust units, a trust unitholder will be treated as
having sold his share of the net profits interests and must treat as ordinary
income his depletion recapture amount, which is an amount equal to the lesser
of the gain on such sale or the sum of the prior depletion deductions taken on
the trust units, but not in excess of the initial basis of the trust units. The
IRS could take the position that a portion of the sales proceeds is ordinary
income to the extent of any accrued income at the time of the sale that was
allocable to the trust units sold even though the income is not distributed to
the selling trust unitholder.

Taxation of Foreign Holders

Unless the election described below is made, a foreign holder, consisting of
a nonresident alien individual, foreign corporation, or foreign estate or
trust, will be subject to federal income withholding tax on his share of gross
royalty income from the net profits interests. The withholding tax will be at a
30% rate, or lower treaty rate if applicable and proper evidence is supplied to
the withholding agent, applied to the gross royalty income received by the
foreign holder without any deductions. Gain realized on a sale of a trust unit
by a foreign holder will be subject to federal income tax only if:

. the gain is otherwise effectively connected with business conducted by
the foreign holder in the United States;

. the foreign holder is an individual who is present in the United States
for at least 183 days in the year of the sale;

. the foreign holder has at any time during the five-year period ending on
the date of sale owned more than a 5% interest in the trust; or

. the trust units cease to be regularly traded on an established
securities exchange.

Gain realized by a foreign holder upon the sale by the trust of all or any
part of the net profits interests would be subject to federal income tax.

Trust unitholders who are foreign holders may elect under Internal Revenue
Code Section 871 or Section 882 or similar provisions of applicable treaties to
treat income attributable to the net profits interests as effectively connected
with the conduct of a trade or business in the United States. The foreign
holder will then be taxed at regular federal income tax rates on the net
income, rather than the gross income, attributable to the net profits
interests, including gain recognized on the disposition of trust units. Absent
a treaty exception, the net income of a corporate foreign holder which has made
such an election will also be subject to the branch profits tax imposed under
Section 884 to the extent not reinvested in a United States trade or business.
To claim the deductions allowable in computing net income, including cost
depletion, an electing foreign holder must file a United States income tax
return. To avoid tax withholding, an electing foreign holder must provide
proper certificates or other evidence to the withholding agent. Once made, the
election is irrevocable unless an applicable treaty allows the election to be
made annually. The election is applicable to all income and gain realized by
the foreign holder on any real property interests located in the United States,
including those interests held through partnerships, fixed investment trusts,
and other pass-through entities.

Backup Withholding

In general, distributions of trust income will not be subject to backup
withholding unless the trust unitholder is an individual or other noncorporate
taxpayer and he fails to comply with certain reporting procedures.

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<PAGE>

Tax Shelter Registration

Cross Timbers believes that the requirements for tax shelter registration
under Internal Revenue Code Section 6111 would be met if any trust unitholder's
investment base is substantially reduced by borrowing. To avoid any potential
penalty, the trust will be registered as a tax shelter with the IRS. The
trustee will furnish the tax shelter registration number to each trust
unitholder. Each trust unitholder must disclose this number by attaching Form
8271 to his tax return.

ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THIS
INVESTMENT OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED
BY THE IRS.

Reports

The trustee will furnish to trust unitholders of record quarterly, and to
all trust unitholders annually, reports to facilitate their computation of
their tax liability. See "Description of the Trust Units--Periodic Reports."

STATE TAX CONSIDERATIONS

The following is a brief discussion of the material state income taxes and
other state tax matters affecting the trust and the trust unitholders. Trust
unitholders are urged to consult their own legal and tax advisors as these
matters relate to their individual circumstances.

Income Tax Considerations

Texas presently does not have a state income tax on resident or nonresident
individuals. The Texas franchise tax imposes, in effect, an income tax on
corporations and limited liability companies which qualify to do business or
actually do business in Texas. Trust unitholders that are corporations or
limited liability companies will be subject to Texas franchise taxes on income
from the net profits interests.

New Mexico imposes income taxes upon resident and nonresidents. In the case
of nonresidents, income derived from tangible property within the state is
subject to tax. The income tax laws of New Mexico are based on federal income
tax laws. Thus, assuming the trust is taxed as a grantor trust for federal
income tax purposes, the trust unitholders will be subject to New Mexico income
tax on their share of income from New Mexico net profits interest. Nonresidents
of New Mexico will not be subject to New Mexico taxation with respect to gains
realized from sale or exchange of trust units. Trust unitholders may also be
subject to tax by the state in which they reside on income derived from the
trust.

The trustee will provide information concerning the trust sufficient to
identify the income of the Trust allocable to each state. Trust unitholders
should consult their own tax advisors to determine their income tax filing
requirements with respect to their share of income of the trust allocable to
states imposing an income tax on such income.

Probate and Property Considerations

The trust units may constitute real property or an interest in real property
under the inheritance, estate and probate laws of Texas and New Mexico. If the
trust units are held to be real property or an interest in real property under
the laws of a state in which the underlying properties are located, the trust
units may be subject to devolution, probate and administrative laws, and
inheritance or estate and similar taxes, under the laws of such state.

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<PAGE>

ERISA CONSIDERATIONS

The Employee Retirement Income Security Act of 1974 regulates pension,
profit-sharing and other employee benefit plans to which it applies. ERISA also
contains standards for persons who are fiduciaries of those plans. In addition,
the Internal Revenue Code provides similar requirements and standards which are
applicable to qualified plans, which include these types of plans and to
individual retirement accounts, whether or not subject to ERISA.

A fiduciary of a qualified plan should carefully consider fiduciary
standards under ERISA regarding the qualified plan's particular circumstances
before authorizing an investment in trust units. A fiduciary should consider

. whether the investment satisfies the prudence requirements of Section
404(a)(1)(B) of ERISA;

. whether the investment satisfies the diversification requirements of
Section 404(a)(1)(C) of ERISA; and

. whether the investment is in accordance with the documents and
instruments governing the qualified plan as required by Section
404(a)(1)(D) of ERISA.

A fiduciary should also consider whether an investment in trust units might
result in direct or indirect nonexempt prohibited transactions under Section
406 of ERISA and Internal Revenue Code Section 4975. In deciding whether an
investment involves a prohibited transaction, a fiduciary must determine
whether there are plan assets in the transaction. On November 13, 1986, the
Department of Labor published final regulations concerning whether or not a
qualified plan's assets would be deemed to include an interest in the
underlying assets of an entity for purposes of the reporting, disclosure and
fiduciary responsibility provisions of ERISA and analogous provisions of the
Internal Revenue Code. These regulations provide that the underlying assets of
an entity will not be considered "plan assets" if the equity interests in the
entity are a publicly offered security. Cross Timbers expects that at the time
of the sale of the trust units in this offering, they will be publicly offered
securities. Fiduciaries, however, will need to determine whether the
acquisition of trust units is a nonexempt prohibited transaction under the
general requirements of ERISA Section 406 and Internal Revenue Code Section
4975.

The prohibited transaction rules are complex, and persons involved in
prohibited transactions are subject to penalties. For that reason, potential
qualified plan investors should consult with their counsel to determine the
consequences under ERISA and the Internal Revenue Code of their acquisition and
ownership of trust units.

DESCRIPTION OF THE TRUST AGREEMENT

The following information and the information included under "Description of
the Trust Units" summarize the material information contained in the trust
agreement. This summary may not contain all the information that is important
to you. For more detailed provisions concerning the trust, you should read the
trust agreement. A copy of the trust agreement was filed as an exhibit to the
registration statement. See "Available Information."

Creation and Organization of the Trust; Amendments

Cross Timbers created the net profits interests and conveyed them to the
trust in exchange for 25,000,000 trust units.

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<PAGE>

Cross Timbers organized the trust under the Delaware Business Trust Act to
acquire and hold the net profits interests for the benefit of the trust
unitholders under an agreement between Cross Timbers, the trustee and the
Delaware trustee. The trustee has all the power to collect and distribute
proceeds received by the trust and to pay trust liabilities and expenses. The
Delaware trustee has only such powers as are required to be performed by a
Delaware resident trustee under the Delaware Business Trust Act.

Neither the trust nor the trustee has any control over or responsibility for
costs relating to the operation of the underlying properties. Neither Cross
Timbers nor other operators of the underlying properties have any contractual
commitments to the trust to conduct further drilling on or to maintain their
ownership interest in any of these properties. For a description of the
underlying properties and other information relating to them, see "The
Underlying Properties."

The beneficial interest in the trust is divided into 25,000,000 trust units.
Each of the trust units represents an equal undivided portion of the trust. You
will find additional information concerning the trust units in "Description of
the Trust Units."

Amendment of the trust indenture requires a vote of holders of 80% or more
of the outstanding trust units. However, no amendment may--

. increase the power of the trustee to engage in business or investment
activities;

. alter the rights of the trust unitholders as among themselves; or

. permit the trustee to distribute the net profits interests in kind.

Transfer of Additional Net Profits Interests

Cross Timbers will have the right, but no obligation, until November 30,
1999, to transfer additional net profits interests to the trust, so long as:

. the additional net profits interests are substantially identical in
terms to the net profits interests originally transferred to the trust;
and

. the additional net profits interests relate to increased working
interests acquired by Cross Timbers in the same oil and natural gas
properties in which the underlying properties are included.

For example, if one of the underlying properties is Cross Timbers' 60%
working interest in an oil and natural gas lease and Cross Timbers acquires an
additional 20% working interest in that lease prior to November 30, 1999, it
may transfer to the trust an 80% net profits interest in the additional working
interest. After the additional transfer, the net profits interest held by the
trust would relate to Cross Timbers' entire 80% working interest in that lease.

Cross Timbers will receive additional trust units if it transfers additional
net profits interests to the trust. The number of additional trust units issued
will be based on the amount of the discounted future net revenues from the
proved reserves added to the trust's net profits interests as the result of the
transfer. The value of the added proved reserves will be calculated based upon
the June 30, 1999 reserve report. A maximum of 3,000,000 additional trust units
can be issued to Cross Timbers if it conveys additional net profits interests
to the trust.

Cross Timbers periodically considers increasing its working interests in oil
and natural gas properties by purchasing interests from other working interest
owners. It has discussed purchases with large working interest owners, but it
is not currently engaged in negotiations or discussions regarding any purchase
of additional interests. There is no assurance that any acquisition of
additional interests will occur prior to November 30, 1999 or that Cross
Timbers will transfer any additional net profits interests to the trust.

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<PAGE>

Assets of the Trust

The assets of the trust consist of net profits interests and any cash and
temporary investments being held for the payment of expenses and liabilities
and for distribution to the trust unitholders.

Duties and Limited Powers of the Trustee

The duties of the trustee are specified in the trust indenture and by the
laws of the State of Delaware. The trustee's principal duties consist of:

. collecting income attributable to the net profits interests;

. paying expenses, charges and obligations of the trust from the trust's
income and assets;

. distributing distributable income to the trust unitholders; and

. taking any action it deems necessary and advisable to best achieve the
purposes of the trust.

