<PAGE>
As filed with the Securities and Exchange Commission on October 6, 2000.
Registration No. 333-56983
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------------
Amendment No. 1 to Form S-3
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
--------------
<TABLE>
<S> <C>
CROSS TIMBERS OIL COMPANY CROSS TIMBERS ROYALTY TRUST
(Exact name of co-registrant as specified in (Exact name of co-registrant as specified in
its charter) its charter)
Delaware Texas
(State or other jurisdiction of (State or other jurisdiction of
incorporation or organization) incorporation or organization)
75-2347769 75-6415930
(I.R.S. Employer Identification No.) (I.R.S. Employer Identification No.)
810 Houston Street, Suite 2000 Bank of America
Fort Worth, Texas 76102 P.O. Box 830650
(817) 870-2800 Dallas, Texas 75283-0650
(Address, including zip code, and telephone (214) 508-2440
number, including area code, of (Address, including zip code, and telephone
registrant's principal executive offices) number, including area code, of
Bob R. Simpson registrant's principal executive offices)
810 Houston Street, Suite 2000 Ron E. Hooper
Fort Worth, Texas 76102 901 Main Street
(817) 870-2800 Dallas, Texas 75202
(Name, address, including zip code, and (214) 508-2440
telephone number, including area code, of (Name, address, including zip code, and
agent for service) telephone number, including area code, of
agent for service)
</TABLE>
--------------
Copies to:
<TABLE>
<S> <C> <C>
F. Richard Bernasek, Esq. James M. Prince, Esq. Grant C. Lightle
Kelly, Hart & Hallman, P.C. Vinson & Elkins L.L.P. Thompson & Knight L.L.P.
1700 Pacific Ave., Suite
201 Main Street, Suite 2500 2300 First City Tower 3300
Fort Worth, Texas 76102 1001 Fannin Dallas, Texas 75201
(817) 332-2500 Houston, Texas 77002 (214) 969-1700
(713) 758-2222
</TABLE>
--------------
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. [_]
--------------
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. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
PROSPECTUS
Subject to completion, dated October 6, 2000
1,200,000 Trust Units
Cross Timbers Royalty Trust
------------------------------------------------------
This is a public offering of units of beneficial interest in the Cross
Timbers Royalty Trust. The offered units of Cross Timbers Royalty Trust are
currently outstanding. Cross Timbers Oil Company formed the trust as a grantor
trust in 1991 and is offering all of the trust units to be sold in this
offering, and Cross Timbers Oil will receive all proceeds from the offering.
The trust will not receive any proceeds from the offering.
There is currently a public market for the trust units. The trust units are
listed on the New York Stock Exchange under the symbol "CRT". On October 4,
2000, the last reported sale price of the trust units on the New York Stock
Exchange was $15.69 per unit.
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 Oil.
The Trust. The trust owns net profits interests in oil and natural gas
producing properties located in New Mexico, Texas and Oklahoma. The net
profits interests entitle the trust to receive 90% for royalty properties
and 75% for working interest properties of the net proceeds from the sale of
production from these oil and natural gas properties owned by Cross Timbers
Oil.
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.
INVESTING IN THE TRUST UNITS INVOLVES RISKS.
SEE "RISK FACTORS" BEGINNING ON PAGE 11.
<TABLE>
<CAPTION>
Per
Trust
Unit Total
----- ------
<S> <C> <C>
Public offering price............................................. $ $
Underwriting discount............................................. $ $
Proceeds, before expenses, to Cross Timbers Oil................... $ $
</TABLE>
Cross Timbers Oil has granted the underwriters a 30-day option to purchase up
to an additional 160,000 trust units on the same terms and conditions as set
forth above to cover over-allotments, if any.
Neither the Securities and Exchange Commission nor any other regulatory body
has approved or disapproved of these securities or determined that this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.
Lehman Brothers, on behalf of the underwriters, expects to deliver the trust
units to purchasers on or about , 2000.
------------------------------------------------------
Lehman Brothers
Dain Rauscher Wessels
Fidelity Capital Markets
a division of National Financial Services LLC
October , 2000
<PAGE>
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
Price Range of Trust Units and Distributions................... 15
Cross Timbers Oil Company...................................... 16
The Trust...................................................... 16
The Underlying Properties...................................... 16
Computation of Net Proceeds.................................... 28
Federal Income Tax Consequences................................ 31
State Tax Considerations....................................... 36
ERISA Considerations........................................... 37
Description of the Trust Indenture............................. 38
Description of the Trust Units................................. 42
Selling Trust Unitholder....................................... 45
Underwriting................................................... 45
Legal Matters.................................................. 47
Experts........................................................ 47
Available Information.......................................... 48
Glossary of Certain Oil and Natural Gas Terms.................. 49
Summary Reserve Reports........................................ Exhibits A and B
</TABLE>
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 December 31, 1999 included in this
prospectus. These estimates are contained in summaries by Miller and Lents of
the reserve reports as of December 31, 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.
Cross Timbers Royalty Trust
Cross Timbers Royalty Trust was formed in 1991 by Cross Timbers Oil Company.
Cross Timbers Oil conveyed to the trust net profits interests in oil and
natural gas producing properties located primarily in the San Juan Basin of New
Mexico, the Permian Basin of West Texas and in Oklahoma. We refer to Cross
Timbers Oil's interests in these properties as the underlying properties.
The net profits interests entitle the trust to receive 90% of net proceeds
from the sale of oil and natural gas from the underlying properties that are
included in each of three royalty interest conveyances, and 75% of net proceeds
from the sale of oil and natural gas from the underlying properties that are
included in each of two working interest conveyances. Each month Cross Timbers
Oil collects cash received from the sale of production and deducts property and
production taxes from all underlying properties, and deducts development costs,
production costs and overhead from only the underlying properties included in
the two working interest conveyances, and distributes net proceeds to the
trust.
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 Oil calculates the net proceeds separately for each of the
five conveyances of net profits interests in the underlying properties. Any
excess costs for underlying properties covered by one conveyance will not
reduce net proceeds calculated for properties covered by another conveyance.
The trust makes 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 Oil's Ownership Interests in the Trust and the Underlying
Properties
The underlying properties include royalty and overriding royalty interests
and working interests. Working interest properties bear the costs of
exploration, production and development while royalty and overriding royalty
interests do not. Net profits interests in the underlying properties were
3
<PAGE>
conveyed to the trust by Cross Timbers Oil in five separate property groups.
Three are 90% net profits interests in royalty and overriding royalty interest
groups, one in each of New Mexico, Oklahoma and Texas. The remaining two are
75% net profits interests in working interest groups in each of Oklahoma and
Texas.
Cross Timbers Oil's retained interest in the underlying properties entitles
it to retain all net proceeds from production after deducting the percentage
of net proceeds payable to the trust. Effectively, this entitles Cross Timbers
Oil to 10% for the 90% net profits interests properties and 25% for the 75%
net profits interests properties of the net proceeds from production. Cross
Timbers Oil is under no obligation to continue to own the underlying
properties, but currently intends to do so.
The following chart shows the relationship of Cross Timbers Oil, the trust
and the public trust unitholders after this offering, assuming full exercise
of the underwriters' overallotment option.
[FLOW CHART SHOWING THE RELATIONSHIP AMONG CROSS TIMBERS, THE TRUST AND THE
PUBLIC TRUST UNITHOLDERS APPEARS HERE]
Management of Cross Timbers Oil 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 Oil may form additional royalty trusts with other
properties.
The Underlying Properties
The producing underlying properties are long-lived properties, generally
with well-established production histories operated by major oil companies or
large independent energy companies. The underlying properties comprise Cross
Timbers Oil's interest in over 2,900 properties acquired by Cross Timbers Oil
from 1986 through 1990. As of December 31, 1999, approximately 72% of the
discounted estimated future net revenues attributable to the net profits
interests is allocable to the 90% net profits interests in royalty properties
and 28% is allocable to the 75% net profits interests in working interests
properties. Estimated proved reserves attributable to the underlying
properties are approximately 40% oil and 60% natural gas, based on the
discounted present value of estimated future net revenues as of December 31,
1999.
4
<PAGE>
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 December 31, 1999 was 12 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 1999. 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 96% of the discounted
present value of estimated future net revenues from the underlying properties.
Effect of Development
The underlying properties are Cross Timbers Oil's undivided interests in oil
and natural gas leases and the production from existing and future wells on
those leases. If the operators successfully drill additional wells on acreage
covered by these leases or successfully conduct other development activities,
those activities will enhance production from the underlying properties. Since
the trust units were initially sold to the public in February 1992, 50% of
production sold through December 31, 1999 was replaced by increased proved
reserves. The trust will benefit from increased production free of costs on the
90% net profits interests, but net of 75% of the development costs on the 75%
net profits interests. There can be no assurances that the operators will
continue to develop the underlying properties. Cross Timbers Oil operates an
immaterial amount of the underlying properties, based on the discounted present
value of estimated future net revenues.
Development History
Cross Timbers Oil estimates that royalty properties in the San Juan Basin
underlying certain of the 90% net profits interests include more than 2,000
gross (approximately 30 net) wells on 60,000 gross acres. Most of these wells
are operated by Amoco Production Company and Burlington Resources Oil & Gas
Company. Gas was first produced in the San Juan Basin in 1921, and today it is
considered to be the second largest gas producing area in the United States.
The San Juan Basin is characterized by multiple productive geologic formations,
including the Fruitland Coal, Pictured Cliffs, Mesaverde and Dakota.
Development has taken place in several phases, including 160-acre infill
drilling of the Mesaverde starting in 1977 and of the Dakota starting in 1979.
The most recent development phase from 1980 to the present has been in the
Fruitland Coal because of the incentive of the Section 29 federal income tax
credit applicable to gas produced from coal seam gas wells drilled prior to
January 1, 1993. However, advanced technology and improved operating procedures
have allowed further Fruitland Coal development after the expiration of the tax
credit drilling eligibility period. Operators have reported continued
development in additional formations and the use of enhanced recovery
techniques in existing productive formations, but it is not known if this
activity has affected or will affect Trust reserves or distributions.
5
<PAGE>
The underlying properties from which the 75% net profits interests were
carved are working interests in developed properties which have been undergoing
systematic secondary and enhanced recovery operations. Any increase or decrease
in costs from such activities directly affects the net proceeds payable to the
trust under the applicable 75% net profits interests. See "Risk Factors--
Development Costs." For a summary of development and operating costs over the
last five years associated with the working interest properties, see "Selected
Financial Data."
Ownership of the Underlying Properties
Cross Timbers Oil currently owns the underlying properties, subject to the
net profits interests, and is entitled to any proceeds received in excess of
the net proceeds paid to the trust. Cross Timbers Oil's duties under the
conveyances creating the net profits interests are ministerial in nature. For
the 90% net profits interests, Cross Timbers Oil is required to receive
payments from the sale of production from the underlying properties, deduct
taxes and pay 90% of such amount to the trustee for distribution to trust
unitholders. For the 75% net profits interests, Cross Timbers Oil is required
to receive payments representing its share of the sale of production, deduct
taxes and costs invoiced by the operators of such underlying properties and pay
75% of the net amount to the trust. Cross Timbers Oil may sell the underlying
properties, subject to and burdened by the net profits interests, without the
consent of the trustee or the trust unitholders. Following any such sale, the
purchaser of the underlying properties would be required to calculate and pay
to the trust the net proceeds and to otherwise perform all of Cross Timbers
Oil's duties under the conveyances. Cross Timbers Oil does not currently intend
to sell the underlying properties.
Recent Developments
The trust reported third quarter 2000 royalty income of $3,394,310.
Distributable income for the quarter was $3,346,332 or $0.557722 per unit of
beneficial interest. The distributable income for the quarter includes
approximately $.04 per unit related to revenue overpaid to the trust for the
distribution declared in September. Cross Timbers Oil expects the correction of
this overpayment to affect distributable income in the fourth quarter 2000.
6
<PAGE>
Proved Reserves
Based on the reserve report as of December 31, 1999, estimated proved
reserves of the underlying properties are approximately 40% oil and 60% natural
gas on a Mcfe basis. The following table provides estimated proved oil and
natural gas reserves for the underlying properties, and the estimated proved
reserves and undiscounted and discounted estimated future net revenues for the
net profits interests. Proved reserves in the table are based on oil and
natural gas prices realized by Cross Timbers Oil as of December 31, 1999, which
averaged $23.93 per Bbl of oil (based on a West Texas Intermediate posted price
of $22.75), and $2.19 per Mcf of natural gas. Gas equivalents in the table are
the sum of Mcf of gas and the Mcfe of the stated Bbls of oil, 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 for presentation of proved reserves. Reserve estimates are subject
to revision.
<TABLE>
<CAPTION>
Underlying
Properties Net Profits Interests
--------------- ---------------------------------------
Estimated Future
Net Revenues from
Proved Reserves Proved Reserves Proved Reserves
--------------- --------------- -----------------------
Natural Natural
Oil Gas Oil Gas
(MBbls) (MMcf) (MBbls) (MMcf) Undiscounted Discounted
------- ------- ------- ------- ------------ ----------
(in thousands, except
per unit data)
<S> <C> <C> <C> <C> <C> <C>
90% Net Profits
Interests
San Juan Basin
Conventional.......... 82 26,531 74 23,878 $ 55,075 $23,281
Coal seam............. -- 5,992 -- 5,393 8,681 5,642
----- ------ ----- ------ -------- -------
Total............... 82 32,523 74 29,271 63,756 28,923
Other New Mexico....... 146 346 131 291 3,459 2,063
Texas.................. 497 4,235 444 3,619 17,831 9,799
Oklahoma............... 87 2,057 70 1,744 5,105 2,793
----- ------ ----- ------ -------- -------
Total............... 812 39,161 719 34,925 90,151 43,578
----- ------ ----- ------ -------- -------
75% Net Profits
Interests (a)
Texas.................. 1,921 848 892 394 20,881 9,718
Oklahoma............... 1,727 589 587 194 13,302 7,330
----- ------ ----- ------ -------- -------
Total............... 3,648 1,437 1,479 588 34,183 17,048
----- ------ ----- ------ -------- -------
Total Net Profits
Interests.............. 4,460 40,598 2,198 35,513 $124,334 $60,626
===== ====== ===== ====== ======== =======
Per Trust Unit.......... $ 20.72 $ 10.10
======== =======
</TABLE>
--------
(a) Proved reserves for the 75% net profits interests owned by the trust are
calculated by subtracting from 75% of proved reserves of the underlying
properties that are working interests, reserve quantities of a sufficient
value to pay 75% of the future estimated costs, before overhead and trust
administrative expenses, that are deducted in calculating net proceeds.
Accordingly, proved reserves for the 75% 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>
Selected Financial Data
The following table provides oil and natural gas sales volumes and summary
financial data relating to the trust and underlying properties for each of the
years in the five-year period ended December 31, 1999 and for each of the six-
month periods ended June 30, 1999 and 2000.
<TABLE>
<CAPTION>
Six Months Ended
June 30
Year Ended December 31 (Unaudited)
-------------------------------------------------- --------------------
1995 1996 1997 1998 1999 1999 2000
--------- --------- --------- --------- --------- --------- ---------
(in thousands, except per unit data)
<S> <C> <C> <C> <C> <C> <C> <C>
Statement of
Distributable Income
Data
Royalty income.......... $ 5,740 $ 8,270 $ 10,550 $ 7,080 $ 6,691 $ 2,693 $ 4,830
Interest income......... 8 11 16 10 11 4 10
--------- --------- --------- --------- --------- --------- ---------
Total income.......... 5,748 8,281 10,566 7,090 6,702 2,697 4,840
Administration expense.. 170 204 159 163 152 85 115
--------- --------- --------- --------- --------- --------- ---------
Distributable income.... $ 5,578 $ 8,077 $ 10,407 $ 6,927 $ 6,550 $ 2,612 $ 4,725
========= ========= ========= ========= ========= ========= =========
Distributable income per
trust unit............. $0.929705 $1.346162 $1.734541 $1.154555 $1.091635 $0.435295 $0.787571
========= ========= ========= ========= ========= ========= =========
Section 29 tax credit
per trust unit......... $0.180246 $0.189374 $0.212340 $0.162287 $0.157564 $0.081657 $ 0.063(a)
========= ========= ========= ========= ========= ========= =========
Computation of Royalty
Income
90% Net Profits
Interests
Revenues
Oil sales.............. $ 1,380 $ 1,663 $ 1,853 $ 1,412 $ 1,347 $ 550 $ 1,094
Natural gas sales...... 4,410 6,414 8,798 6,955 7,133 3,008 4,270
--------- --------- --------- --------- --------- --------- ---------
Total................. 5,790 8,077 10,651 8,367 8,480 3,558 5,364
--------- --------- --------- --------- --------- --------- ---------
Costs--Taxes,
transportation and
other................. 682 777 967 849 1,444 569 879
--------- --------- --------- --------- --------- --------- ---------
Net proceeds.......... 5,108 7,300 9,684 7,518 7,036 2,989 4,485
--------- --------- --------- --------- --------- --------- ---------
Royalty Income--90% net
profits interests..... 4,597 6,570 8,716 6,766 6,332 2,690 4,036
--------- --------- --------- --------- --------- --------- ---------
75% Net Profits
Interests
Revenues
Oil sales.............. 5,339 6,461 6,289 3,844 3,842 1,436 3,224
Natural gas sales...... 154 212 226 139 127 43 118
--------- --------- --------- --------- --------- --------- ---------
Total................. 5,493 6,673 6,515 3,983 3,969 1,479 3,342
--------- --------- --------- --------- --------- --------- ---------
Costs
Taxes, transportation
and other............. 599 535 556 347 165 61 311
Production expense..... 2,620 2,707 2,645 2,580 2,388 1,195 1,241
Development costs...... 750 1,164 869 1,143 736 441 348
Net (excess costs)
excess cost recovery
and interest.......... -- -- -- (505) 201 (222) 384
--------- --------- --------- --------- --------- --------- ---------
Total................. 3,969 4,406 4,070 3,565 3,490 1,475 2,284
--------- --------- --------- --------- --------- --------- ---------
Net proceeds.......... 1,524 2,267 2,445 418 479 4 1,058
--------- --------- --------- --------- --------- --------- ---------
Royalty Income--75% net
profits interests..... 1,143 1,700 1,834 314 359 3 794
--------- --------- --------- --------- --------- --------- ---------
Total Royalty Income.. $ 5,740 $ 8,270 $ 10,550 $ 7,080 $ 6,691 $ 2,693 $ 4,830
========= ========= ========= ========= ========= ========= =========
Oil and Gas Sales
Volumes
Net Profits Interests
Oil sales (Bbls)....... 149 168 177 105 98 39 72
Natural gas sales
(Mcf)................. 2,992 3,829 3,878 3,019 3,163 1,502 1,359
Underlying Properties
Oil sales (Bbls)....... 441 437 424 392 349 175 169
Natural gas sales
(Mcf)................. 3,513 4,385 4,419 3,502 3,643 1,735 1,567
Average Prices
Oil per Bbl............ $ 15.25 $ 18.60 $ 19.20 $ 13.40 $ 14.88 $ 11.36 $ 25.48
Natural Gas per Mcf.... $ 1.30 $ 1.51 $ 2.04 $ 2.03 $ 1.99 $ 1.76 $ 2.80
</TABLE>
--------
(a) Estimated based on qualifying sales volumes through June 30, 2000 and the
factors used in the calculation of the 1999 Section 29 tax credit. The
actual 2000 Section 29 credit will be determined in February 2001.
8
<PAGE>
Historical Trust Distributions and Related Data
Trust units were initially sold to the public at $10.00 per unit in February
1992. Annual cash distributions paid, Section 29 federal income tax credits
available per trust unit, cost depletion factor (the percentage of trust unit
cost allowed as a cost depletion deduction for federal income tax purposes),
and the total present value (discounted at 10%) of estimated future net
revenues at December 31 of each year were as follows:
<TABLE>
<CAPTION>
Total Present
Section 29 Value of
Tax Credits Estimated
Cash Per Cost Future Net
Distributions Trust Depletion Revenues
per Trust Unit Unit Factor at December 31
-------------- ----------- --------- --------------
<S> <C> <C> <C> <C>
1992.................... $ 1.217402 $0.092 7.0% $54,589,000
1993.................... 1.282923 0.150 7.0 40,911,000
1994.................... 1.124811 0.203 8.5 41,241,000
1995.................... 0.929705 0.180 8.1 42,243,000
1996.................... 1.346162 0.189 9.5 76,847,000
1997.................... 1.734541 0.212 8.8 43,496,000
1998.................... 1.154555 0.162 8.0 35,776,000
1999.................... 1.091635 0.158 8.9 60,626,000
2000 (through
September)............. 1.345293 0.082(a) 7.7 --
---------- ------
$11.227027 $1.428
========== ======
</TABLE>
--------
(a) Estimated based on qualifying sales volumes attributable to distributions
through August 2000 and the factors used in the calculation of the 1999
Section 29 credit. The actual 2000 Section 29 credit will be determined in
February 2001.
Posted West Texas Intermediate oil prices and wellhead gas prices used in
calculating the estimated future net revenues were:
<TABLE>
<CAPTION>
December 31, Oil Natural Gas
------------ ------ -----------
<S> <C> <C>
1992......................................................... $18.00 $1.69
1993......................................................... 12.50 1.75
1994......................................................... 16.00 1.51
1995......................................................... 18.00 1.37
1996......................................................... 24.25 2.64
1997......................................................... 15.50 1.76
1998......................................................... 9.50 1.88
1999......................................................... 22.75 2.19
</TABLE>
9
<PAGE>
The Offering
Trust units offered by Cross
Timbers Oil...................... 1,200,000
Trust units outstanding..........
6,000,000
Cross Timbers Oil ownership
after the offering...............
160,000 trust units if the underwriters
do not exercise their over-allotment
option; none if they exercise their
option in full.
Use of proceeds..................
Cross Timbers Oil will receive all net
proceeds from this offering, which will
be used to repay indebtedness under its
revolving credit facility.
NYSE symbol......................
CRT
Investing in the Trust Units
Investing in these trust units differs from investing in corporate stock
in the following ways:
. trust unitholders are owed a fiduciary duty by the trustee, but not
by Cross Timbers Oil;
. 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 natural gas and, to a lesser extent, oil. 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 Oil. 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 predictability of future
cash distributions to trust unitholders.
Trust Distributions Are Affected by Production and Development Costs for the
75% Net Profits Interests Properties
Production and development costs on the 75% net profits interests 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 the 75% net profits interests
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.
The 75% net profits interests properties include all of Cross Timbers Oil's
working interests in seven producing properties located in Texas and Oklahoma.