If a trust liability is contingent or uncertain in amount or not yet
currently due and payable, the trustee may create a cash reserve to pay for the
liability. If the trustee determines that the cash on hand and the cash to be
received is insufficient to cover the trust's liability, the trustee may borrow
funds required to pay the liabilities. The trustee may borrow the funds from
any person, including itself. The trustee may also mortgage the assets of the
trust to secure payment of the indebtedness. If the trustee borrows funds, the
trust unitholders will not receive distributions until the borrowed funds are
repaid.

Each month, the trustee will pay trust obligations and expenses and
distribute to the trust unitholders the remaining proceeds received from the
net profits interests. The cash held by the trustee as a reserve against future
liabilities or for distribution at the next distribution date must be invested
in:

. interest bearing obligations of the United States government;

. repurchase agreements secured by interest-bearing obligations of the
United States government; or

. money market mutual funds.

The trust may not acquire any asset except the net profits interests, cash
and temporary cash investments, and it may not engage in any investment
activity except investing cash on hand.

At the request of Cross Timbers, the trustee must sell for cash net profits
interests relating to the underlying properties sold by Cross Timbers to an
unaffiliated third party. However, these sales are required only if in any
calendar year the net profits interests sold do not exceed 1% of the discounted
present value of estimated future net revenues for the proved reserves of the
trust's net profits interests, as contained in the most recent reserve report.

The trustee may sell the net profits interests in any of the following
circumstances:

. the sale does not involve a material part of the trust's assets and is
in the best interests of the trust unitholders. A majority of the trust
units represented at a meeting of the trust unitholders where a quorum
is present must approve the sale; or

. the sale constitutes a material part of the trust's assets and is in the
best interests of the trust unitholders. Holders representing 80% of the
outstanding trust units must approve the sale.

Upon dissolution of the trust the trustee must sell the net profits
interests. No trust unitholder approval is required. The trustee will
distribute to the trust unitholders the net proceeds from any sale of the net
profits interests.

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The trustee may require any trust unitholder to dispose of his trust units
if an administrative or judicial proceeding seeks to cancel or forfeit any of
the property in which the trust holds an interest because of the nationality or
any other status of that trust unitholder. If a trust unitholder fails to
dispose of his trust units, the trustee has the right to cancel all
certificates representing the trust units held by that trust unitholder. The
trustee would then issue a new certificate in the name of the trustee and sell
the trust units to an eligible third party. The trustee would pay to the former
trust unitholder the proceeds from the sale of those trust units.

The trustee may agree to modifications of the terms of the conveyances or to
settle disputes involving the conveyances. The trustee may not agree to
modifications or settle disputes involving the royalty part of the conveyances
if these actions would change the character of the net profits interests in
such a way that the net profits interests become working interests or that the
trust becomes an operating business.

Liabilities of the Trust

Because the trust does not conduct an active business and the trustee has
little power to incur obligations, Cross Timbers expects that the trust will
only incur liabilities for routine administrative expenses. These might include
the trustee's fees and accounting, engineering, legal and other professional
fees.

Responsibility and Liability of the Trustee

Under the trust agreement, the trustee is required to act in the best
interests of the trust unitholders at all times. The trustee must exercise the
same judgment and care in supervising and managing the trust's assets as
persons of ordinary prudence, discretion and intelligence would exercise.

The trustee will not make business decisions affecting the assets of the
trust. Therefore, substantially all of the trustee's functions under the trust
agreement are expected to be ministerial in nature. See "--Duties and Limited
Powers of the Trustee," above. Under Delaware law, the trustee may not profit
from any transaction with the trust. The trust agreement, however, provides
that the trustee may:

. charge for its services as trustee;

. retain funds to pay for future expenses and deposit them in its own
account;

. lend funds at commercial rates to the trust to pay the trust's expenses;
and

. seek reimbursement from the trust for its out-of-pocket expenses.

In discharging its duties to trust unitholders, the trustee may act in its
discretion and will be liable to the trust unitholders only for fraud, gross
negligence or acts or omissions in bad faith. The trustee will not be liable
for any act or omission of its agents or employees unless the trustee acted in
bad faith or with gross negligence in their selection and retention. The
trustee and the Delaware trustee will be indemnified for any liability or cost
that either incurs in the administration of the trust, except in cases of
fraud, gross negligence or bad faith. The trustees will have a lien on the
assets of the trust as security for this indemnification and compensation
earned as trustee. The trustees are entitled to indemnification from trust
assets or, to the extent that trust assets are insufficient, from Cross
Timbers. Trust unitholders will not be liable to the trustees for any
indemnification. See "Description of the Trust Units--Liability of Trust
Unitholders." The trustee must ensure that all contractual liabilities of the
trust are limited to the assets of the trust and will be liable for its failure
to do so.

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<PAGE>

Delaware law permits the trust unitholders to file actions seeking other
remedies, including:

. removal of the trustee;

. specific performance;

. appointment of a receiver;

. an accounting by the trustee to trust unitholders; and

. punitive damages.

Duration of the Trust; Sale of Net Profits Interests

The trust will dissolve if:

. the trust sells all of the net profits interests;

. annual gross proceeds attributable to the underlying properties are less
than $1 million for each of two consecutive years after 2000;

. the holders of 80% or more of the outstanding trust units vote in favor
of dissolution; or

. the trust violates the rule against perpetuities.

The trustee would then sell all of the trust's assets, either by private
sale or public auction, and distribute the net proceeds of the sale to the
trust unitholders.

Dispute Resolution

Any dispute, controversy or claim that may arise between Cross Timbers and
the trustee relating to the trust will be submitted to binding arbitration
before a tribunal of three arbitrators.

Compensation of the Trustees

The compensation of the trustee and the Delaware trustee will be paid out of
the trust's assets. See "The Trust."

Miscellaneous

The trustee may consult with counsel, accountants, geologists and engineers
and other parties the trustee believes to be qualified as experts on the
matters for which advice is sought. The trustee will be protected for any
action it takes in good faith reliance upon the opinion of the expert.

DESCRIPTION OF THE TRUST UNITS

Each trust unit is an undivided share of the beneficial interest in the
trust. Each trust unitholder has the same rights regarding each of his trust
units as every other trust unitholder has regarding his units. The trust will
have 25,000,000 trust units outstanding upon completion of this offering. In
addition, the trust may issue up to an additional 3,000,000 trust units to
Cross Timbers in exchange for the transfer by Cross Timbers to the trust of
additional net profits interests. See "Description of the Trust Agreement--
Transfer of Additional Net Profits Interests."

Distributions and Income Computations

Each month, the trustee will determine the amount of funds available for
distribution to the trust unitholders. Available funds are the excess cash
received by the trust from the net profits interests and other sources that
month, over the trust's liabilities for that month. Available funds will be
reduced by any cash the trustee decides to hold as a reserve against future
liabilities. Trust

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<PAGE>

unitholders that own their trust units on the monthly record date, which is the
end of the last business day of the month, will receive a pro-rata distribution
no later than 10 business days after the monthly record date. The first
distribution to trust unitholders purchasing trust units in this offering will
be made around December 15, 1999 to trust unitholders owning trust units on
November 30, 1999.

Unless otherwise advised by counsel or the IRS, the trustee will treat the
income and expenses of the trust for each month as belonging to the trust
unitholders of record on the monthly record date. Trust unitholders will
recognize income and expenses for tax purposes in the month the trust receives
or pays those amounts, rather than in the month the trust distributes them.
Minor variances may occur. For example, the trustee could establish a reserve
in one month that would not result in a tax deduction until a later month. The
trustee could also make a payment in one month that would be amortized for tax
purposes over several months. See "Federal Income Tax Consequences."

Transfer of Trust Units

Trust unitholders may transfer their trust units by sending their trust unit
certificate to the trustee along with a transfer form that is properly
completed. The trustee will not require either the transferor or transferee to
pay a service charge for any transfer of a trust unit. The trustee may require
payment of any tax or other governmental charge imposed for a transfer. The
trustee may treat the owner of any trust unit as shown by its records as the
owner of the trust unit. The trustee will not be considered to know about any
claim or demand on a trust unit by any party except the record owner. A person
who acquires a trust unit after any monthly record date will not be entitled to
the distribution relating to that monthly record date. Delaware law will govern
all matters affecting the title, ownership, warranty or transfer of trust
units.

Periodic Reports

The trustee will mail to trust unitholders quarterly reports showing the
assets, liabilities, receipts and disbursements of the trust for each quarter
except the fourth quarter. No later than 120 days following the end of each
year, the trustee will mail to the trust unitholders an annual report
containing audited financial statements of the trust.

The trustee will file all required trust federal and state income tax and
information returns. The trustee will prepare and mail to trust unitholders of
record quarterly, and to all trust unitholders annually, reports that trust
unitholders need to correctly report their share of the income and deductions
of the trust.

Each trust unitholder and his representatives may examine, for any proper
purpose, during reasonable business hours the records of the trust and the
trustee.

Liability of Trust Unitholders

Cross Timbers believes, however, that it is highly unlikely the trust would
incur such excess liabilities. As a royalty interest, the trust's net profits
interests are generally not subject to operational and environmental
liabilities and obligations. The trust conducts no active business that would
give rise to other business liabilities. The trustee has limited ability to
incur obligations on behalf of the trust. The trustee must not enter into a
contract without ensuring that all contractual liabilities of the

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<PAGE>

trust are limited to claims against the assets of the trust. The trustee will
be liable for its failure to do so. Because of the value and passive nature of
the trust assets and the restrictions in the indenture on the power of the
trustee to incur liabilities, Cross Timbers believes it is unlikely that a
trust unitholder would incur any liability from the trust based on its
ownership of trust units.

Voting Rights of Trust Unitholders

Trust unitholders have more limited voting rights than those of stockholders
of most public corporations. For example, there is no requirement for annual
meetings of trust unitholders or for annual or other periodic re-election of
the trustee.

The trustee or trust unitholders owning at least 15% of the outstanding
trust units may call meetings of trust unitholders. Meetings must be held in
Fort Worth, Texas. The trustee must send written notice of the time and place
of the meeting and the matters to be acted upon to all of the trust unitholders
at least 20 days and not more than 60 days before the meeting. Trust
unitholders representing a majority of trust units outstanding must be present
or represented to have a quorum. Each trust unitholder is entitled to one vote
for each trust unit owned.

Unless otherwise required by the trust indenture, a matter is approved by
the vote of a majority of the trust units held by the trust unitholders at a
meeting where there is a quorum. This is true, even if a majority of the total
trust units did not approve it. The affirmative vote of the holders of 80% of
the outstanding trust units is required to:

. terminate the trust;

. amend the trust indenture; or

. approve the sale of all or any material part of the assets of the trust.

The trustee must consent before all or any part of the trust assets can be
sold except in connection with the termination of the trust or limited sales
directed by Cross Timbers in conjunction with its sale of underlying
properties. The trustee may be removed, with or without cause, by the vote of
the holders of a majority of the outstanding trust units.

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Comparison of Trust Units and Common Stock

You should be aware of the following ways in which an investment in trust
units is different from an investment in common stock of a corporation.

<TABLE>
<CAPTION>
Trust Units Common Stock
----------- ------------
<S> <C> <C>
Voting.................. Limited voting rights. Corporate statutes provide
specific voting rights to
stockholders on electing
directors and major corporate
transactions.

Income Tax.............. The trust is not subject to Corporations are taxed on their
income tax; trust unitholders income, and their stockholders
are directly subject to income are taxed on dividends.
tax on their proportionate
shares of trust income,
adjusted for tax deductions.

Distributions........... Substantially all trust income Stockholders receive dividends
is distributed to trust at the discretion of the board
unitholders. of directors.

Business and Assets..... Interest is limited to specific A corporation conducts an
assets with a finite economic active business for an
life. unlimited term and can reinvest
its earnings and raise
additional capital to expand.

Limited Liability....... Trust unitholders have the same Corporate laws provide that a
limitations afforded corporate stockholder is not liable for
stockholders under Delaware the obligations and liabilities
law. Texas law, however, is not of the corporation, subject to
clear on limited liability of limited exceptions.
trust unitholders. However, due
to the size and nature of the
trust assets, liability in
excess of the trust
unitholders' investment is
extremely unlikely.

Fiduciary Duties........ The trustees have only such Officers and directors have a
duty to trust unitholders as is fiduciary duty of loyalty to
provided in the trust stockholders and a duty to use
agreement. Cross Timbers does due care in management and
not owe a fiduciary duty to the administration of a
trust, the trustees or trust corporation.
unitholders.
</TABLE>

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SELLING TRUST UNITHOLDER

Cross Timbers currently owns 100% of the 25,000,000 outstanding trust units.
It is offering 10,000,000 trust units in this offering, or 11,500,000 trust
units if the underwriters exercise their over-allotment option in full.

Assuming the sale of all trust units offered in this offering and the
exercise in full of the underwriters' over-allotment option, Cross Timbers will
have 13,500,000 trust units, or 54% of the outstanding trust units available
for future sale or distribution.

Cross Timbers has announced that it may form additional royalty trusts with
other properties. It may sell trust units, exchange them for oil and natural
gas properties or use them for other corporate purposes.

Prior to this offering there has been no public market for the trust units.
Cross Timbers cannot predict the effect on future market prices, if any, of
market sales of trust units or the availability of trust units for sale if it
disposes of its remaining trust units. Nevertheless, sales of substantial
amounts of trust units in the public market could adversely affect prevailing
market prices.

LEGAL MATTERS

Counsel for Cross Timbers, Kelly, Hart & Hallman, P.C., Fort Worth, Texas,
will give a legal opinion to the underwriters regarding matters related to this
offering. Richards, Layton & Finger, P.C., Wilmington, Delaware, special
Delaware counsel for Cross Timbers and the trust, will give a legal opinion as
to the validity of the trust units. Counsel for the underwriters, Andrews &
Kurth L.L.P., Houston, Texas, will give a legal opinion to the underwriters
regarding other matters related to this offering. Butler & Binion, L.L.P.,
Houston, Texas, will give the tax opinion described in the section of this
prospectus captioned "Federal Income Tax Consequences." Certain members of
Kelly, Hart & Hallman, P.C. currently own approximately 21,200 shares of common
stock of Cross Timbers, and certain partners of Butler & Binion, L.L.P. own
95,985 shares of common stock of Cross Timbers.

EXPERTS

Certain information appearing in this prospectus regarding the June 30, 1999
estimated quantities of reserves of the underlying properties and net profits
interests owned by the trust, the future net revenues from those reserves and
their present value is based on estimates of the reserves and present values
prepared by or derived from estimates prepared by Miller and Lents, Ltd.
independent petroleum engineers.

The statements of revenues and direct operating expenses of the Underlying
Properties, the statement of assets and trust corpus of Texas Permian Trust,
included in this prospectus have been audited by Arthur Andersen LLP,
independent public accountants, as indicated in their reports relating to those
financial statements, and are included in this prospectus in reliance upon the
authority of said firm as experts in accounting and auditing.

AVAILABLE INFORMATION

The trust and Cross Timbers have filed with the SEC in Washington, D.C. a
registration statement, including all amendments, under the Securities Act of
1933 relating to the trust units. As permitted by the rules and regulations of
the SEC, this prospectus does not contain all of the information contained in
the registration statement and the exhibits and schedules to the registration

52
<PAGE>

statement. In addition, Cross Timbers files annual, quarterly and current
reports, proxy statements and other information with the SEC. You may read and
copy the registration statement and any of Cross Timbers' reports, statements
or other information at the SEC's public reference room at 450 Fifth Street,
N.W., Washington, D.C. 20549. You may request copies of these documents, upon
payment of a duplicating fee, by writing to the SEC at the address in the
previous sentence. To obtain information on the operation of the public
reference rooms you may call the SEC at (800) SEC-0330. Cross Timbers' filings
are also available to the public on the SEC Internet Web site at
http://www.sec.gov.

The SEC allows Cross Timbers to "incorporate by reference" information Cross
Timbers files with it, which means that Cross Timbers can disclose important
information to you by referring you to those documents. The information
incorporated by reference is considered to be part of this prospectus.

Cross Timbers incorporates by reference in this prospectus the following
documents:

. its Annual Report on Form 10-K for the year ended December 31, 1998, as
amended by Amendment No. 1, filed April 9, 1999, and Amendment No. 2,
filed April 16, 1999;

. its Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999
and June 30, 1999;

. its Current Reports on Form 8-K filed on February 16, 1999 (Amendment
No. 2 to Report dated April 24, 1998), April 23, 1999 (Report dated
April 8, 1999), May 24, 1999 (Amendment No. 1 to Report dated April 8,
1999), May 27, 1999 (Report dated May 17, 1999), July 8, 1999 (Report
dated July 1, 1999), July 12, 1999 (Report dated July 7, 1999),
September 7, 1999 (Report dated August 30, 1999), September 30, 1999
(Report dated September 14, 1999) and September 30, 1999 (Report dated
September 15, 1999); and

. all other documents filed by it pursuant to Sections 13(a), 13(c), 14 or
15(d) of the Securities Exchange Act of 1934 after the date of this
prospectus and prior to termination of the offering of the trust units.

Information that Cross Timbers files later with the SEC will automatically
update the information in this prospectus. In all cases, you should rely on the
later information over different information included or incorporated by
reference in this prospectus.

As a recipient of this prospectus, you may request a copy of any document
Cross Timbers incorporates by reference, except exhibits to the documents that
are not specifically incorporated by reference, at no cost to you by writing or
calling Cross Timbers at 810 Houston Street, Suite 2000, Fort Worth, Texas
76102, Attention: Investor Relations, telephone (817) 870-2800.

53
<PAGE>

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

In this prospectus the following terms have the meanings specified below.

Bbl--One stock tank barrel, or 42 US gallons liquid volume, of crude oil or
other liquid hydrocarbons.

Bcf--One billion cubic feet of natural gas.

BOE--One barrel of oil equivalent, computed on an approximate energy
equivalent basis that one Bbl equals six Mcf.

Btu--A British Thermal Unit, a common unit of energy measurement.

Estimated Future Net Revenues--Also referred to as "estimated future net
cash flows." The result of applying current prices of oil and natural gas to
estimated future production from oil and natural gas proved reserves, reduced
by estimated future expenditures, based on current costs to be incurred, in
developing and producing the proved reserves, excluding overhead.

MBbl--One thousand Bbls.

MBOE--One thousand Bbls of oil equivalent (BOE).

Mcf--One thousand cubic feet of natural gas.

Mcfe--One thousand cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.

MMBtu--One million British Thermal Units (Btus).

MMcf--One million cubic feet of natural gas.

Natural Gas Revenue--Includes revenue related to the sale of natural gas,
natural gas liquids and plant products.

Net Oil and Natural Gas Wells or Acres--Determined by multiplying "gross"
oil and natural gas wells or acres by the interest in such wells or acres
represented by the underlying properties.

Net Profits Interest (also called a net overriding royalty interest)--A
nonoperating interest that creates a share in gross production from an
operating or working interest in oil and gas properties. The share is measured
by net profits from the sale of production.

NYMEX--New York Mercantile Exchange, where futures and options contracts for
the oil and natural gas industry and some precious metals are traded.

Oil Revenue--Includes revenue related to the sale of oil and condensate
production.

Overriding Royalty Interest--A royalty interest created or "carved" out of a
working or operating interest. Its term extends for the same term as the
working interest from which it is carved.

Proved Developed Reserves--Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.

54
<PAGE>

Proved Reserves--The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering data,
appear with reasonable certainty to be recoverable in the future from known oil
and natural gas reservoirs under existing economic and operating conditions.

The Securities and Exchange Commission definition of proved oil and gas
reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows:

Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the date
the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalations
based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion
delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any; and (B) the immediately adjoining portions not yet
drilled, but which can be reasonably judged as economically productive
on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the
reservoir.

(ii) Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are included
in the "proved" classification when successful testing by a pilot
project, or the operation of an installed program in the reservoir,
provides support for the engineering analysis on which the project or
program was based.

(iii) Estimates of proved reserves do not include the following: (A)
oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (B) crude oil, natural
gas, and natural gas liquids, the recovery of which is subject to
reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (C) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled prospects; and (D)
crude oil, natural gas, and natural gas liquids, that may be recovered
from oil shales, coal, gilsonite and other such sources.

Proved Undeveloped Reserves--Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required.

Reserve-to-Production Index--An estimate, expressed in years, of the total
estimated proved reserves attributable to a producing property divided by
production from the property for the 12 months preceding the date as of which
the proved reserves were estimated.

Royalty Interest--A real property interest entitling the owner to receive a
specified portion of the gross proceeds of the sale of oil and natural gas
production or, if the conveyance creating the interest provides, a specific
portion of oil and natural gas produced, without any deduction for the costs to
explore for, develop or produce the oil and natural gas. A royalty interest
owner has no right to consent to or approve the operation and development of
the property, while the owners of the working interest have the exclusive right
to exploit the mineral on the land.

Standardized Measure of Discounted Future Net Cash Flows--Also referred to
herein as "standardized measure." It is the present value of estimated future
net revenues computed by discounting estimated future net revenues at a rate of
10% annually.