Each of these properties has been unitized for the purpose of conducting
secondary recovery operations to increase or maintain production levels. Under
the terms of the agreements establishing the units, if the requisite percentage
of working interest owners in the unit approves a development project, all such
owners are required to pay their proportionate share of development costs. The
working interests owned by Cross Timbers Oil do not constitute a sufficient
interest in any of the units to veto or control a development decision. Under
the terms of the conveyances creating the 75% net profits interests, the trust
will not be liable for any development costs, but the amount of development
costs will be deducted when computing net proceeds payable to the trust.
The net proceeds payable to the trust for production from the underlying
properties will be reduced by all related development costs, and, if materially
increased development activities were to
11
<PAGE>
occur, distributions from the trust could be materially and adversely affected.
If these development costs and production expenses exceed the proceeds of
production from the properties, the trust would not receive payments from the
properties until the proceeds from production exceed the cumulative excess of
costs and expenses plus accrued interest during the deficit period. The
computation of net proceeds is made separately for each conveyance creating the
75% net profits interests from working interest properties in Texas and
Oklahoma. Any excess development costs and production expenses on working
interest properties in one state will not reduce the net proceeds payable from
working interest properties in the other state.
For example, as a result of low oil prices and a development project to
convert one of the Texas properties underlying the 75% net profits interests to
carbon dioxide injection, costs exceeded revenues by a total of $832,330 for
the period from April 1998 through April 1999 and in August 1999. These excess
costs and related accrued interest were recovered from May 1999 through May
2000. After two years of excess cost recoveries, the Texas 75% net profits
interests began contributing to trust royalty income in May 2000. Primarily
because of lower oil prices and reduced production resulting from mechanical
complications on one of the underlying properties, costs also exceeded revenues
for five monthly net proceeds calculations for the Oklahoma 75% net profits
interests from August 1998 through September 1999. These costs were recovered
from October 1998 through October 1999. Excess development costs occurred twice
prior to 1998. Development costs and production expenses exceeded the proceeds
of production from the working interest properties in Texas from January to
April 1994; these excess costs were recovered from May to August 1994.
Development costs and production expenses exceeded the proceeds of production
from the working interest properties in Oklahoma from October 1993 to June
1994; these excess costs were recovered from July to September 1994.
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.
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.
12
<PAGE>
Neither the Trust Nor Cross Timbers Oil Controls Operations and Development
Neither the trustee nor the trust unitholders can influence or control the
operation or future development of the underlying properties. Because Cross
Timbers Oil does not operate most of the underlying properties, it is unable to
significantly influence the operations or future development of the underlying
properties.
The current operators of the underlying properties are under no obligation
to continue operating the properties. Neither the trustee nor trust unitholders
have the right to replace an operator.
Cross Timbers Oil May Transfer or Abandon Underlying Properties
Although it has no current intention of selling any of the underlying
properties, Cross Timbers Oil 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
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 Oil's obligations
relating to calculating, reporting and paying to the trust net profits on that
portion of the underlying properties, and Cross Timbers Oil would have no
continuing obligation to the trust for those properties.
The operator, Cross Timbers Oil 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 terminate 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. Sale of all the net profits interests will terminate the
trust. The net proceeds of any sale will be distributed to the trust
unitholders.
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.
Trust Unitholders Will Have Limited Ability to Enforce Rights
The trust indenture and related trust law permit the trustee and the trust
to sue Cross Timbers Oil or any other future owner of the underlying properties
to compel it to fulfill the terms of the conveyance of the net profits
interests. If the trustee does not take appropriate action to enforce
provisions of the conveyance, 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 Oil
or any future owner of the underlying properties.
Limited Liability of Trust Unitholders Is Uncertain
Texas law is not clear whether a trust unitholder could be held personally
liable for the trust's liabilities if those liabilities exceeded the value of
the trust's assets.
Cross Timbers Oil believes it is highly unlikely the trust could incur such
excess liabilities. As a royalty interest, the trust's net profit interest is
generally not subject to operational and environmental
13
<PAGE>
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.
Cross Timbers Oil's Liability to the Trust Is Limited
The net profits interest conveyances provide that Cross Timbers Oil 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 Oil. 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."
An IRS Ruling Has Not Been Requested
The trust has received an opinion of tax counsel that the trust is a
"grantor trust" for federal income tax purposes. This means that:
. you will be taxed directly on your pro rata share of the net income of
the trust, regardless of whether all of that net income is distributed
to you;
. you will be allowed depletion deductions equal to the greater of
percentage depletion or cost depletion, computed on the tax basis of
your trust units, and your pro rata share of other deductions of the
trust; and
. you will be allowed the tax credit of your share of qualifying coal seam
gas production provided under Section 29 of the Internal Revenue Code,
subject to limitations described in this prospectus.
Tax counsel believes that its opinion is in agreement with the present
position of the IRS regarding grantor trusts. Neither Cross Timbers Oil nor the
trustee has requested a ruling from the IRS regarding these tax questions.
There can be no assurances that Cross Timbers Oil or the trust would be granted
such a ruling if requested or that the IRS will not change its position in the
future. The tax treatment of the trust and trust unitholders could be different
from that described above if the IRS were to successfully challenge that
treatment. See "Federal Income Tax Consequences."
14
<PAGE>
FORWARD-LOOKING STATEMENTS
Some statements made by Cross Timbers Oil 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 Oil will receive all proceeds from the sale of trust units after
deducting underwriting discounts and costs of the offering paid by Cross
Timbers Oil. The net proceeds will be approximately $ million and will
increase to $ million if the underwriters exercise their over-allotment
option in full. Cross Timbers Oil intends to apply the net proceeds from the
offering to repay outstanding indebtedness under its bank revolving credit
facility. The facility bears interest at a floating rate, currently 8.4%, and
matures on May 12, 2005. Cross Timbers Oil incurred its bank debt to finance
acquisitions of oil and natural gas producing properties, repurchases of Cross
Timbers Oil common stock, and development expenditures.
PRICE RANGE OF TRUST UNITS AND DISTRIBUTIONS
The trust units are traded on the NYSE under the symbol "CRT." The following
table sets forth, for the periods indicated, the high and low prices of the
trust units as reported on the New York Stock Exchange Composite Tape and the
amount of distributions per trust unit.
<TABLE>
<CAPTION>
Sales Price Cash
--------------- Distributions
Low High per Trust Unit
------- ------- --------------
<S> <C> <C> <C>
1997:
First Quarter............................... $13.625 $15.750 $.511589
Second Quarter.............................. 14.250 16.750 .536106
Third Quarter............................... 16.000 17.750 .353022
Fourth Quarter.............................. 16.000 18.500 .333824
1998:
First Quarter............................... $13.563 $17.250 $.382494
Second Quarter.............................. 13.500 17.688 .267899
Third Quarter............................... 11.063 14.250 .272882
Fourth Quarter.............................. 7.625 12.688 .231280
1999:
First Quarter............................... $ 8.438 $10.125 $.240065
Second Quarter.............................. 9.000 10.750 .195230
Third Quarter............................... 10.125 13.875 .276342
Fourth Quarter.............................. 9.250 12.750 .379998
2000:
First Quarter............................... $ 9.500 $14.750 $.383466
Second Quarter.............................. 10.000 14.375 .404105
Third Quarter .............................. 13.000 17.000 .557722
Fourth Quarter (through October 4).......... 15.063 16.188 --
</TABLE>
The closing price of the trust units on the NYSE on October 4, 2000, was
$15.69. As of October 4, 2000, there were 6,000,000 trust units outstanding and
approximately 162 trust unitholders of record.
15
<PAGE>
CROSS TIMBERS OIL COMPANY
Cross Timbers Oil 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 Oil organized the trust
and conveyed the net profits interests to the trust in 1991 in exchange for all
of the trust units. Cross Timbers Oil continues to own the underlying
properties from which the net profits interests were conveyed. Cross Timbers
Oil purchased a total of 1,360,000 trust units during the period from July 1996
to January 1998 for an average price of $13.75 per unit.
Management of Cross Timbers Oil has been involved in the formation of three
other publicly traded royalty trusts. The trusts are the Hugoton Royalty Trust
formed in 1998, and the Permian Basin Royalty Trust and the San Juan Basin
Royalty Trust both formed in 1980. Cross Timbers Oil may form additional trusts
with other properties.
THE TRUST
The trust was created under the laws of the State of Texas in 1991. In
connection with the formation of the trust, Cross Timbers Oil conveyed to the
trust the net profits interests in the underlying properties in exchange for
all 6,000,000 of the trust units.
The trustee is Bank of America, N.A. 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 pays the trustee a fee of less than $10,000 per year. The trust
will also incur legal, accounting and engineering fees, printing costs and
other expenses that are deducted from the net proceeds received by the trust
before distributions are made to trust unitholders. These costs and expenses
totaled $152,000 for the year ended December 31, 1999.
THE UNDERLYING PROPERTIES
Cross Timbers Oil owns the underlying properties, subject to the net profits
interests conveyed to the trust. Cross Timbers Oil may, at any time, sell all
or any portion of the underlying properties, subject to the net profits
interests. It has no current intention to do so.
The underlying properties include Cross Timbers Oil's undivided interests in
specified oil and natural gas leases and the production from existing and
future wells on those leases. Cross Timbers Oil's 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 or
maintain revenues subject to the trust's net profits interest.
Cross Timbers Oil's interests comprising the underlying properties are
referred to in the oil and natural gas industry as an "overriding royalty",
"royalty" and 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. Overriding
royalty and royalty interests are interests in oil and gas
16
<PAGE>
properties entitling the owner to receive a specified percentage of production,
with no requirement for the owner to bear the cost of exploration, development
or production.
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. Major
oil companies and large independent producers operate most of the underlying
properties. A lease operator has significant influence on operations of the
lease, including the timing and amount of discretionary expenditures for
operational and development activities.
Historical Results from the Underlying Properties
The following table provides oil and natural gas sales volumes, average
sales prices, revenues, direct operating expenses and development costs
relating to the underlying properties for 1997, 1998 and 1999 and the six-month
periods ended June 30, 1999 and 2000.