55
<PAGE>

The Financial Accounting Standards Board requires disclosure of standardized
measure of discounted future net cash flows relating to proved oil and gas
reserve quantities, per paragraph 30 of Statement of Financial Accounting
Standards No. 69, as follows:

A standardized measure of discounted future net cash flows relating to
an enterprise's interests in (a) proved oil and gas reserves and (b) oil
and gas subject to purchase under long-term supply, purchase, or similar
agreements and contracts in which the enterprise participates in the
operation of the properties on which the oil or gas is located or otherwise
serves as the producer of those reserves shall be disclosed as of the end
of the year. The standardized measure of discounted future net cash flows
relating to those two types of interests in reserves may be combined for
reporting purposes. The following information shall be disclosed in the
aggregate and for each geographic area for which reserve quantities are
disclosed:

a. Future cash inflows. These shall be computed by applying year-end prices
of oil and gas relating to the enterprise's proved reserves to the year-
end quantities of those reserves. Future price changes shall be
considered only to the extent provided by contractual arrangements in
existence at year-end.

b. Future development and production costs. These costs shall be computed
by estimating the expenditures to be incurred in developing and
producing the proved oil and gas reserves at the end of the year, based
on year-end costs and assuming continuation of existing economic
conditions. If estimated development expenditures are significant, they
shall be presented separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying
the appropriate year-end statutory tax rates, with consideration of
future tax rates already legislated, to the future pretax net cash flows
relating to the enterprise's proved oil and gas reserves, less the tax
basis of the properties involved. The future income tax expenses shall
give effect to tax deductions, tax credits and allowances relating to
the enterprise's proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting
future development and production costs and future income tax expenses
from future cash inflows.

e. Discount. This amount shall be derived from using a discount rate of 10
percent a year to reflect the timing of the future net cash flows
relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is
the future net cash flows less the computed discount.

Working Interest (also called an operating interest)--A real property
interest entitling the owner to receive a specified percentage of the proceeds
of the sale of oil and natural gas production or a percentage of the
production, but requiring the owner of the working interest to bear the cost to
explore for, develop and produce such oil and natural gas. A working interest
owner who owns a portion of the working interest may participate either as
operator or by voting his percentage interest to approve or disapprove the
appointment of an operator and certain activities in connection with the
development and operation of a property.

56
<PAGE>

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<S> <C>
Underlying Properties
Report of Independent Public Accountants................................ F-2
Statements of Revenues and Direct Operating Expenses for the Years Ended
December 31, 1996, 1997 and 1998 and the Six Months Ended June 30, 1998
and 1999............................................................... F-3
Notes to Financial Statements........................................... F-4

Texas Permian Trust
Pro Forma Statement of Assets and Trust Corpus as of December 31, 1998.. F-7
Pro Forma Statement of Distributable Income for the Year Ended December
31, 1998............................................................... F-8
Pro Forma Statement of Distributable Income for the Six Months Ended
June 30, 1999.......................................................... F-9
Notes to Pro Forma Financial Statements................................. F-10
</TABLE>

F-1
<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

Cross Timbers Oil Company:

We have audited the accompanying statements of revenues and direct operating
expenses of the Underlying Properties of Cross Timbers Oil Company ("the
Company") for each of the three years in the period ended December 31, 1998.
These financial statements are the responsibility of the Company's management.
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 statement. 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.

In our opinion, the statements referred to above present fairly, in all
material respects, the revenues and direct operating expenses of the Underlying
Properties for each of the three years in the period ended December 31, 1998,
in conformity with generally accepted accounting principles.

ARTHUR ANDERSEN LLP

Fort Worth, Texas
August 4, 1999

F-2
<PAGE>

UNDERLYING PROPERTIES

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

For the Years Ended December 31, 1996, 1997 and 1998
and the Six Months Ended June 30, 1998 and 1999

<TABLE>
<CAPTION>
Six Months
Year Ended December 31, Ended June 30,
----------------------- ---------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
(unaudited)
(in thousands)
<S> <C> <C> <C> <C> <C>
Revenues
Oil sales............................ $47,663 $51,783 $35,316 $19,901 $18,898
Gas sales............................ 14,168 17,016 15,726 8,139 6,702
------- ------- ------- ------- -------
Total.............................. 61,831 68,799 51,042 28,040 25,600
------- ------- ------- ------- -------
Direct Operating Expenses
Production and property taxes and
transportation...................... 4,652 4,997 4,292 2,281 1,853
Production expenses.................. 15,377 15,597 15,842 7,159 7,018
------- ------- ------- ------- -------
Total.............................. 20,029 20,594 20,134 9,440 8,871
------- ------- ------- ------- -------
Excess of Revenues over Direct
Operating Expenses.................... $41,802 $48,205 $30,908 $18,600 $16,729
======= ======= ======= ======= =======
</TABLE>

See Accompanying Notes to Financial Statements.

F-3
<PAGE>

UNDERLYING PROPERTIES

NOTES TO FINANCIAL STATEMENTS

1. UNDERLYING PROPERTIES

The Underlying Properties are predominantly working interests in producing
properties currently owned by Cross Timbers Oil Company ("Company") in the
Permian Basin of Texas and New Mexico. The Company will convey 80% defined net
profits interests ("Net Profits Interests") in the Underlying Properties to the
Texas Permian Trust ("Trust") as of September 30, 1999.

All of the Underlying Properties were acquired by the Company from 1986
through July 1999. Significant property acquisitions were made by the Company
during the periods presented in the accompanying financial statements. The
accompanying statements include the historical revenues and direct operating
expenses from these acquired properties for all periods presented.

2. BASIS OF PRESENTATION

The statements of revenues and direct operating expenses of the Underlying
Properties were derived from the historical accounting records of the Company
(and prior owners for acquisitions occurring during the periods presented), and
are presented on the accrual basis of accounting before the effects of
conveyance of the Net Profits Interests. Direct operating expenses include
necessary production, marketing and transportation costs that are charged at
the well level, including direct labor costs, electricity, maintenance,
workover costs, insurance and property taxes. The statements do not include
depreciation, depletion and amortization, general and administrative or
interest expenses.

Royalty income of the Trust is determined based on the defined 80% net
profits interest percentage of net proceeds of the Underlying Properties. Net
proceeds for each year ended December 31 is computed based on Company cash
receipts and disbursements for the period from December of the prior year
through November. Net proceeds for each six-month period ended June 30 is
computed based on Company cash receipts and disbursements for the period
December of the prior year through May. The computation also includes the
following deductions for development costs and overhead on the properties.
Accordingly, royalty income of the Trust is materially different from the
excess of revenues over direct operating expenses from the Underlying
Properties.

<TABLE>
<CAPTION>
Six Months Ended
Year Ended December 31 June 30
----------------------- -----------------
1996 1997 1998 1998 1999
------- ------- ------- -------- --------
(in thousands)
<S> <C> <C> <C> <C> <C>
Development costs.................. $13,612 $36,494 $17,403 $ 9,596 $ 2,899
Overhead........................... 3,127 3,344 3,852 1,877 1,952
</TABLE>

3. RELATED PARTY TRANSACTIONS

The Company sells a significant portion of natural gas production from the
Underlying Properties, generally at amounts approximating monthly spot market
prices, to its wholly owned subsidiary, Cross Timbers Energy Services, Inc.
("CTES"), which markets natural gas to third parties. Sales to CTES from the
Underlying Properties were $2,714,000 in 1997, $8,068,000 in 1998, $3,324,000
in the six months ended June 30, 1998 and $4,142,000 in the six months ended
June 30, 1999. There were no sales to CTES from the Underlying Properties in
1996.

4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)

Proved oil and natural gas reserves of the Underlying Properties have been
estimated as of June 30, 1999 by independent petroleum engineers. The reserve
estimates provided for the Underlying Properties are before the effects of
conveying the defined net profits interests to the Trust. In accordance with
Statement of Financial Accounting Standards No. 69, estimates of future net
revenues from proved reserves have been prepared using period-end oil and
natural gas prices and current costs to produce and develop the proved
reserves, excluding overhead. The

F-4
<PAGE>

UNDERLYING PROPERTIES

NOTES TO FINANCIAL STATEMENTS--(Continued)

standardized measure of future net cash flows from oil and natural gas reserves
is calculated based on discounting such future net cash flows at an annual rate
of 10%. Year-end realized crude oil prices were $18.59 per barrel for 1995,
$24.46 per barrel for 1996, $15.67 per barrel for 1997, and $10.09 per barrel
for 1998. Year-end weighted average realized natural gas prices were $1.82 per
Mcf for 1995, $3.80 per Mcf for 1996, $2.58 per Mcf for 1997, and $1.91 per Mcf
for 1998. At June 30, 1999, the realized crude oil price was $17.95 and the
weighted average realized natural gas price was $2.24.

The standardized measure of future net cash flows is not intended to
represent the fair value of the Underlying Properties. Numerous uncertainties
are inherent in estimating volumes and values of proved reserves and in
projecting future production rates and timing of development expenditures. Such
reserve estimates are subject to change as additional information becomes
available. The reserves actually recovered and the timing of production may be
substantially different from the original estimates. Also, because natural gas
prices are influenced by seasonal demand, use of period-end prices, as required
by the Financial Accounting Standards Board, may not be representative in
estimating future revenues or reserve data.

Reserve estimates for Underlying Properties that were acquired between 1996
and 1999 are not available for periods prior to the date they were acquired by
the Company. Estimated proved reserves and the related standardized measure of
these properties were calculated as of December 31, 1995, 1996, 1997 and 1998,
by adding production prior to the date acquired to estimates as of the
acquisition dates.

Proved Reserves
<TABLE>
<CAPTION>
Oil (Bbls) Gas (Mcf)
---------- ---------
(in thousands)
<S> <C> <C>
Balance, December 31, 1995.............................. 32,501 78,444
Revisions............................................. 1,521 3,015
Extensions, discoveries and other additions........... 2,007 9,422
Production............................................ (2,404) (5,964)
------ -------
Balance, December 31, 1996.............................. 33,625 84,917
Revisions............................................. 146 (692)
Extensions, discoveries and other additions........... 8,737 27,958
Production............................................ (2,827) (6,503)
------ -------
Balance, December 31, 1997.............................. 39,681 105,680
Revisions............................................. (3,763) (5,708)
Extensions, discoveries and other additions........... 119 7,855
Production............................................ (2,859) (7,656)
------ -------
Balance, December 31, 1998.............................. 33,178 100,171
Revisions............................................. 5,312 3,621
Extensions, discoveries and other additions........... 992 748
Production............................................ (1,386) (3,478)
------ -------
Balance, June 30, 1999.................................. 38,096 101,062
====== =======
</TABLE>

Proved Developed Reserves
<TABLE>
<CAPTION>
Oil (Bbls) Gas (Mcf)
---------- ---------
(in thousands)
<S> <C> <C>
December 31, 1995....................................... 22,296 65,826
====== ======
December 31, 1996....................................... 23,594 58,557
====== ======
December 31, 1997....................................... 26,173 66,889
====== ======
December 31, 1998....................................... 22,188 63,962
====== ======
June 30, 1999........................................... 26,129 63,853
====== ======
</TABLE>

F-5
<PAGE>

UNDERLYING PROPERTIES

NOTES TO FINANCIAL STATEMENTS--(Continued)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves

<TABLE>
<CAPTION>
December 31,
---------------------------- June 30,
1996 1997 1998 1999
---------- -------- -------- --------
(in thousands)
<S> <C> <C> <C> <C>
Future cash inflows.................. $1,129,484 $874,289 $528,882 $901,449
Future costs:
Production......................... 376,163 351,447 241,325 343,966
Development........................ 46,210 80,968 59,138 65,420
---------- -------- -------- --------
Future net cash flows................ 707,111 441,874 228,419 492,063
10% discount factor.................. 305,282 206,817 113,310 240,467
---------- -------- -------- --------
Standardized measure of discounted
future net cash flows............... $ 401,829 $235,057 $115,109 $251,596
========== ======== ======== ========
</TABLE>

Changes in Standardized Measure of Discounted Future Net Cash Flows from
Proved Reserves

<TABLE>
<CAPTION>
Six
Months
Year Ended December 31, Ended
------------------------------ June 30,
1996 1997 1998 1999
-------- --------- --------- --------
(in thousands)
<S> <C> <C> <C> <C>
Standardized measure, beginning
of period....................... $180,349 $ 401,829 $ 235,057 $115,109
-------- --------- --------- --------
Revisions:
Prices and costs............... 223,080 (207,639) (124,998) 141,865
Quantity estimates............. 6,550 28,897 (15,088) 3,018
Accretion of discount.......... 16,051 35,925 21,759 4,885
Future development costs....... (14,565) (61,054) 8,185 (851)
Production rates and other..... (36) 104 (37) 51
-------- --------- --------- --------
Net revisions................ 231,080 (203,767) (110,179) 148,968
Extensions, discoveries and other
additions....................... 18,285 48,810 3,715 1,353
Production....................... (41,803) (48,206) (30,908) (16,729)
Development costs................ 13,918 36,391 17,424 2,895
-------- --------- --------- --------
Net change..................... 221,480 (166,772) (119,948) 136,487
-------- --------- --------- --------
Standardized measure, end of
period.......................... $401,829 $ 235,057 $ 115,109 $251,596
======== ========= ========= ========
</TABLE>

F-6
<PAGE>

TEXAS PERMIAN TRUST

PRO FORMA STATEMENT OF ASSETS AND TRUST CORPUS (Unaudited)

June 30, 1999

<TABLE>
<CAPTION>
(in thousands)
<S> <C>
Net profits interests in oil and gas properties................ $191,324
========
Trust Corpus (25,000,000 units of beneficial interest
authorized and outstanding)................................... $191,324
========
</TABLE>

See Accompanying Notes to Pro Forma Financial Statements.

F-7
<PAGE>

TEXAS PERMIAN TRUST

PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)

For the Year Ended December 31, 1998
(in thousands, except for per Unit amounts)

<TABLE>
<CAPTION>
Pro Forma
Adjustments (Note 2)
--------------------
Underlying Other Cash
Properties Costs (a) Basis (b) Pro Forma
---------- --------- --------- ---------
<S> <C> <C> <C> <C>
Revenues:
Oil................................. $35,316 $4,187 $39,503
Gas................................. 15,726 683 16,409
------- ------ -------
Total Revenues.................... 51,042 4,870 55,912
------- ------ -------
Direct Operating Expenses:
Production and property taxes and
transportation..................... 4,292 44 4,336
Production.......................... 15,842 (757) 15,085
------- ------ -------
Total............................. 20,134 (713) 19,421
------- ------ -------
Excess of revenues over direct operat-
ing expenses......................... $30,908 5,583 36,491
======= ======
Development costs..................... $17,403 5,825 23,228
Overhead.............................. 3,852 (27) 3,825
-------
Net proceeds......................................................... 9,438
Net profits percentage............................................... 80%
-------
Trust royalty income................................................. 7,550
Administrative expense............................................... 300
-------
Distributable income................................................. $ 7,250
=======
Distributable income per Unit (25,000,000 Trust Units issued and out-
standing--Note 1)................................................... $ 0.29
=======
</TABLE>

See Accompanying Notes to Pro Forma Financial Statements.

F-8
<PAGE>

TEXAS PERMIAN TRUST

PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)

For the Six Months Ended June 30, 1999
(in thousands, except for per Unit amounts)

<TABLE>
<CAPTION>
Pro Forma
Adjustments (Note 2)
--------------------
Underlying Other Cash
Properties Costs (a) Basis (b) Pro Forma
---------- --------- --------- ---------
<S> <C> <C> <C> <C>
Revenues:
Oil................................. $18,898 $(2,888) $16,010
Gas................................. 6,702 652 7,354
------- ------- -------
Total Revenues.................... 25,600 (2,236) 23,364
------- ------- -------
Direct Operating Expenses:
Production and property taxes and
transportation..................... 1,853 432 2,285
Production.......................... 7,018 811 7,829
------- ------- -------
Total............................. 8,871 1,243 10,114
------- ------- -------
Excess of revenues over direct operat-
ing expenses......................... $16,729 (3,479) 13,250
======= =======
Development costs..................... $2,899 4,469 7,368
Overhead.............................. 1,952 (17) 1,935
-------
Net proceeds......................................................... 3,947
Net profits percentage............................................... 80%
-------
Trust royalty income................................................. 3,158
Administrative expense............................................... 150
-------
Distributable income................................................. $ 3,008
=======
Distributable income per Unit (25,000,000 Trust Units issued and out-
standing--Note 1)................................................... $ 0.12
=======
</TABLE>

See Accompanying Notes to Pro Forma Financial Statements.

F-9
<PAGE>

TEXAS PERMIAN TRUST

NOTES TO PRO FORMA FINANCIAL STATEMENTS (Unaudited)

1. BASIS OF PRESENTATION

Texas Permian Trust ("Trust") will be created by Cross Timbers Oil Company
("Company") by conveying net profits interests ("Net Profits Interests") from
the Underlying Properties to the Trust in exchange for 25 million units of
beneficial interest in the Trust.

The pro forma statement of assets and trust corpus is presented as if the
Trust were created June 30, 1999. The Net Profits Interests are presented at
the Company's historical net book value at June 30, 1999 based on the
successful efforts method of accounting.

The pro forma statements of distributable income for the year ended December
31, 1998 and for the six months ended June 30, 1999 have been prepared from the
historical statements of revenues and direct operating expenses of the
Underlying Properties, adjusted to the cash basis, and based on the following
assumptions:

a. The Trust was formed and the Net Profits Interests were conveyed to
the Trust prior to December 1, 1997.

b. Net proceeds related to the Net Profits Interests are received and
recorded as royalty income by the Trust in the month following their
receipt by the Company from the Underlying Properties. Generally the Trust
will receive and record royalty income two months after the month of
production. This basis for recognizing royalty income differs from
generally accepted accounting principles which requires that revenues be
accrued in the month of production.

c. Royalty income is calculated based on 80% of the Net Proceeds from
the Underlying Properties. Net Proceeds is a defined term in the Net
Profits Interests conveyances to the Trust.

d. Administrative expense is estimated to be $300,000 for the year and
$150,000 for six months. Such expense generally would include Trustee fees
and costs incurred by the Trustee to administer the Trust and report Trust
results to Unitholders, including the expense of attorneys, independent
auditors, reservoir engineers, printing and mailing.

2. PRO FORMA ADJUSTMENTS

The following pro forma adjustments were made to the historical revenues and
direct operating expenses of the Underlying Properties to present Trust pro
forma distributable income for the year ended December 31, 1998 and the six
months ended June 30, 1999:

a. Historical development costs of $17,403,000 for 1998 and $2,899,000
for the six months ended June 30, 1999, and a Company overhead charge of
$3,852,000 for 1998 and $1,952,000 for the six months ended June 30, 1999.
The overhead charge is based on a monthly count of active wells operated by
the Company and is specified by the terms of the Net Profits Interests
conveyances to the Trust.

b. Adjustment from the accrual basis to the cash basis of accounting.
Pro forma distributable income for the year ended December 31, 1998 is
based on Net Proceeds received by the

F-10
<PAGE>

TEXAS PERMIAN TRUST

NOTES TO PRO FORMA FINANCIAL STATEMENTS (Unaudited)--(Continued)

Company in December 1997 through November 1998, and for the six months
ended June 30, 1999 is based on Net Proceeds received by the Company in
December 1998 through May 1999.

3. FEDERAL INCOME TAXES

As a grantor trust, the Trust will not be required to pay federal income
taxes. Accordingly, the accompanying pro forma statement of distributable
income does not include a provision for federal income taxes.

4. PRO FORMA SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

Proved oil and natural gas reserves of the Trust have been estimated as of
June 30, 1999 by independent petroleum engineers. In accordance with Statement
of Financial Accounting Standards No. 69, estimates of future net revenues from
proved reserves have been prepared using period-end oil and natural gas prices
and current costs to produce and develop the proved reserves. The standardized
measure of future net cash flows from oil and natural gas reserves is
calculated based on discounting such future net cash flows at an annual rate of
10%. Year-end realized crude oil prices were $15.67 and $10.09 per barrel at
December 31, 1997 and 1998, respectively, and $17.95 per barrel at June 30,
1999. Weighted average realized gas prices were $2.58 and $1.91 per Mcf at
December 31, 1997 and 1998, respectively, and $2.24 per Mcf at June 30, 1999.
As the Trust is not subject to taxation at the trust level, no provision is
included for federal income taxes.

Reserve quantities and revenues for the Net Profits Interests were estimated
from projections of reserves and revenues attributable to the Underlying
Properties. Since the Trust has a defined net profits interest, the Trust does
not own a specific ownership percentage of the oil and natural gas reserves or
production quantities. Accordingly, reserves and production allocated to the
Trust pertaining to its 80% net profits interest in the working interest
properties have effectively been reduced to reflect recovery of the Trust's 80%
portion of applicable production and development costs, excluding overhead and
trust administrative expenses. Because Trust reserve quantities are determined
using an allocation formula, any fluctuations in actual or assumed prices or
costs will result in revisions to the estimated reserve quantities allocated to
the Net Profits Interests.

The Net Profits Interests' 80% share of production and development costs are
netted in royalty income received by the Net Profits Interests. Accordingly,
these costs are not shown separately as future costs in calculating the
standardized measure. Only production taxes, calculated at the same rate as
incurred on the underlying properties, is included in future production costs
in calculating the standardized measure.

F-11
<PAGE>

TEXAS PERMIAN TRUST

NOTES TO PRO FORMA FINANCIAL STATEMENTS (Unaudited)--(Continued)

The standardized measure of future net cash flows is not intended to
represent the fair value of the Trust. Numerous uncertainties are inherent in
estimating volumes and values of proved reserves and in projecting future
production rates and timing of development expenditures. Such reserve estimates
are subject to change as additional information becomes available. The reserves
actually recovered and the timing of production may be substantially different
from the original estimates. Also, because natural gas prices are influenced by
seasonal demand, use of period-end prices, as required by the Financial
Accounting Standards Board, may not be representative in estimating future
revenues or reserve data.