<TABLE>
<CAPTION>
Six Months Ended
June 30
Year Ended December 31 (Unaudited)
------------------------- ------------------
1997 1998 1999 1999 2000
-------- ------- ------- -------- --------
(in thousands, except per unit data)
<S> <C> <C> <C> <C> <C>
Computation of Royalty
Income
90% Net Profits
Interests
Revenues
Oil sales.............. $ 1,853 $ 1,412 $ 1,347 $ 550 $ 1,094
Natural gas sales...... 8,798 6,955 7,133 3,008 4,270
-------- ------- ------- -------- --------
Total................. 10,651 8,367 8,480 3,558 5,364
-------- ------- ------- -------- --------
Costs--Taxes,
transportation and
other ................ 967 849 1,444 569 879
-------- ------- ------- -------- --------
Net proceeds.......... 9,684 7,518 7,036 2,989 4,485
-------- ------- ------- -------- --------
Royalty Income--90% net
profits interests..... 8,716 6,766 6,332 2,690 4,036
-------- ------- ------- -------- --------
75% Net Profits
Interests
Revenues
Oil sales.............. 6,289 3,844 3,842 1,436 3,224
Natural gas sales...... 226 139 127 43 118
-------- ------- ------- -------- --------
Total................. 6,515 3,983 3,969 1,479 3,342
-------- ------- ------- -------- --------
Costs
Taxes, transportation
and other............. 556 347 165 61 311
Production and other
expenses.............. 2,645 2,580 2,388 1,195 1,241
Development costs...... 869 1,143 736 441 348
Excess costs........... -- (515) (433) (363) --
Recovery of excess
costs and accrued
interest.............. -- 10 634 141 384
-------- ------- ------- -------- --------
Total................. 4,070 3,565 3,490 1,475 2,284
-------- ------- ------- -------- --------
Net proceeds.......... 2,445 418 479 4 1,058
-------- ------- ------- -------- --------
Royalty Income--75% net
profits interests..... 1,834 314 359 3 794
-------- ------- ------- -------- --------
Total Royalty Income.. $ 10,550 $ 7,080 $ 6,691 $ 2,693 $ 4,830
======== ======= ======= ======== ========
Underlying Properties
Oil and Gas Sales
Volumes
Oil sales (Bbls)....... 424 392 349 175 169
Natural gas sales
(Mcf)................. 4,419 3,502 3,643 1,735 1,567
Total sales in Mcfe.... 6,963 5,854 5,737 2,785 2,581
Average Prices
Oil per Bbl............ $ 19.20 $ 13.40 $ 14.88 $ 11.36 $ 25.48
Natural gas per Mcf.... $ 2.04 $ 2.03 $ 1.99 $ 1.76 $ 2.80
</TABLE>
Discussion and Analysis of Historical Results from the Underlying Properties
Years Ended December 31, 1997, 1998 and 1999
Royalty income for 1997 was $10,550,000 as compared with $7,080,000 for 1998
and $6,691,000 for 1999. The 33% decrease in royalty income from 1997 to 1998
was primarily because of lower oil prices and lower gas volumes related to
lawsuit settlement proceeds of $733,000
17
<PAGE>
received in 1997. The 5% decrease in royalty income from 1998 to 1999 was
primarily because of recovery of prior year excess costs. Royalty income
derived from gas sales was 69% in 1997, 80% in 1998 and 79% in 1999.
Royalty income is recorded when received by the trust, which is the month
following receipt by Cross Timbers Oil, and generally two months after oil
production and three months after gas production. Royalty income is generally
affected by three major factors:
(1) oil and gas sales volumes;
(2) oil and gas sales prices; and
(3) costs deducted in the calculation of royalty income.
Sales Volumes. Underlying oil sales volumes decreased 7% from 1997 to 1998,
as compared to a 11% decrease from 1998 to 1999. The decline in oil volumes
from 1997 to 1998 was the result of a temporary disruption of production
resulting from mechanical complications on one of the underlying Oklahoma
working interest properties, as well as the initial downtime of development
projects on some of the properties underlying the 75% net profits interests.
Approximately half the 1999 decline was attributable to the same mechanical
complications that affected 1998 volumes. Production on this property gradually
increased over the last half of 1999. The unit operator is planning a well
workover program in 2000 to increase production levels after pumping unit
mechanical problems in the last half of 1998 forced many wells to be shut-in
because oil prices were too low to support costly repairs. The remainder of the
1999 decline in oil volumes primarily reflected natural production decline.
Underlying gas sales volumes decreased 21% from 1997 to 1998, as compared to
a 4% increase from 1998 to 1999. Underlying gas sales volumes for 1997 included
636,000 Mcf attributable to lawsuit settlement proceeds received by the trust.
Excluding the effects of volumes related to lawsuit settlement proceeds, gas
sales volumes declined 7% from 1997 to 1998 primarily because of natural
decline and timing of cash receipts. Increased volumes from 1998 to 1999 were
primarily attributable to significant receipts related to prior periods.
Sales Prices. The average oil price for 1997 was $19.20 per Bbl, 43% higher
than the 1998 average oil price of $13.40, which was 10% lower than the 1999
average price of $14.88. Because of the two-month interval between oil
production and receipt by the trust of related royalty income, the 1998 average
price includes the effect of oil prices that began to weaken in December 1997
and continued to decline through 1998. West Texas Intermediate posted crude oil
prices dropped to $8.00 per barrel in December 1998, the lowest level since
1978. After OPEC members and other oil producers agreed to production cuts in
March 1999, oil prices climbed throughout the year. The posted price reached
$24.00 in December 1999, the highest level at that time since the 1990 Persian
Gulf War.
The 1997 average gas price was $2.04 per Mcf, relatively unchanged from the
1998 average gas price of $2.03, which was 2% higher than the 1999 average
price of $1.99. Prior to 1999, purchaser deductions were netted in the gas
price. As of 1999, these purchaser deductions are included in taxes,
transportation and other costs (see "Costs" below). Considering the effect of
this change in classification, gas prices declined 16% from 1998 to 1999. Gas
prices were lower in 1999 primarily because of the abnormally warm winter of
1998-1999 across the United States that resulted in higher levels of gas in
storage. San Juan Basin gas prices, in particular, were lower in 1999 because
of an abundance of hydroelectric energy in West Coast markets following a
winter with abnormally high precipitation. Gas prices trended higher during
1999 as gas in storage declined.
San Juan Basin gas prices have strengthened relative to prices in other
regions because of increased demand in the southwest U.S., including increased
use of gas during the summer to
18
<PAGE>
generate electricity. Also, recently completed pipelines have redirected a
portion of western Canadian gas supplies from West Coast to East Coast markets,
alleviating some downward price pressure for gas sold in California.
Costs. Because properties underlying the 90% net profits interests are
royalty and overriding royalty interests, the calculation of royalty income
from these interests only includes deductions for production and property
taxes, legal costs, and marketing and transportation charges. In addition to
these costs, the calculation of royalty income from the 75% net profits
interests includes deductions for production and development costs since the
related underlying properties are working interests. Royalty income is
calculated monthly for each of the five conveyances under which the net profits
interests were conveyed to the trust. If monthly costs exceed revenues for any
conveyance, such excess costs cannot reduce royalty income from other
conveyances, but must be recovered, with accrued interest, from future net
proceeds of that conveyance.
Before adjustment for excess costs (see "Excess Costs" below), total costs
deducted in the calculation of royalty income were $5,037,000 in 1997,
$4,919,000 in 1998 and $4,733,000 in 1999. The 2% decrease in costs from 1997
to 1998 is primarily the result of lower production taxes associated with lower
oil and gas revenues, largely offset by increased development costs. Higher
1998 development costs were primarily associated with a carbon dioxide
injection project on one of the properties underlying the Texas 75% net profits
interests. The 4% decrease in costs from 1998 to 1999 is primarily attributable
to decreased development costs and production expense, offset by increased
purchaser deductions for gathering and compression charges (included in taxes,
transportation and other) which had been netted in the gas sales price prior to
1999.
Excess Costs. During 1998, costs exceeded revenues for the Texas 75% net
profits interests by $505,000 and the Oklahoma 75% net profits interests by
$10,000. During 1999, costs exceeded revenues for properties underlying the
Texas 75% net profits interests by $327,000 and the Oklahoma 75% net profits
interests by $106,000. Excess costs for the Texas 75% net profits interests
were primarily the result of low oil prices and increased development costs
related to the 1998 carbon dioxide injection project, while excess costs for
the Oklahoma 75% net profits interests were primarily related to low oil prices
and reduced oil sales volumes related to mechanical complications on one of the
underlying properties.
Excess costs from one conveyance cannot reduce royalty income computed under
another conveyance, but must be recovered from future net proceeds of the same
conveyance before the conveyance can again contribute to trust royalty income.
With improved oil prices in the last half of 1999, excess costs of $527,000
were recovered for the Texas 75% net profits interests and excess costs and
accrued interest of $107,000 were recovered for the Oklahoma 75% net profits
interests. Excess costs and accrued interest from the Oklahoma 75% net profits
interests were fully recovered in October 1999.
Remaining excess costs and accrued interest were $376,000 ($282,000 net to
the trust) as of December 31, 1999. Excess costs were fully recovered in May
2000. The Texas 75% net profits interests did not contribute to 1999 royalty
income and only contributed $0.02 per unit to 1998 royalty income as compared
to $0.18 per unit to 1997 royalty income, or 10% of total 1997 distributions.
Six Months Ended June 30, 1999 and 2000
For the six months ended June 30, 1999, royalty income was $2,693,000
compared with $4,830,000 for the same 2000 period. This 79% increase in royalty
income is because of higher oil and gas prices. The following are explanations
of significant variances from the first six months of 1999 to the comparable
period in 2000:
19
<PAGE>
Sales Volumes. Decreased oil sales volumes in the six months ended June 30,
2000 are primarily because of the timing of cash receipts. Natural production
decline was largely offset by increased production on one of the Texas working
interest properties as a result of carbon dioxide injections.
Decreased gas volumes are primarily because of higher natural decline in
coal seam gas production and the timing of cash receipts, partially offset by
purchaser volume adjustments.
Sales Prices. Lower average 1999 prices reflect abnormally low prices
resulting from global excess supply. After OPEC members and other oil producers
agreed to production cuts in March 1999, oil prices climbed through the
remainder of 1999 and first quarter 2000. Increased demand in 2000 has more
than offset OPEC production increases in March and June, sustaining higher
prices through June 2000. The average West Texas Intermediate posted price for
June 2000 was $28.79 per Bbl. Although OPEC members have proposed additional
production increases to reduce prices, during September 2000 crude oil prices
rose to their highest level in the last 10 years.
The average gas price increased 59%, which is partly attributable to
purchaser deductions which were netted in the gas price prior to second quarter
1999. Since then, these purchaser deductions are included in taxes,
transportation and other costs (see "Costs" below). Excluding the effect of
this change, gas prices increased 48% over this period. Gas prices were lower
in 1999 primarily because of the abnormally warm winter of 1998-1999
experienced across the United States that resulted in higher levels of gas in
storage. Gas prices began to increase in May 1999 and, after declining briefly
at year end, have continued to strengthen in 2000, as gas storage remains lower
than prior year levels. At September 5, 2000, the average NYMEX price for the
following twelve months was $4.49 per MMBtu. The trust's recent gas prices have
averaged $0.40 per MMBtu higher than the NYMEX price, primarily because of the
effect of higher natural gas liquids prices.
Costs. Taxes, transportation and other increased primarily as a result of
increased taxes on higher oil and gas revenues. Also, beginning in second
quarter 1999, this cost category has included purchaser deductions for
gathering and compression charges. Prior to second quarter 1999, these charges
were netted in the gas sales price. As a result, taxes, transportation and
other includes an increase of $286,000 in purchaser deductions. Lower
development costs reflect completion of the carbon dioxide injection project on
one of the underlying Texas working interest properties in third quarter 1999.
Primarily because of higher oil prices, all excess costs and accrued
interest for the Texas 75% net profits interests were fully recovered in second
quarter 2000. After two years of excess costs and recovery of these costs, the
Texas 75% net profits interests again began contributing to trust royalty
income in May 2000. There are no excess costs remaining to be recovered as of
June 30, 2000. Excess costs occurred in the 1999 periods because of low oil
prices and costs related to the carbon dioxide injection project.
Producing Acres and Well Counts
For the following data, "gross" refers to the total wells or acres in which
Cross Timbers Oil owns a working interest and "net" refers to gross wells or
acres multiplied by the percentage working interest owned by Cross Timbers Oil.
Although many 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 royalties contain approximately 462,000 gross (approximately
26,000 net) producing acres. Information regarding the number of wells on
royalty properties is generally not made available to royalty interest owners.
Accordingly, an accurate well count for all underlying royalties cannot be
provided.