<TABLE>
<CAPTION>
Oil (Bbls) Gas (Mcf)
------------ ----------
(in thousands)
<S> <C> <C>
Proved Reserves
Balance, January 1, 1998........................... 17,020 45,006
Revisions........................................ (4,483) (10,934)
Extensions, discoveries and other additions...... 52 3,404
Production....................................... (433) (1,067)
--------- --------
Balance, December 31, 1998......................... 12,156 36,409
Revisions........................................ 5,347 10,612
Extensions, discoveries and other additions...... 271 204
Production....................................... (205) (592)
--------- --------
Balance, June 30, 1999............................. 17,569 46,633
========= ========
Proved Developed Reserves
January 1, 1998.................................... 12,095 30,861
========= ========
December 31, 1998.................................. 8,751 25,193
========= ========
June 30, 1999...................................... 12,358 30,374
========= ========
Standardized Measure of Discounted Future Net Cash
Flows Relating to Proved Reserves
<CAPTION>
December 31, June 30,
1998 1999
------------ ----------
(in thousands)
<S> <C> <C>
Future cash inflows................................ $ 193,110 $416,083
Future production taxes and transportation......... 10,375 22,433
--------- --------
Future net cash flows.............................. 182,735 393,650
10% discount factor................................ 90,648 192,373
--------- --------
Standardized measure of discounted future net cash
flows............................................. $ 92,087 $201,277
========= ========
Changes in Standardized Measure of Discounted Fu-
ture Net Cash Flows from Proved Reserves
<CAPTION>
Year Ended Six Months
December 31, Ended June
1998 30, 1999
------------ ----------
(in thousands)
<S> <C> <C>
Standardized measure, beginning of period.......... $ 188,046 $ 92,087
Extensions, discoveries and other additions........ 2,972 1,082
Trust royalty income............................... (7,550) (3,158)
Changes in prices and other........................ (108,788) 107,358
Accretion of discount.............................. 17,407 3,908
--------- --------
Standardized measure, end of period................ $ 92,087 $201,277
========= ========
</TABLE>

F-12
<PAGE>

UNDERWRITING

Cross Timbers and the underwriters named below have entered into an
underwriting agreement with respect to the trust units being offered. Subject
to certain conditions, each underwriter has severally agreed to purchase the
number of trust units indicated in the following table. Goldman, Sachs & Co.,
Lehman Brothers Inc., Banc of America Securities LLC, Dain Rauscher Wessels, a
division of Dain Rauscher Incorporated, and Salomon Smith Barney Inc. are the
representatives of the underwriters.

<TABLE>
<CAPTION>
Number of
Underwriter Trust Units
----------- -----------
<S> <C>
Goldman, Sachs & Co................................................
Lehman Brothers Inc................................................
Banc of America Securities LLC.....................................
Dain Rauscher Wessels..............................................
Salomon Smith Barney Inc...........................................
----------
Total............................................................ 10,000,000
==========
</TABLE>

If the underwriters sell more trust units than the total number shown in the
table above, the underwriters have an option to buy up to an additional
1,500,000 trust units from Cross Timbers to cover such sales. They may exercise
that option for 30 days. If any trust units are purchased pursuant to this
option, the underwriters will severally purchase trust units in approximately
the same proportion shown in the table above.

The following table shows the per trust unit and total underwriting
discounts and commissions to be paid to the underwriters by Cross Timbers.
These amounts are shown assuming both no exercise and full exercise of the
underwriters' option to purchase 1,500,000 additional trust units.

<TABLE>
<CAPTION>
Paid by Cross Timbers
----------------------
No
Exercise Full Exercise
-------- -------------
<S> <C> <C>
Per trust unit...........................................
Total..................................................
</TABLE>

Trust units sold by the underwriters to the public will initially be offered
at the initial public offering price shown on the cover of this prospectus. Any
trust units sold by the underwriters to securities dealers may be sold at a
discount of up to $ . per trust unit from the initial public offering price.
Any such securities dealers may resell any trust units purchased from the
underwriters to certain other brokers or dealers at a discount of up to $ .
per trust unit from the initial public offering price. If all the trust units
are not sold at the initial offering price, the representatives may change the
offering price and the other selling terms.

Cross Timbers and its executive officers have agreed with the underwriters
not to dispose of or hedge any of their trust units or securities convertible
into or exchangeable for trust units during the period from the date of this
prospectus continuing through the date 180 days after the date of this
prospectus, except with the prior written consent of the representatives. This
agreement does not apply to any existing employee benefit plans.

Prior to the offering, there has been no public market for the trust units.
The initial public offering price will be negotiated among Cross Timbers and
the representatives. Among the factors considered in determining the initial
public offering price of the trust units, in addition to prevailing market
conditions, will be estimates of distributions to trust unitholders and overall
quality of the underlying properties.

U-1
<PAGE>

Cross Timbers will apply to list the trust units on the New York Stock
Exchange under the symbol "TPT." In order to meet one of the requirements for
listing the trust units on the New York Stock Exchange, the underwriters have
undertaken to sell lots of 100 or more trust units to a minimum of 400
beneficial holders to establish at least 1,000,000 trust units in the public
float having a minimum total public market value of $4,000,000.

In connection with the offering, the underwriters may purchase and sell
trust units in the open market. These transactions may include short sales,
stabilizing transactions and purchases to cover positions created by short
sales. Short sales involve the sale by the underwriters of a greater number of
trust units than they are required to purchase in the offering. Stabilizing
transactions consist of certain bids or purchases made for the purpose of
preventing or retarding a decline in the market price of the trust units while
the offering is in progress.

The underwriters also may impose a penalty bid. This occurs when a
particular underwriter repays to the underwriters a portion of the underwriting
discount it received because the representatives repurchased trust units sold
by or for the account of such underwriter in stabilizing or short covering
transactions.

These activities by the underwriters may stabilize, maintain or otherwise
affect the market price of the trust units. As a result, the price of the trust
units may be higher than the price that otherwise might exist in the open
market. If these activities are commenced, they may be discontinued by the
underwriters at any time. These transactions may be effected on the New York
Stock Exchange, in the over-the-counter market or otherwise.

The underwriters do not expect sales to discretionary accounts to exceed
five percent of the total number of trust units offered.

On July 1, 1999, Cross Timbers acquired, with an affiliate of Lehman
Brothers Inc., the common stock of Spring Holding Company, a private oil and
gas company located in Tulsa, Oklahoma, for total consideration of $85 million.
Cross Timbers and the Lehman Brothers affiliate each indirectly own, through a
holding company, 50% of Spring and have equal board representation and control
of Spring.

On August 2, 1999, Cross Timbers announced that it and the affiliate of
Lehman Brothers Inc. agreed to purchase certain oil and natural gas properties
from Ocean Energy, Inc. for $235.3 million in cash. Cross Timbers and the
Lehman Brothers affiliate will each contribute approximately $50 million in
cash to the holding company that will acquire the properties. The balance of
the purchase price will be financed through a loan arranged by affiliates of
Lehman Brothers Inc.

As a result of the Spring and Ocean transactions, Cross Timbers and the
Lehman Brothers affiliate will each own a 50% equity interest in the holding
company. At a later date, Cross Timbers will have the right to purchase, and
the Lehman Brothers affiliate will have the right to sell to Cross Timbers, the
affiliate's 50% equity interest.

Cross Timbers estimates that total expenses of the offering, other than
underwriting discounts and commissions, will be approximately $800,000.

Because it is expected that the National Association of Securities Dealers,
Inc. will view the trust units offered hereby as interests in a direct
participation program, the offering is being made in compliance with Rule 2810
of the NASD's Conduct Rules.

Cross Timbers and the trust have agreed to indemnify the several
underwriters against certain liabilities, including liabilities under the
Securities Act of 1933. The trust's indemnity obligations are limited to the
assets of the trust, and neither the trustee nor any unitholder will have any
obligation to indemnify the underwriters.

U-2
<PAGE>

EXHIBIT A

[MILLER AND LENTS LETTERHEAD]
August 4, 1999

Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, TX 76102

Re:Underlying Properties (100%)

Relating to the Texas Permian Trust
As of July 1, 1999
SEC Pricing Case

Gentlemen:

At your request, we estimated the proved reserves and future net revenue as
of July 1, 1999, attributable to the Cross Timbers Oil Company interest in
certain oil and gas properties prior to inclusion in the Texas Permian Trust,
i.e., Underlying Properties (100%). The properties are located in the Permian
Basin of West Texas and eastern New Mexico. The aggregate results of our
evaluations are as follows:

<TABLE>
<CAPTION>
Net Reserves as of
7/1/99 Future Net Revenue
----------------------------------------------------
Oil and
Condensate, Gas, Undiscounted, Discounted at
Reserves Category MBbls. MMcf M$ 10% Per Year, M$
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
New Mexico
- -----------------------------------------------------------------------------
Proved Developed
Producing 2,450.6 12,211.4 41,984.8 23,924.0
- -----------------------------------------------------------------------------
Proved Nonproducing 152.3 505.0 2,388.0 621.1
- -----------------------------------------------------------------------------
Proved Undeveloped 389.7 604.3 3,404.9 1,079.7
- -----------------------------------------------------------------------------
Subtotal 2,992.6 13,320.7 47,777.7 25,624.8
- -----------------------------------------------------------------------------
Texas
- -----------------------------------------------------------------------------
Proved Developed
Producing 21,595.4 46,211.4 270,070.0 168,648.8
- -----------------------------------------------------------------------------
Proved Nonproducing 1,931.0 4,924.9 27,728.3 10,040.1
- -----------------------------------------------------------------------------
Proved Undeveloped 11,577.4 36,605.1 146,486.8 47,282.3
- -----------------------------------------------------------------------------
Subtotal 35,103.8 87,741.4 444,285.1 225,971.2
- -----------------------------------------------------------------------------
Total Texas Permian
Trust
- -----------------------------------------------------------------------------
Proved Developed
Producing 24,046.0 58,422.8 312,054.8 192,572.8
- -----------------------------------------------------------------------------
Proved Nonproducing 2,083.3 5,429.9 30,116.3 10,661.2
- -----------------------------------------------------------------------------
Proved Undeveloped 11,967.1 37,209.4 149,891.7 48,362.0
- -----------------------------------------------------------------------------
TOTAL 38,096.4 101,062.1 492,062.8 251,596.0
</TABLE>
<PAGE>

[LOGO OF MILLER AND LENTS APPEARS HERE]

Cross Timbers Oil Company August 4, 1999
Page 2

These estimates were computed, at your instruction, by deducting estimated
production and net revenue for the period January 1, 1999 to June 30, 1999
from our January 1, 1999 estimates of proved reserves and future net revenue,
which we reported to you in our letter of March 22, 1999. In our judgment, the
projections of future oil and gas production employed in our March 22, 1999
report are, in the aggregate, representative of current trends. We base this
judgment on our review of the production trends for the University Block 9,
Prentice, Crockett, Cornell, Russell, and other areas that, in total,
represent 100 percent of the estimated proved developed producing reserves for
the Texas Permian Royalty Trust.

Our estimates also include additional interests in the Cornell Unit that
were acquired by Cross Timbers as of August 1, 1999. These reserves and net
revenue were evaluated as of August 1, 1999 and were added to the reserves and
net revenue of the other properties with no adjustment for the one-month
difference in the evaluation date.