20
<PAGE>
The underlying working interest properties are developed properties
undergoing secondary or tertiary recovery operations. The underlying working
interest properties consist of 60,154 gross (2,290 net) producing acres. As of
December 31, 1999, there were 1,480 gross (66.5 net) productive oil wells, 989
gross (41.6 net) injection wells and no wells in process of drilling on these
properties. During 1997, 15 gross (1.5 net) producing wells were drilled. No
wells were drilled during 1998. During 1999, 8 gross (0.1 net) producing wells
were drilled.
Non-Producing Acres
The underlying nonproducing royalties contain approximately 200,000 gross
(approximately 3,000 net) acres in Texas, Oklahoma and New Mexico which were
nonproducing at the date of the trust's creation. Cross Timbers Oil is the
owner of underlying mineral interests in the majority of this acreage. The
trust is entitled to 10% of oil and gas production attributable to the
underlying mineral properties, but is not entitled to delay rental payments or
lease bonuses. There has been no significant development of such nonproducing
acreage since the trust's creation.
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 Mcfe for the underlying properties:
<TABLE>
<CAPTION>
Six Months Ended
Year Ended December 31 June 30
----------------------- -----------------
1997 1998 1999 1999 2000
------- ------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
Sales prices:
Oil (per Bbl)................... $ 19.20 $ 13.40 $ 14.88 $ 11.36 $ 25.48
Natural gas (per Mcf)........... 2.04 2.03 1.99 1.76 2.80
Production costs (per Mcfe)...... 0.38 0.44 0.42 0.43 0.48
Production and property taxes and
transportation costs (per
Mcfe)........................... 0.22 0.20 0.28 0.23 0.46
</TABLE>
Producing Acreage, Wells and Drilling
90% Net Profits Interests. These underlying properties are royalty and
overriding royalty interests primarily located in mature producing oil and gas
fields. The most significant producing region for these properties is located
is the San Juan Basin in northwestern New Mexico. Estimated proved reserves
attributable to the trust's 90% net profits interests from this region totaled
29.3 Bcf of natural gas at December 31, 1999, or approximately 82% of total gas
reserves attributable to the trust's 90% net profits interests at that date.
Cross Timbers Oil estimates that underlying properties in the San Juan Basin
include more than 2,000 gross (approximately 30 net) wells, covering over
60,000 gross acres. Most of these wells are operated by Amoco Production
Company and Burlington Resources Oil & Gas Company. Production from
conventional gas wells is primarily from the Dakota, Mesaverde and Pictured
Cliffs formations.
Exploitation of coal seam gas reserves in the Fruitland formation was the
most significant recent development activity in the San Juan Basin until the
drilling period for the federal income tax credit expired on January 1, 1993.
Since that date, operators in the San Juan Basin have continued to report
development of coal seam gas reserves without the incentive of the federal
income tax credit. Cross Timbers Oil does not know whether any of this
development activity has directly affected trust royalties attributable to such
reserves or production. During 1996, additional eastward pipeline capacity was
completed in the San Juan Basin, reducing the dependence of San Juan Basin gas
on California markets and effectively increasing San Juan Basin gas prices in
relation to prices from other regions. Gas-powered electricity generation
continues to increase in the southwest U.S., thereby increasing demand for San
Juan Basin gas. Additional eastward pipeline capacity for western
21
<PAGE>
Canadian gas supplies, which previously were primarily directed to U.S. West
Coast markets, has also improved the market for San Juan Basin gas.
The underlying properties also include royalties in the Sand Hills field of
Crane County, Texas. Most of these properties are operated by Exxon Company,
U.S.A. and Chevron, U.S.A. The Sand Hills field was discovered in 1931 and
includes production from three main intervals, the Tubb, McKnight and Judkins.
Development potential for the field includes recompletions and additional
infill drilling.
75% Net Profits Interests. The underlying properties consist of working
interests, as detailed below, that are developed properties undergoing
secondary or tertiary recovery operations:
<TABLE>
<CAPTION>
Ownership by
Cross Timbers Oil
-----------------
Net
Working Revenue
Unit County/State Operator Interest Interest
---- --------------- -------- -------- --------
<S> <C> <C> <C> <C>
North Central Mobil Producing Texas and New Mexico, Inc. 3.2% 2.1%
Levelland.............. Hockley/Texas
North Cowden............ Ector/Texas Occidental Permian Ltd. 1.7% 1.4%
Penwell................. Ector/Texas Texaco Exploration and Production, Inc. 5.2% 4.6%
Sharon Ridge Canyon..... Borden/Texas Exxon Company, U.S.A. 4.3% 2.8%
Hewitt.................. Carter/Oklahoma Exxon Company, U.S.A. 11.3% 9.9%
South Graham Deese...... Carter/Oklahoma Maynard Oil Company 8.2% 7.0%
Wildcat Jim Penn........ Carter/Oklahoma Texaco Exploration and Production, Inc. 8.6% 7.5%
</TABLE>
Oil and Natural Gas Reserves
Miller and Lents has estimated oil and gas reserves attributable to the net
profits interests as of December 31, 1996, 1997, 1998 and 1999. Numerous
uncertainties are inherent in estimating reserve volumes and values and such
estimates are subject to change as additional information becomes available.
The reserves actually recovered and the timing of production of these reserves
may be substantially different from the original estimates.
Miller and Lents estimated 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 Oil in the underlying
properties. Since the trust owns defined net profits interests, the trust does
not own a specific ownership percentage of the oil and gas reserve quantities.
Accordingly, reserves allocated to the trust's 75% net profits interests in the
working interest properties have effectively been reduced to reflect recovery
of the trust's 75% portion of applicable production and development costs.
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 standardized measure of discounted future net cash flows and changes in
such discounted cash flows as presented below were prepared using assumptions
required by the Financial Accounting Standards Board. Such assumptions include
the use of year-end prices for oil and gas and year-end costs for estimated
future development and production expenditures to produce the proved reserves.
Because natural gas prices are influenced by seasonal demand, use of year-end
prices, as required by the Financial Accounting Standards Board, may not be the
most representative in estimating future revenues or reserve data. Future net
cash flows are discounted at an annual rate of 10%. No provision is included
for federal income taxes since future net revenues are not subject to taxation
at the trust level.
Year-end oil prices used to determine the standardized measure were based on
a West Texas Intermediate crude oil posted price of $24.25 per Bbl in 1996,
$15.50 per Bbl in 1997, $9.50 per Bbl in 1998 and $22.75 per Bbl in 1999. The
year-end weighted average gas prices used to determine the standardized measure
were $2.64 per Mcf in 1996, $1.76 per Mcf in 1997, $1.88 per Mcf in 1998 and
$2.19 per Mcf in 1999.
22
<PAGE>
During 2000, Cross Timbers Oil filed estimates of oil and natural gas
reserves as of December 31, 1999 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, 1999, with the
exception that Form EIA-23 includes only reserves from properties operated by
Cross Timbers Oil.
Proved Reserves
The following table summarizes changes in estimated proved reserves
attributable to the net profits interests and the underlying properties from
December 31, 1996 through December 31, 1999 (in thousands):
<TABLE>
<CAPTION>
Net Profits Interests
-------------------------------------------------------------
90% Net 75% Net Underlying
Profits Interests Profits Interests Total Properties
-------------------- -------------------- ----------------- ------------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
-------- ---------- --------- --------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31,
1996................... 680.8 39,680.6 1,805.0 690.5 2,485.8 40,371.1 5,282.3 46,421.8
Extensions, discoveries
and other additions... 107.9 270.0 -0- -0- 107.9 270.0 122.3 310.8
Revisions of prior
estimates............. 25.5 1,779.7 (745.8) (301.5) (720.3) 1,478.2 (562.3) 1,761.7
Production............. (82.7) (3,844.1) (94.5) (33.4) (177.2) (3,877.5) (424.0) (4,418.9)
------- ---------- --------- -------- ------- -------- -------- --------
Balance, December 31,
1997................... 731.5 37,886.2 964.7 355.6 1,696.2 38,241.8 4,418.3 44,075.4
Extensions, discoveries
and other additions... 3.6 95.7 -0- -0- 3.6 95.7 4.1 265.6
Revisions of prior
estimates............. 25.3 1,482.1 (696.7) (282.4) (671.4) 1,199.7 (1,620.1) 894.5
Production............. (83.9) (3,010.8) (20.9) (7.9) (104.8) (3,018.7) (392.4) (3,502.1)
------- ---------- --------- -------- ------- -------- -------- --------
Balance, December 31,
1998................... 676.5 36,453.2 247.1 65.3 923.6 36,518.5 2,409.9 41,733.4
Extensions, discoveries
and other additions... 10.5 162.2 -0- -0- 10.5 162.2 13.1 186.0
Revisions of prior
estimates............. 109.9 1,462.1 1,251.8 533.4 1,361.7 1,995.5 2,385.7 2,322.0
Production............. (77.8) (3,152.7) (19.9) (10.2) (97.7) (3,162.9) (348.6) (3,643.0)
------- ---------- --------- -------- ------- -------- -------- --------
Balance, December 31,
1999................... 719.1 34,924.8 1,479.0 588.5 2,198.1 35,513.3 4,460.1 40,598.4
======= ========== ========= ======== ======= ======== ======== ========
</TABLE>
During 1997, 1998, and 1999, upward revisions of prior estimates of the 90%
net profits interests' proved gas reserves were primarily because of lower than
anticipated production declines. During 1997, proved oil reserves of the 90%
net profits interests increased primarily because of development drilling on
trust royalty acreage in Lea County, New Mexico. Revisions of prior estimates
of the 75% net profits interests' proved reserves and the underlying
properties' proved oil reserves in each of these years were primarily the
result of changes in the year-end oil prices used in estimating proved
reserves.
23
<PAGE>
Proved Developed Reserves
The following are estimated quantities of proved developed oil and gas
reserves attributable to the net profits interests as of December 31, 1996 and
each following year-end through December 31, 1999 (in thousands):
<TABLE>
<CAPTION>
90% Net 75% Net
Profits Interests Profits Interests Total
------------------- -----------------------------------
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
-------- ---------- --------- ---------------- --------
<S> <C> <C> <C> <C> <C> <C>
December 31, 1996........ 676.6 37,705.7 1,701.2 675.7 2,377.8 38,381.4
======= ========== ========= ======= ======= ========
December 31, 1997........ 727.9 35,947.4 908.6 346.8 1,636.5 36,294.2
======= ========== ========= ======= ======= ========
December 31, 1998........ 672.8 34,514.0 206.4 60.7 879.2 34,574.7
======= ========== ========= ======= ======= ========
December 31, 1999........ 715.7 33,036.5 1,375.0 570.3 2,090.7 33,606.8
======= ========== ========= ======= ======= ========
</TABLE>
Changes in proved developed reserves are explained under "Proved Reserves"
above.
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
of the Net Profits Interests
The following are summary calculations of the standardized measure of
discounted future net cash flows as of December 31, 1997, 1998 and 1999 (in
thousands):
<TABLE>
<CAPTION>
90% Net 75% Net
Profits Interests Profits Interests Total
--------------------------- ------------------------- ---------------------------
December 31, December 31, December 31,
--------------------------- ------------------------- ---------------------------
1997 1998 1999 1997 1998 1999 1997 1998 1999
-------- ------- -------- ------- ------ -------- -------- ------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Future cash inflows..... $ 77,217 $77,207 $ 97,902 $14,975 $2,582 $ 36,670 $ 92,192 $79,789 $134,572
Future production
taxes.................. (5,346) (5,401) (7,751) (847) (131) (2,487) (6,193) (5,532) (10,238)
-------- ------- -------- ------- ------ -------- -------- ------- --------
Future net cash flows... 71,871 71,806 90,151 14,128 2,451 34,183 85,999 74,257 124,334
10% discount factor..... (36,221) (37,222) (46,573) (6,282) (1,259) (17,135) (42,503) (38,481) (63,708)
-------- ------- -------- ------- ------ -------- -------- ------- --------
Standardized measure.... $ 35,650 $34,584 $ 43,578 $ 7,846 $1,192 $ 17,048 $ 43,496 $35,776 $ 60,626
======== ======= ======== ======= ====== ======== ======== ======= ========
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows from
Proved Reserves of the Net Profits Interests
The following reconciles the changes during 1997, 1998 and 1999 in the
standardized measure (in thousands):
<TABLE>
<CAPTION>
90% Net 75% Net
Profits Interests Profits Interests Total
-------------------------- ------------------------ --------------------------
1997 1998 1999 1997 1998 1999 1997 1998 1999
-------- ------- ------- ------- ------ ------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Standardized measure,
January 1.............. $ 54,884 $35,650 $34,584 $21,963 $7,846 $ 1,192 $ 76,847 $43,496 $35,776
Extensions, discoveries
and other additions.... 1,311 155 384 -0- -0- -0- 1,311 155 384
Accretion of discount... 4,861 3,176 3,078 1,980 698 106 6,841 3,874 3,184
Revisions of prior
estimates, changes in
price and other........ (16,689) 2,369 11,864 (14,264) (7,038) 16,109 (30,953) (4,669) 27,973
Royalty income.......... (8,717) (6,766) (6,332) (1,833) (314) (359) (10,550) (7,080) (6,691)
-------- ------- ------- ------- ------ ------- -------- ------- -------
Standardized measure,
December 31............ $ 35,650 $34,584 $43,578 $ 7,846 $1,192 $17,048 $ 43,496 $35,776 $60,626
======== ======= ======= ======= ====== ======= ======== ======= =======
</TABLE>
24
<PAGE>
Discounted Present Value of the Coal Seam Tax Credit
The standardized measure above does not include the effects of the coal seam
tax credit since the trust is not a taxable entity. The following summarizes
the estimated coal seam tax credit attributable to the 90% net profits
interests at December 31, 1997, 1998 and 1999. Such estimates are based on
projected coal seam gas production through the year 2002 as estimated by
independent engineers. The estimates are also based on the current year
estimated Btu content and the coal seam tax credit of $1.05 per MMBtu at
December 31, 1997 and 1998, and $1.02 per MMBtu at December 31, 1999. See
"Regulation--Coal Seam Tax Credit."
<TABLE>
<CAPTION>
December 31,
--------------------
1997 1998 1999
------ ------ ------
(in thousands)
<S> <C> <C> <C>
Undiscounted........................................... $3,390 $2,780 $1,979
====== ====== ======
Discounted present value at 10%........................ $2,784 $2,359 $1,740
====== ====== ======
</TABLE>
Regulation
Oil and Natural Gas Regulation. Sales of crude oil, condensate and natural
gas liquids are currently not regulated and are made at market prices. 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 Oil 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. Federal, state and local laws regulating the
discharge of materials into the environment affect companies that are engaged
in the oil and gas industry. Those laws may impact operations of the underlying
properties. Cross Timbers Oil believes that it is in substantial compliance
with the environmental laws and regulations that apply to the operations of the
underlying properties. Cross Timbers Oil has not previously incurred material
expenses in complying with environmental laws and regulations that affect
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, New Mexico and Oklahoma 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.
Other Regulation. The petroleum industry is 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 Oil does not believe that compliance with these laws
will have a material adverse effect upon the trust unitholders.
25
<PAGE>
Certain Provisions Affecting San Juan Basin Royalty Interests
Contracts creating or governing some of the underlying properties that are
royalties and overriding royalties in the San Juan Basin contain provisions
that purportedly either reduce the overriding royalty interest or convert the
royalty or overriding royalty interest into a working interest when gas
production falls below specified levels. Cross Timbers Oil believes these
provisions were included in these contracts because of a federal regulation,
that has since been repealed, limiting the amount of royalties and overriding
royalties placed on federal leases in the San Juan Basin. No assurances,
however, can be made regarding the effect of these provisions on the trust.
Cross Timbers and other royalty interest owners filed a lawsuit, later joined
by the trust in 1993, to recover revenues suspended by working interest owners
based on their interpretation of these reduction or conversion provisions. The
trust, Cross Timbers Oil and the other royalty owners settled this lawsuit in
1996, receiving past production due to the trust and receiving further
compensation for an agreement to reduce the trust's interest in the involved
properties.
Coal Seam Tax Credit
The trust receives royalty income from coal seam wells. Under Section 29 of
the Internal Revenue Code, coal seam gas produced prior to January 1, 2003 from
wells drilled after December 31, 1979 and before January 1, 1993, qualifies for
the federal income tax credit for producing nonconventional fuels. This tax
credit for 1999 was approximately $1.02 per MMBtu. Such credit, calculated
based on the trust unitholder's pro rata share of qualifying production, may
not reduce the trust unitholder's regular tax liability (after the foreign tax
credit and certain other nonrefundable credits) below his alternative minimum
tax. Any part of the Section 29 tax credit not allowed for the tax year solely
because of this limitation is subject to certain carryover provisions.
Title to Properties
Cross Timbers Oil believes that its title to the underlying properties is,
and the trust's title to the net profits interests 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 Oil's
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
26
<PAGE>
the net profits interests. Cross Timbers Oil 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 Oil 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 Oklahoma and New Mexico
counsel that the net profits interests covering the underlying properties in
Oklahoma and New Mexico also constitute interests in real property under
Oklahoma and New Mexico law. Cross Timbers Oil has recorded the conveyances in
the appropriate real property records of Oklahoma, Texas and New Mexico. If a
determination were made in a bankruptcy proceeding of Cross Timbers Oil 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 executory contract and
rejected in the bankruptcy proceeding, Cross Timbers Oil would not be required
to perform its obligations under the net profits interest and the trust would
seek damages as one of Cross Timbers Oil's unsecured creditors. Although no
assurance can be given, Cross Timbers Oil does not believe that the net profits
interests should be subject to rejection in a bankruptcy proceeding as
executory contracts.
Marketing
Most of the natural gas production from the underlying properties is from
royalty or overriding royalty interests. Owners of such interests typically do
not have the right to sell their production and are generally paid under the
terms of the related working interest owners sales agreement.
Oil and natural gas are generally sold from the underlying properties at
posted and spot prices. The majority of sales from the underlying properties
comprising the 75% net profits interests are to major oil and gas companies.
Information about purchasers of oil and gas from underlying properties
comprising the 90% net profits interests is generally not provided by operators
to Cross Timbers Oil as a royalty owner, or to the trust.
Litigation
There is no material litigation involving the underlying properties.
27
<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. The net profits interests entitle the trust to receive:
. 90% of the net proceeds from the sale of oil and natural gas produced
from the three conveyances that represent royalty and overriding royalty
interests underlying properties; and
. 75% of the net proceeds from the sale of oil and natural gas produced
from the two conveyances that represent working interests 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 Oil pays either 90% or 75% 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 Oil
will not pay to the trust interest on the net proceeds held by Cross Timbers
Oil 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. The 90% net
profits interests are royalty and overriding royalty interests and production
costs are zero. Production costs apply only to working interest properties,
which comprise the 75% net profit interests.
Gross proceeds means an amount received by Cross Timbers Oil 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 Oil 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.
28
<PAGE>
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;
. 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;
. other 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.
Cross Timbers Oil charges an overhead fee to administer the underlying
properties. The administration includes various engineering, accounting and
other administrative functions. This fee is $270,840 per year to the underlying
properties and $203,130 per year net to the trust as of June 30, 2000 for all
working interest underlying properties. The fee is adjusted annually and will
increase or decrease each year based on changes in the year-end index of
average weekly earnings of crude petroleum and natural gas workers.
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 five separate
conveyances, one each for the three 90% net profits interests conveyances and
for the two 75% net profits interests conveyances. Net proceeds are calculated
separately for the underlying properties covered by each conveyance, so excess
production costs in one conveyance do not reduce net proceeds from the other.
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;
29
<PAGE>
. 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
. 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 conveyances permit Cross Timbers Oil 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 accrued
and reimbursed from the transferred property prior to the transfer will not
reduce the net proceeds payable to the trust from the underlying properties
retained by Cross Timbers Oil. The conveyances have been recorded in the
appropriate real property records to give notice of the net profits interests
to Cross Timbers Oil's creditors and transferees.
Cross Timbers Oil may enter into farmout, operating, participation, and
other similar agreements covering an underlying property if Cross Timbers Oil
believes it to be advantageous. 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 Oil under the agreement
and not on Cross Timbers Oil's original interest before modification by the
agreement. Cross Timbers Oil may enter into any of these agreements without the
consent or approval of the trustee or any trust unitholder. However, Cross
Timbers Oil's interest in entering into any of these types of agreements should
be parallel with that of trust unitholders because of its retained interest in
10% of the net proceeds from the conveyances of underlying properties that are
royalty or overriding royalty interests and 25% of the net proceeds from the
conveyances of underlying properties that are working interests.
Cross Timbers Oil and any transferee will have the right to abandon any well
or property if it believes the well or property ceases to produce or is not
capable of producing in commercially paying quantities. Upon termination of the
lease, that portion of the net profits interests relating to the abandoned
property will be extinguished.
Cross Timbers Oil must maintain books and records sufficient to determine
the amounts payable for the net profits interests. Quarterly and annually,
Cross Timbers Oil must deliver to the trustee a statement of the computation of
the net proceeds for each computation period. Cross Timbers Oil will cause the
annual computation of net proceeds to be audited. The audit cost will be borne
by the trust.
30
<PAGE>
FEDERAL INCOME TAX CONSEQUENCES
This section summarizes 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
Winstead Sechrest & Minick P.C. regarding the classification of the trust and
certain federal income tax consequences described below, which will be
confirmed at the time of the closing. Winstead Sechrest & Minick P.C. 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 summary 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
Winstead Sechrest & Minick P.C. is of the opinion that, for federal income
tax purposes:
. the trust is a grantor trust and not a business entity taxable as a
partnership or a corporation; and
. the income from the net profits interests is royalty income subject to
an allowance for depletion.
Winstead Sechrest & Minick P.C. 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 Winstead Sechrest & Minick P.C., under current law, the
trust is taxable as a grantor trust and not as a business entity. As a grantor
trust, the trust is not subject to tax at the trust level. For tax purposes,
the grantors, who in this case are the trust unitholders, are 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 Winstead Sechrest & Minick P.C., 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
31
<PAGE>
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.
Direct Taxation of Trust Unitholders
Since the trust is treated as a grantor trust for federal income tax
purposes, each trust unitholder is taxed directly on his share of trust income
and is entitled to claim his share of trust deductions. Each trust unitholder
recognizes taxable income when the trust receives or accrues it, even if it is
not distributed until later. Trust unitholders 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 treats 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 pays expenses only on the day it receives a royalty payment. All
expenses paid on a royalty receipt day are 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 are reported as
belonging to the trust unitholders who received a distribution for that period.
The amount of the distribution for a trust unit generally equals 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 Winstead Sechrest & Minick P.C., the income from the net
profits interests is 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. Winstead Sechrest & Minick P.C. 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
takes 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 qualifies
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
32
<PAGE>
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 Oil believes that trust unitholders who purchase trust units
in this offering will derive a substantially greater benefit from cost
depletion than from percentage depletion.