We performed evaluations, which are designated as the SEC Pricing Case,
using price, expense, and gas production curtailment premises specified by you
and described in detail on Attachment 1.

Proved reserves and future net revenue were estimated in accordance with
the provisions contained in Securities and Exchange Commission Regulation S-X,
Rule 4-10. The Securities and Exchange Commission definition of proved
reserves is shown on Attachment 2. Estimates of future net revenue and
discounted future net revenue are not intended and should not be interpreted
to represent fair market values for the estimated reserves. We assumed that
abandonment costs would be equal to salvage values at abandonment. Future
costs, if any, for restoration of producing properties to satisfy
environmental standards were not deducted from future revenues as such
estimates are beyond the scope of this assignment.

Following Attachment 2 is a list of exhibits which include annual
projections of future production and net revenue for each state and reserve
category. Also included in the exhibits are one-line summaries for the total
trust and for each state showing the proved reserves and future net revenue
for the individual properties. Projections of individual property future
production and net revenue are included in separate volumes to this report.
These exhibits and volumes should not be relied upon independently of this
narrative.

The proved developed producing reserves and production forecasts were
estimated by production decline extrapolations, water-oil ratio trends, P/-Z
declines, or in a few cases, by volumetric calculations. For some properties
with insufficient performance history to establish trends, we estimated future
production by analogy with other properties with similar characteristics. The
past performance trends of many properties were influenced by production
curtailments, workovers, waterfloods, and/or infill drilling. Actual future
production may require that our estimated trends be significantly altered.

The estimated proved undeveloped reserves require significant capital
expenditures such as drilling and completion costs. The proved undeveloped
reserve estimates for infill wells are based on analogies to similar infill
wells in the same field and/or the production histories of offset wells in the
same field.
<PAGE>

[LOGO OF MILLER AND LENTS APPEARS HERE]

Cross Timbers Oil Company August 4, 1999
Page 3

Reserve estimates from volumetric calculations and from analogies are often
less certain than reserve estimates based on well performance obtained over a
period during which a substantial portion of the reserves was produced.

With the exception of a few properties, the data employed in our
determinations of proved reserves and future net income were provided by Cross
Timbers Oil Company. We obtained pressure and production information from
independent sources for some properties that had insufficient data from Cross
Timbers Oil Company to employ as bases for reserve estimates. The current
expenses for each lease were obtained from operating statements provided by
Cross Timbers Oil Company except for certain leases where Cross Timbers Oil
Company deducted items considered by Cross Timbers Oil Company to be
nonrecurring expenditures. No overhead was included for those properties
operated by Cross Timbers Oil Company. For some properties, such as large
waterfloods, Cross Timbers Oil Company assumed a decline in variable operating
costs due to depleting production which was derived by forecasting a decrease
in the property well count. None of the data provided to us by Cross Timbers
Oil Company, including, but not limited to, graphical representations and
tabulations of past production performance, well tests and pressures,
ownership interests, prices, and operating costs, were verified by us as such
was not within the scope of our assignment.

The evaluations presented in this report, with the exceptions of those
parameters specified by others, reflect our informed judgments based on
accepted standards of professional investigation but are subject to those
generally recognized uncertainties associated with interpretation of
geological, geophysical, and engineering information. Government policies and
market conditions different from those employed in this study may cause the
total quantity of oil or gas to be recovered, actual production rates, prices
received, or operating and capital costs to vary from those presented in this
report.

Our workpapers and data are in our files and available for review upon
request. If you have any questions regarding the above, or if we can be of
further assistance, please call.

Very truly yours,

MILLER AND LENTS, LTD.

By /s/ James C. Pearson
-------------------------
James C. Pearson
President
<PAGE>

Attachment 1

7-1-99

UNDERLYING PROPERTIES (100%)

RELATING TO THE

TEXAS PERMIAN TRUST

SEC PRICING CASE

<TABLE>
<S> <C>
A.Oil Price All oil/condensate prices held constant at $17.95 per
barrel through the life of the property.

B.Gas Price Estimated 7/1/99 price held constant through the life of
the property.

C.Operating Costs Current expenses held constant through the life of the
property.

D.Discount Rate 10% per year.
</TABLE>
<PAGE>

Attachment 2

Proved Reserves Definitions
In Accordance With
Securities and Exchange Commission Regulation S-X

Proved Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e.,
prices and costs as of the date the estimate is made. Prices include
consideration of changes in existing prices provided only by contractual
arrangements but not on escalations based upon future conditions.

1. Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any, and
(b) the immediately adjoining portions not yet drilled but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.

2. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in
the proved classification when successful testing by a pilot project or
the operation of an installed program in the reservoirs provides support
for the engineering analysis on which the project or program was based.

3. Estimates of proved reserves do not include the following:

a. Oil that may become available from known reservoirs but is
classified separately as indicated additional reserves.

b. Crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors.

c. Crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects.

d. Crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite, and other such sources.

Depending upon their status of development, proved reserves are subdivided
into proved developed reserves and proved undeveloped reserves.

Proved Developed Oil and Gas Reserves

Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the
application of fluid injection or other improved recovery techniques for
supplementing the natural forces and mechanisms of primary recovery should be
included as proved developed reserves only after testing by a pilot project or
after the operation of an installed program has confirmed through production
response that increased recovery will be achieved.

Proved Undeveloped Oil and Gas Reserves

Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where
a relatively major expenditure is required for recompletion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting
productive units that are reasonably certain of production when drilled.
Proved reserves for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of production from the
existing productive formation. Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.
<PAGE>

EXHIBIT B

[MILLER AND LENTS LETTERHEAD]
August 5, 1999

Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, TX 76102

Re:Texas Permian Trust
80% Net Profits Interests
As of July 1, 1999
SEC Pricing Case

Gentlemen:

At your request, we estimated the proved reserves and future net revenue as
of July 1, 1999, attributable to the Texas Permian Trust interest in certain
oil and gas properties. The properties are located in the Permian Basin of West
Texas and eastern New Mexico. The aggregate results of our evaluations are as
follows:

<TABLE>
<CAPTION>
Net Reserves as of
7/1/99 Future Net Revenue
---------------------------------------------------
Oil and
Condensate, Gas, Undiscounted, Discounted at
Reserves Category MBbls. MMcf M$ 10% Per Year, M$
- ----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
New Mexico
- ----------------------------------------------------------------------------
Proved Developed
Producing 1,211.5 6,036.7 33,587.8 19,139.3
- ----------------------------------------------------------------------------
Proved Nonproducing 78.0 258.5 1,910.4 496.9
- ----------------------------------------------------------------------------
Proved Undeveloped 134.8 209.0 2,723.9 863.7
- ----------------------------------------------------------------------------
Subtotal 1,424.3 6,504.2 38,222.1 20,499.9
- ----------------------------------------------------------------------------
Texas
- ----------------------------------------------------------------------------
Proved Developed
Producing 10,111.8 21,637.8 216,056.0 134,919.0
- ----------------------------------------------------------------------------
Proved Nonproducing 957.0 2,440.7 22,182.7 8,032.1
- ----------------------------------------------------------------------------
Proved Undeveloped 5,076.2 16,049.8 117,189.4 37,825.9
- ----------------------------------------------------------------------------
Subtotal 16,145.0 40,128.3 355,428.1 180,777.0
- ----------------------------------------------------------------------------
Total Texas Permian
Trust
- ----------------------------------------------------------------------------
Proved Developed
Producing 11,323.3 27,674.5 249,643.8 154,058.3
- ----------------------------------------------------------------------------
Proved Nonproducing 1,035.0 2,699.2 24,093.1 8,529.0
- ----------------------------------------------------------------------------
Proved Undeveloped 5,211.0 16,258.8 119,913.3 38,689.6
- ----------------------------------------------------------------------------
TOTAL 17,569.3 46,632.5 393,650.2 201,276.9
</TABLE>
<PAGE>

[LOGO OF MILLER AND LENTS APPEARS HERE]

Cross Timbers Oil Company August 5, 1999
Page 2

We performed evaluations, which are designated as the SEC Pricing Case,
using price, expense, and gas production curtailment premises specified by you
and described in detail on Attachment 1.

The Texas Permian Trust interests evaluated herein are comprised of an 80
percent net profits interest of certain Cross Timbers Oil Company properties
presented in our report, "Underlying Properties (100%) Relating to the Texas
Permian Trust, as of July 1, 1999, SEC Pricing Case," dated August 4, 1999,
incorporated herein by reference. At your instruction, the net oil and
condensate reserves and the net natural gas reserves attributable to the Texas
Permian Trust interests were computed from 80 percent of the Cross Timbers Oil
Company interests in those properties after adjustment for the estimated
reserves attributable to the future operating expenses and capital costs. As a
result of this procedure, a change in the future costs or prices or capital
expenditures different from those projected herein may result in a change in
the computed reserves to the net interests even if there are no revisions or
additions to the gross reserves attributable to the property.

[LOGO OF MILLER AND LENTS APPEARS HERE]

Cross Timbers Oil Company August 5, 1999
Page 3

Our workpapers and data are in our files and available for review upon
request. If you have any questions regarding the above, or if we can be of
further assistance, please call.

Very truly yours,

MILLER AND LENTS, LTD.

/s/ Larry M. Gring
By___________________________________
Larry M. Gring
Senior Vice President
<PAGE>

Attachment 1

7-1-99

TEXAS PERMIAN TRUST

80% NET PROFITS INTERESTS

SEC PRICING CASE

<TABLE>
<S> <C>
A.Oil Price All oil/condensate prices held constant at $17.95 per
barrel through the life of the property.

B.Gas Price Estimated 7/1/99 price held constant through the life of
the property.

C.Operating Costs Current expenses held constant through the life of the
property.

D.Discount Rate 10% per year.
</TABLE>
<PAGE>

Attachment 2

Proved Reserves Definitions
In Accordance With
Securities and Exchange Commission Regulation S-X

Proved Oil and Gas Reserves

3. Estimates of proved reserves do not include the following:

a. Oil that may become available from known reservoirs but is
classified separately as indicated additional reserves.

b. Crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors.

c. Crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects.

d. Crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite, and other such sources.

Depending upon their status of development, proved reserves are subdivided
into proved developed reserves and proved undeveloped reserves.

Proved Developed Oil and Gas Reserves

Proved Undeveloped Oil and Gas Reserves

- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------

No dealer, salesperson or other person is authorized to give any information
or to represent anything not contained in this prospectus. You must not rely
on any unauthorized information or representations. This prospectus is an
offer to sell the Trust Units offered hereby, but only under circumstances and
in jurisdictions where it is lawful to do so. The information contained in
this prospectus is current only as of its date.