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 computes cost
depletion using his basis in his trust units. Information is 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 include any state and local taxes imposed on the trust
and administrative expenses of the trustee. Although the issue has not been
finally resolved, Winstead Sechrest & Minick P.C. 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.
Section 29 Coal Seam Gas Tax Credit
Certain of the natural gas production attributable to the net profits
interests is from coal seam gas. Subject to certain statutory requirements,
taxpayers are entitled to the Section 29 tax credit for production and sale of
certain natural gas produced from coal seams. The Section 29 tax credit applies
to coal seam gas produced and sold to unrelated party prior to January 1, 2003
from wells drilled prior to January 1, 1993 and after December 31, 1979. The
Section 29 tax credit is equal to $3.00 per barrel of oil equivalent, which is
5.8 MMBtu, adjusted for inflation since 1979. The credit is reduced by a
formula computation as the price of oil rises above an inflation adjusted
amount. The Section 29 credit available for gas produced in 1999 was $1.02 per
MMBtu. In the opinion of Winstead Sechrest & Minick P.C., if the requisite
statutory requirements are met, the trust unitholders will be eligible to claim
the Section 29 tax credit for sales of qualified coal seam gas production
included in the calculation of the net profits interests. Cross Timbers Oil
believes that all of the statutory requirements have been or will be met on
substantially all of the coal seam wells.
The Section 29 tax credit allowable for any taxable year cannot exceed the
excess of the taxpayer's regular tax liability for that taxable year, as
reduced by the taxpayer's foreign tax credits and certain nonrefundable
credits, over the taxpayer's tentative minimum tax liability for that year. Any
amount of Section 29 tax credit disallowed for the tax year solely because of
this limitation will increase the taxpayer's minimum tax credit carryover. This
credit may be carried forward indefinitely as a credit against the taxpayer's
regular tax liability, subject, however to the limitation described in the
first sentence of this paragraph. There is no provision for the carryback or
carryforward of the Section 29 tax credit in any other circumstances, so, a
trust unitholder may not receive the full benefit of the tax credit depending
on his particular circumstances.
33
<PAGE>
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. Section 29 tax credits generated by an investment in the trust
units, therefore, can be utilized to offset regular tax liability on income
from any source, subject to the limitations discussed in "Section 29 Coal Seam
Gas Tax Credit" above.
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 Winstead
Sechrest & Minick P.C., 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 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;
34
<PAGE>
. 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.
Tax Shelter Registration
Cross Timbers Oil 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 has been 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."
35
<PAGE>
STATE TAX CONSIDERATIONS
The following is a brief summary 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 and Oklahoma impose 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 and Oklahoma 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 and subject to Oklahoma income tax on their share of income
from Oklahoma net profits interests. Nonresidents of New Mexico and Oklahoma,
however, may not be taxed in those states on gains from sales 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, New Mexico and
Oklahoma. 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.
36
<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. The trust units are publicly traded on
the New York Stock Exchange. 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.
37
<PAGE>
DESCRIPTION OF THE TRUST INDENTURE
The following information and the information included under "Description of
the Trust Units" summarize the material information contained in the trust
indenture. 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 indenture. A copy of the trust indenture was filed as an exhibit to the
registration statement. See "Available Information."
Creation and Organization of the Trust; Amendments
Cross Timbers Oil created the net profits interests and conveyed them to the
trust in exchange for 12,000,000 trust units. The 12,000,000 units were
subsequently converted to 6,000,000 outstanding units.
Cross Timbers Oil organized the trust under Texas law to acquire and hold
the net profits interests for the benefit of the trust unitholders under an
agreement between Cross Timbers Oil and the trustee. The trustee has all the
power to collect and distribute proceeds receiveable by the trust and to pay
trust liabilities and expenses.
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 Oil 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 6,000,000 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.
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 Texas. 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
38
<PAGE>
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
. bank certificates of deposit.
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.
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 termination 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.
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 must purchase for cash from trust
assets the trust units held by the ineligible holder. The purchase price for
the trust units will be the market price on a specified day. The trustee may
then either cancel the trust certificate for the trust units so purchased or
sell them to an eligible third party with the proceeds becoming revenue of the
trust.
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, the trust has only incurred liabilities for
routine administrative expenses, such as the trustee's fees and accounting,
engineering, legal and other professional fees. Cross Timbers Oil does not
expect the trust to incur other types of liabilities in the future.
39
<PAGE>
Responsibility and Liability of the Trustee
The trustee is a fiduciary for the trust unitholders and 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. Under Texas law, the trustee's duties to the trust unitholders are
similar to the duty of care owed by a corporate director to the corporation and
its shareholders. The primary difference between the trustee's duties and a
corporate director's duties is the absence of the legal presumption protecting
the trustee's decisions from challenge.
The trustee does not make business decisions affecting the assets of the
trust. Therefore, substantially all of the trustee's functions under the trust
indenture are ministerial in nature. See "--Duties and Limited Powers of the
Trustee," above. The trust indenture 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 in compliance with applicable law;
. 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 will be indemnified for any liability or cost that it incurs in the
administration of the trust, except in cases of fraud or acts or omissions in
bad faith. The trustee has a lien on the assets of the trust as security for
this indemnification and compensation earned as trustee. The trustee is
entitled to indemnification from trust assets. Trust unitholders will not be
liable to the trustee 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 such contractual liabilities if it fails to do so.
Under Texas law, if the trustee acts in bad faith or with gross negligence,
the trustee will be liable to the trust unitholders for damages. Texas law also
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 terminate 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;
. 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.
40
<PAGE>
Compensation of the Trustee
The trustee's compensation 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.
41
<PAGE>
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 has
6,000,000 trust units outstanding.
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 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.
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.
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
The trustee is required to ensure that all contractual liabilities of the
trust are limited to the assets of the trust. The trustee will be liable for
such contractual liabilities if it fails to do so.
42
<PAGE>
Texas law, however, is unclear whether a trust unitholder would be liable for
any liability of the trust that exceeds the net assets of the trust and the
trustee.
Cross Timbers Oil believes it is highly unlikely the trust could 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 may not conduct an 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 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 Oil 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 Oil 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.
43
<PAGE>
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....... Texas law and the laws of the Corporate laws provide that a
other states do not stockholder is not liable for
specifically provide for the obligations and liabilities
limited liability of trust of the corporation, subject to
unitholders. However, due to limited exceptions.
the size and nature of the
trust assets, liability in
excess of the trust
unitholders' investment is
extremely unlikely.
Fiduciary Duties........ The trustee has a fiduciary Officers and directors have a
duty to trust unitholders, but fiduciary duty of loyalty to
Cross Timbers Oil does not. stockholders and a duty to use
due care in management and
administration of a
corporation.
</TABLE>
44
<PAGE>
SELLING TRUST UNITHOLDER
Cross Timbers Oil currently owns 1,360,000 trust units, or approximately 23%
of the 6,000,000 outstanding trust units. It is offering 1,200,000 trust units
in this offering, or 1,360,000 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 Oil
will own no trust units.
Cross Timbers Oil 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.
UNDERWRITING
Under an underwriting agreement among Cross Timbers Oil, the trust and each
of the underwriters named below, each of the underwriters named below has
agreed to purchase from Cross Timbers Oil the respective number of trust units
shown opposite its name:
<TABLE>
<CAPTION>
Number
of
Trust
Underwriters Units
------------ ------
<S> <C>
Lehman Brothers Inc. ...............................................
Dain Rauscher Incorporated..........................................
Fidelity Capital Markets
a division of National Financial Services LLC......................
Total..............................................................
</TABLE>
Fidelity Capital Markets, a division of National Financial Services LLC, is
acting as an underwriter of this offering and will be facilitating electronic
distribution through the Internet.
The underwriting agreement provides that the underwriters' obligations to
purchase the trust units depend on the satisfaction of the conditions contained
in the underwriting agreement, and that if any of the trust units are purchased
by the underwriters, all of the trust units must be purchased. The conditions
contained in the underwriting agreement include the condition that all the
representations and warranties made by Cross Timbers Oil to the underwriters
are true, that there has been no material adverse change in condition of Cross
Timbers Oil or in the financial markets and that Cross Timbers Oil deliver to
the underwriters customary closing documents.
The following table shows the underwriting fees to be paid to the
underwriters by Cross Timbers Oil in connection with this offering. These
amounts are shown assuming both no exercise and full exercise of the
underwriters' option to purchase additional trust units. This underwriting fee
is the difference between the initial price to the public and the amount the
underwriters pay to Cross Timbers Oil to purchase the trust units. On a per
unit basis, the underwriting fee is % of the price to public.
<TABLE>
<CAPTION>
No Full
Exercise Exercise
-------- --------
<S> <C> <C>
Per unit................................................... $ $
Total...................................................... $ $
</TABLE>
Cross Timbers Oil has been advised by the underwriters that the underwriters
propose to offer the trust units directly to the public at the price set forth
on the cover page of this prospectus and to dealers (who may include the
underwriters) at this price to the public less a concession not in excess of
$ per unit. The underwriters may allow, and the dealers may reallow, a
concession not in excess of $ per unit to certain brokers and dealers.
After the offering, the underwriters may change the offering price and other
selling terms.
45
<PAGE>
Cross Timbers Oil has agreed to indemnify the underwriters against certain
liabilities, including liabilities under the Securities Act of 1933 and
liabilities arising from breaches of representations and warranties contained
in the underwriting agreement, or to contribute to payments that may be
required to be made in respect of these liabilities.
Cross Timbers Oil has granted to the underwriters an option to purchase up
to an aggregate of 160,000 additional trust units at the initial price to the
public less the underwriting discount set forth on the cover page of this
prospectus exercisable solely to cover over-allotments, if any. Such option may
be exercised at any time until 30 days after the date of this prospectus. If
this option is exercised, each underwriter will be committed, subject to
satisfaction of the conditions specified in the underwriting agreement, to
purchase a number of additional trust units proportionate to the underwriter's
initial commitment as indicated in the preceding table, and we will be
obligated, pursuant to the option, to sell these trust units to the
underwriters.
Cross Timbers Oil and its directors and executive officers have agreed that
they will not, directly or indirectly, sell, offer or otherwise dispose of any
trust units or enter into any derivative transaction with similar effect as a
sale of trust units for a period of days after the date of this prospectus
without the prior written consent of Lehman Brothers Inc. The restrictions
described in this paragraph do not apply to:
. The sale of trust units to the underwriters; or
. Trust units issued by Cross Timbers Oil under employee incentive plans
or upon the exercise of options issued under employee incentive plans.
In connection with this 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. "Covered" short
sales are sales made in an amount not greater than the underwriters' option to
purchase additional trust units from the issuer in the offering. The
underwriters may close out any covered short position by either exercising
their option to purchase additional trust units or purchasing trust units in
the open market. In determining the source of trust units to close out the
covered short position, the underwriters will consider, among other things, the
price of trust units available for purchase in the open market as compared to
the price at which they may purchase trust units through the over-allotment
option. "Naked" short sales are any sales in excess of such option. The
underwriters must close out any naked short position by purchasing trust units
in the open market. A naked short position is more likely to be created if the
underwriters are concerned that there may be downward pressure on the price of
the trust units in the open market after pricing that could adversely affect
investors who purchase in the offering. Stabilizing transactions consist of
various bids for or purchases of trust units made by the underwriters in the
open market prior to the completion of the offering.