---------------

TABLE OF CONTENTS

<TABLE>
<CAPTION>
Page
----
<S> <C>
Prospectus Summary........................................................ 3
Risk Factors.............................................................. 11
Forward-Looking Statements................................................ 15
Use of Proceeds........................................................... 15
Cross Timbers............................................................. 15
The Trust................................................................. 16
Projected Cash Distributions.............................................. 16
The Underlying Properties................................................. 22
Computation of Net Proceeds............................................... 36
Federal Income Tax Consequences........................................... 39
State Tax Considerations.................................................. 43
ERISA Considerations...................................................... 44
Description of the Trust Agreement........................................ 44
Description of the Trust Units............................................ 48
Selling Trust Unitholder.................................................. 52
Legal Matters............................................................. 52
Experts................................................................... 52
Available Information..................................................... 52
Glossary of Certain Oil and Natural Gas Terms............................. 54
Index to Financial Statements............................................. F-1
Underwriting.............................................................. U-1
Summary Reserve Reports............................................Exhibits A&B
</TABLE>

---------------

Through and including , 1999 (the 25th day after the date of this
prospectus), all dealers effecting transactions in these securities, whether
or not participating in this offering, may be required to deliver a
prospectus. This is in addition to a dealer's obligation to deliver a
prospectus when acting as an underwriter and with respect to an unsold
allotment or subscription.

- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------

10,000,000 Trust Units

Texas Permian Trust

---------------

PROSPECTUS

---------------

Goldman, Sachs & Co.

Lehman Brothers

Banc of America Securities LLC

Dain Rauscher Wessels
a division of Dain Rauscher Incorporated

Salomon Smith Barney

Representatives of the Underwriters

- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
<PAGE>

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

All capitalized terms used and not defined in Part II of this Registration
Statement shall have the meanings assigned to them in the Prospectus forming a
part of this Registration Statement.

Item 13. Other Expenses of Issuance and Distribution.

Except for the Registration Fee and the NASD Filing Fee, the following
itemized table sets forth estimates of those expenses payable by Cross Timbers
Oil Company ("the Company") in connection with the offer and sale of the
securities offered hereby:

<TABLE>
<S> <C>
Registration Fee................................................... $ 35,167
New York Stock Exchange Listing Fee................................ 70,000
NASD Filing Fee.................................................... 13,150
Printing and Engraving Expenses.................................... 175,000
Legal Fees and Expenses............................................ 150,000
Accountants' Fees and Expenses..................................... 50,000
Miscellaneous Fees and Expenses.................................... 306,683
--------
Total.............................................................. $800,000
========
</TABLE>

Item 14. Indemnification of Directors and Officers.

Section 6.02 of the Trust Agreement provides that the trustee will be
indemnified by the trust estate or, if trust assets are insufficient, by the
Company, against any and all liability and expenses incurred by it individually
or as trustee in the administration of the trust and the trust estate, except
for any liability or expense resulting from fraud or gross negligence or acts
or omissions in bad faith.

The Company is incorporated in Delaware. Under Section 145 of the Delaware
General Corporation Law (the "DGCL"), a Delaware corporation has the power,
under specified circumstances, to indemnify its directors, officers, employees
and agents in connection with actions, suits or proceedings brought against
them by a third party or in the right of the corporation, by reason that they
were or are such directors, officers, employees or agents, against expenses and
liabilities incurred in any such action, suit or proceeding so long as they
acted in good faith and in a manner that they reasonably believed to be in, or
not opposed to, the best interests of such corporation, and with respect to any
criminal action, that they had no reasonable cause to believe their conduct was
unlawful. With respect to suits by or in the right of such corporation,
however, indemnification is generally limited to attorneys' fees and other
expenses and is not available if such person is adjudged to be liable to such
corporation unless the court determines that indemnification is appropriate. A
Delaware corporation also has the power to purchase and maintain insurance for
such persons. Article Nine of the Certificate of Incorporation of the Company
permits indemnification of directors and officers to the fullest extent
permitted by Section 145 of the DGCL. Reference is made to the Certificate of
Incorporation of the Company.

Section 102(b)(7) of the DGCL provides that a certificate of incorporation
may contain a provision eliminating or limiting the personal liability of a
director to the corporation or its stockholders for monetary damages for breach
of fiduciary duty as a director, provided that such provisions may not
eliminate or limit the liability of a director (i) for any breach of the
director's duty of loyalty to the corporation or its stockholders, (ii) for
acts or omissions not in good faith or which involve intentional misconduct or
a knowing violation of law, (iii) under Section 174 (relating to liability for
unauthorized acquisitions or redemptions of, or dividends on, capital stock) of
the DGCL or (iv) for any transaction from which the director derived an
improper personal benefit. Article Ten of the Company's Certificate of
Incorporation contains such a provision.

II-1
<PAGE>

The above discussion of the Company's Certificate of Incorporation and of
Sections 102(b)(7) and 145 of the DGCL is not intended to be exhaustive and is
qualified in its entirety by such Certificate of Incorporation and statutes.

Additionally, the Company has acquired directors' and officers' insurance in
the amount of $10 million, which provides an exclusion from coverage for
liability under the federal securities laws.

Item 15. Recent Sales of Unregistered Securities.

None.

Item 16. Exhibits.

<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
1.1* --Form of Underwriting Agreement.
4.1* --Texas Permian Trust Agreement.
5.1* --Opinion of Richards, Layton & Finger, P.C., as to legality of the
securities registered hereby.
8.1* --Opinion of Butler & Binion, L.L.P. regarding federal income tax
matters.
8.2* --Opinion of Fred W. Schwendimann, P.A. regarding New Mexico State tax
matters.
10.1* --Form of 80% Net Overriding Royalty Conveyance--Texas.
10.2* --Form of 80% Net Overriding Royalty Conveyance--New Mexico.
15.1 --Awareness letter of Arthur Andersen LLP.
23.1 --Consent of Arthur Andersen LLP.
23.2+ --Consent of Miller and Lents, Ltd.
23.3* --Consent of Richards, Layton & Finger, P.C. (set forth in their
opinion filed as Exhibit 5.1).
23.4* --Consent of Butler & Binion, L.L.P. (set forth in their opinion filed
as Exhibit 8.1).
23.5* --Consent of Fred W. Schwendimann, P.A. (set forth in his opinion
filed as Exhibit 8.2).
24.1+ --Powers of attorney (set forth on the signature page of the original
filing).
</TABLE>
- --------

* To be filed by amendment.

+ Previously filed.

Item 17. Undertakings.

The Company hereby undertakes:

(a) that, for purposes of determining any liability under the Securities Act
of 1933, each filing of the Company's annual reports pursuant to Section 13(a)
or 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each
filing of an employee benefit plan's annual report pursuant to Section 15(d) of
the Securities Exchange Act of 1934) that is incorporated by reference in the
Registration Statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.

(b) to provide to the underwriters at the closing specified in the
underwriting agreement certificates in such denominations and registered in
such names as required by the underwriters to permit prompt delivery to each
purchaser.

(c) for purposes of determining any liability under the Securities Act of
1933, the information omitted from the form of prospectus filed as part of this
registration statement in reliance upon Rule 430A and contained in a form of
prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h)
under the Securities Act shall be deemed a part of this registration statement
as of the time it was declared effective.

II-2
<PAGE>

(d) for the purpose of determining any liability under the Securities Act of
1933, each post-effective amendment that contains a form of prospectus shall be
deemed to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed to be
the initial bona fide offering thereof.

Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
Registrant pursuant to the foregoing provisions, or otherwise, the trustee and
the Company have been advised that in the opinion of the Securities and
Exchange Commission such indemnification is against public policy as expressed
in the Securities Act of 1933 and is, therefore unenforceable. In the event
that claim for indemnification against such liabilities (other than the payment
by the trust or the Company of expenses incurred or paid by a director, officer
or controlling person in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the Trust or the Company will,
unless in the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the
Securities Act of 1933 and will be governed by the final adjudication of such
issue.

II-3
<PAGE>

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Company
certifies that it has reasonable grounds to believe that it meets all the
requirements for filing on Form S-3 and has duly caused this Amendment to
Registration Statement to be signed on its behalf by the undersigned, thereunto
duly authorized, in the City of Fort Worth, State of Texas, on November 12,
1999.

CROSS TIMBERS OIL COMPANY,
for itself and as sponsor of the

Texas Permian Trust,

a trust to be formed

By /s/ Bob R. Simpson
-----------------------------------
Bob R. Simpson
Chairman of the Board

Pursuant to the requirements of the Securities Act of 1933, this Amendment to
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.

<TABLE>
<S> <C> <C>
/s/ Bob R. Simpson Director, Chairman of the November 12, 1999
______________________________________ Board and Chief Executive
Bob R. Simpson Officer (Principal
Executive Officer)

/s/ Steffen E. Palko* Director, Vice Chairman of November 12, 1999
______________________________________ the Board and President
Steffen E. Palko

/s/ J. Luther King, Jr.* Director November 12, 1999
______________________________________
J. Luther King, Jr.

/s/ Jack P. Randall* Director November 12, 1999
______________________________________
Jack P. Randall

/s/ Scott G. Sherman* Director November 12, 1999
______________________________________
Scott G. Sherman
/s/ Louis G. Baldwin Executive Vice President November 12, 1999
______________________________________ and Chief Financial
Louis G. Baldwin Officer (Principal
Financial Officer)

/s/ Bennie G. Kniffen Senior Vice President and November 12, 1999
______________________________________ Controller (Principal
Bennie G. Kniffen Accounting Officer)
</TABLE>

*By /s/ Louis G. Baldwin
-------------------------------
Louis G. Baldwin
Attorney-in-Fact

II-4
<PAGE>

EXHIBIT INDEX

<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
15.1 --Awareness letter of Arthur Andersen LLP.
23.1 --Consent of Arthur Andersen LLP.
</TABLE>

<PAGE>

EXHIBIT 15.1

AWARENESS LETTER--UNAUDITED INTERIM FINANCIAL INFORMATION

Cross Timbers Oil Company
Fort Worth, Texas

We are aware that our reports dated May 10, 1999 and July 22, 1999, which
were included in the Cross Timbers Oil Company's Quarterly Reports on Form 10-Q
for the quarters ended March 31, 1999 and June 30, 1999, are being incorporated
by reference in the Company's Registration Statement on Form S-3.

We also are aware that the aforementioned reports, pursuant to Regulation C
under the Securities Act of 1933, are not considered a part of the Registration
Statement prepared or certified by our firm within the meaning of Sections 7
and 11 of that Act.

ARTHUR ANDERSEN LLP

Forth Worth, Texas

November 12, 1999

<PAGE>

EXHIBIT 23.1

INDEPENDENT PUBLIC ACCOUNTANTS' CONSENT

As independent public accountants, we hereby consent to the use in this
Registration Statement on Form S-1 of Texas Permian Trust and on Form S-3 of
Cross Timbers Oil Company (the Company) of our report dated August 4, 1999, and
to the incorporation by reference of our report dated March 12, 1999 included
in the Company's Form 10-K for the year ended December 31, 1998 and included in
Amendments No. 1 and No. 2 on Form 10-K/A for the year ended December 31, 1998,
and our report dated February 15, 1999 included in the Company's Form 8-K/A
Amendment No. 2 dated April 24, 1998, and to all references to our firm
included in this Registration Statement.

ARTHUR ANDERSEN LLP

Fort Worth, Texas

November 12, 1999