The underwriters may also impose a penalty bid. This occurs when a
particular underwriter repays to the underwriters a portion of the underwriting
discount received by it because the representatives have repurchased trust
units sold by or for the account of such underwriter in stabilizing or short
covering transactions.
Neither Cross Timbers Oil, the trust nor any of the underwriters make any
representation or prediction as to the direction or magnitude of any effect
that transactions described above may have on the price of the trust units or
preventing or retarding a decline in the market price of the trust units. As a
result, the price of the trust units may be higher than the price that might
otherwise exist in the open market.
Similar to other purchase transactions, the underwriters' purchases to cover
the syndicate short sales may have the effect of raising or maintaining the
market price of the trust units or preventing or retarding a decline in the
market price of the trust units. As a result, the price of the trust units may
be higher than the price that might otherwise exist in the open market.
46
<PAGE>
Any offers in Canada will be made only under an exemption from the
requirements to file a prospectus in the relevant province of Canada in which
the sale is made.
Purchasers of the trust units offered in this prospectus may be required to
pay stamp taxes and other charges under the laws and practices of the country
of purchase, in addition to the offering price listed on the cover of this
prospectus.
Some of the underwriters or their affiliates have from time to time provided
investment banking, financial advisory, trustee and lending services to Cross
Timbers Oil and its affiliates in the ordinary course of business for which
they have received customary fees, and they may continue to do so.
On July 1, 1999, Cross Timbers Oil 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 Oil and the Lehman Brothers affiliate each indirectly owned,
through a holding company, 50% of Spring and had equal board representation and
control of Spring. On September 15, 1999, Cross Timbers Oil purchased Lehman's
interest in Spring for $44.3 million.
On September 15, 1999, Cross Timbers Oil acquired, with an affiliate of
Lehman Brothers Inc., certain Arkoma Basin oil and natural gas properties from
Ocean Energy Inc. for $231 million in cash. Cross Timbers Oil and the Lehman
Brothers affiliate each indirectly owned and controlled 50% of the Arkoma Basin
properties through a holding company. On March 31, 2000, Cross Timbers Oil
purchased Lehman's interest in these Arkoma Basin properties for $111 million.
Cross Timbers Oil estimates that total expenses of the offering, other than
underwriting discounts and commissions, will be approximately $500,000.
LEGAL MATTERS
Counsel for Cross Timbers Oil, Kelly, Hart & Hallman, P.C., Fort Worth,
Texas, will give a legal opinion to the underwriters regarding the validity of
the trust units and other matters related to this offering. Counsel for the
underwriters, Vinson & Elkins L.L.P., Houston, Texas, will give a legal opinion
to the underwriters regarding other matters related to this offering. Winstead
Sechrest & Minick P.C., 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
4,027 trust units, and certain partners of Winstead Sechrest & Minick P.C. own
10,189 trust units. Herbert D. Simons is of counsel to Winstead Sechrest &
Minick P.C. and is a member of the board of directors of Cross Timbers Oil.
EXPERTS
Certain information appearing in this prospectus regarding the December 31,
1999 estimated quantities of reserves of the 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 audited financial statements incorporated by reference 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 incorporated by reference in this prospectus in reliance
upon the authority of said firm as experts in accounting and auditing.
47
<PAGE>
AVAILABLE INFORMATION
The trust and Cross Timbers Oil 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
statement. In addition, Cross Timbers Oil files annual, quarterly and current
reports, proxy statements and other information with the SEC. The trust also
files annual, quarterly and current reports, and other information with the
SEC. You may read and copy the registration statement and any of Cross Timbers
Oil's and the trust's 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 Oil's and the trust's filings are also
available to the public on the SEC Internet Web site at http://www.sec.gov.
The SEC allows the trust and Cross Timbers Oil to "incorporate by reference"
information the trust and Cross Timbers Oil file with it, which means that the
trust and Cross Timbers Oil 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.
The trust incorporates by reference in this prospectus the following
documents:
. its Annual Report on Form 10-K for the year ended December 31, 1999;
. its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2000
and June 30, 2000; 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.
Cross Timbers Oil incorporates by reference in this prospectus the following
documents:
. its Annual Report on Form 10-K for the year ended December 31, 1999;
. its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2000
and June 30, 2000;
. its Current Reports on Form 8-K filed on March 9, 2000 (Report dated
February 25, 2000), May 19, 2000 (Report dated May 16, 2000) and August
24, 2000 (Report dated August 15, 2000); 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 the trust and Cross Timbers Oil file 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
the trust or Cross Timbers Oil 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 Oil at 810 Houston Street, Suite
2000, Fort Worth, Texas 76102, Attention: Investor Relations, telephone (817)
870-2800.
48
<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.
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.
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.
MMcfe--One million cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.
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 Proceeds--Amount received by Cross Timbers from sale of production from
the underlying properties, less applicable costs.
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.
90% net profits interest--90% of the net proceeds from the carved
underlying properties, which are royalty and overriding royalty interests
in Texas, Oklahoma and New Mexico.
75% net profits interest--75% of the net proceeds from the carved
underlying properties, which are working interests in Texas and Oklahoma.
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.
49
<PAGE>
Proved Developed Reserves--Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
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
50
<PAGE>
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.
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.
Underlying property--Cross Timbers' interest in certain oil and gas
properties from which the net profits interests were carved and conveyed to the
trust. The underlying properties include royalty and overriding royalty
interests in producing and non-producing properties in Texas, Oklahoma and New
Mexico, and working interests in producing properties located in Texas and
Oklahoma.
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
51
<PAGE>
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.
52
<PAGE>
[LETTERHEAD OF MILLER AND LENTS, LTD.]
March 29, 2000
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, TX 76102
Re: Underlying Properties (100%)
Relating to the Cross Timbers Royalty
Trust
As of January 1, 2000
SEC Pricing Case
Gentlemen:
At your request, we estimated the proved reserves and future net revenue as
of January 1, 2000, attributable to the Cross Timbers Oil Company interest in
certain oil and gas properties prior to inclusion in the Cross Timbers Royalty
Trust, i.e., Underlying Properties (100%). The properties consist of
approximately 670 leases and 7,340 wells and are located primarily in New
Mexico, Oklahoma and Texas.
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 aggregate results of our
evaluations are as follows:
<TABLE>
<CAPTION>
===============================================================================================
Net Reserves as of 01/01/00 Future Net Revenue
--------------------------------------------------------------------
Oil and
Condensate, Gas, Undiscounted, Discounted at
Reserves Category MBbls. MMcf M$ 10% Per Year, M$
-----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Working Interest Properties
-----------------------------------------------------------------------------------------------
Proved Developed 3,436.8 1,400.4 42,382.8 21,728.1
Producing
-----------------------------------------------------------------------------------------------
Proved Undeveloped 210.8 36.9 3,167.8 1,002.9
-----------------------------------------------------------------------------------------------
Subtotal 3,647.6 1,437.3 45,550.6 22,731.0
-----------------------------------------------------------------------------------------------
Royalty Interest Properties
-----------------------------------------------------------------------------------------------
Proved Developed 808.8 37,062.9 96,364.1 47,410.3
Producing
-----------------------------------------------------------------------------------------------
Proved Undeveloped 3.7 2,098.2 4,785.3 1,679.2
-----------------------------------------------------------------------------------------------
Subtotal 812.5 39,161.1 101,149.4 49,089.5
-----------------------------------------------------------------------------------------------
Total Underlying Properties (100%)
-----------------------------------------------------------------------------------------------
Proved Developed 4,245.6 38,463.3 138,746.9 69,138.4
Producing
-----------------------------------------------------------------------------------------------
Proved Undeveloped 214.5 2,135.1 7,953.1 2,682.1
-----------------------------------------------------------------------------------------------
TOTAL 4,460.1 40,598.4 146,700.0 71,820.5
===============================================================================================
</TABLE>
<PAGE>
[LETTERHEAD OF MILLER AND LENTS, LTD]
Cross Timbers Oil Company March 29, 2000
Page 2
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. Future costs of abandoning facilities
and wells and of the restoration of producing properties to satisfy
environmental standards were not deducted from total 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 reserve category,
interest type, and state. Also included in the exhibits are one-line summaries
for the total royalty trust and for each state showing the proved reserves and
future net revenue for each property in the total royalty trust, in the royalty
interest category, in the working interest category, and in each state.
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 well costs or waterflood expansions. 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. Proved undeveloped reserves in the San Juan Basin are based
on the estimated ultimate recoveries of wells in the area of the undeveloped
locations. The proved undeveloped reserve estimates for proposed waterflood
expansions were based on the performance of pilot waterfloods or waterfloods in
other areas of the fields. Volumetric estimates prepared by the unit operator
or engineering committee were employed in estimating the recovery efficiencies
of previous pilots or waterfloods, in predicting the performance of future
waterfloods, and in adjusting the predicted performance of future development
wells based on location in the field. The estimated timing of infill drilling
and waterflood expansion was provided by Cross Timbers Oil Company. As the
actual results of the infill wells and waterflood expansions become available,
our estimates of reserves may be significantly revised.
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
<PAGE>
[LETTERHEAD OF MILLER AND LENTS, LTD.]
Cross Timbers Oil Company March 29, 2000
Page 3
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.
/s/ James C. Pearson
By_______________________________________________
James C. Pearson
Chairman
[SEAL OF JAMES C. PEARSON
STATE OF TEXAS
LICENSED
PROFESSIONAL ENGINEER]
JCP/mk
<PAGE>
Attachment 1
1-1-2000
Underlying Properties (100%)
Relating to the
Cross Timbers Royalty Trust
SEC PRICING CASE
A. Oil Price All oil/condensate prices held constant at a posted
price of $22.75 per barrel through the life of the
property. (Adjust for gravity, transportation charges,
and crude marketing arrangements.)
B. Gas/NGL Price Estimated 12/31/99 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.
<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>
[MILLER AND LENTS, LTD LETTERHEAD]
[FIFTY LOGO]
March 29, 2000
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, TX 76102
Re: Cross Timbers Royalty Trust
Net Profits Interests as of January 1, 2000
SEC Pricing Case
Gentlemen:
At your request, we estimated the proved reserves and future net revenue as
of January 1, 2000, attributable to the Cross Timbers Royalty Trust interests in
certain oil and gas properties located primarily in New Mexico, Oklahoma and
Texas. The properties consist of approximately 670 leases and 7,340 wells.
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 aggregate results of our
evaluations are as follows:
<TABLE>
<CAPTION>
Net Reserves as of 01/01/00 Future Net Reserves
--------------------------------------------------------------------
Oil and
Condensate, Gas, Undiscounted, Discounted at
Reserves Category MBbls. MMcf M$ 10% Per Year, M$
-----------------------------------------------------------------------------------------------
Working Interest Properties
-----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Proved Developed Producing 1,375.0 570.3 31,807.4 16,296.1
-----------------------------------------------------------------------------------------------
Proved Undeveloped 104.0 18.2 2,375.8 752.2
-----------------------------------------------------------------------------------------------
Subtotal 1,479.0 588.5 34,183.2 17,048.3
-----------------------------------------------------------------------------------------------
Royalty Interest Properties
-----------------------------------------------------------------------------------------------
Proved Developed Producing 715.7 33,036.4 85,843.9 42,066.4
-----------------------------------------------------------------------------------------------
Proved Undeveloped 3.4 1,888.4 4,306.8 1,511.2
-----------------------------------------------------------------------------------------------
Subtotal 719.1 34,924.8 90,150.7 43,577.6
-----------------------------------------------------------------------------------------------
Total Net Profits Interests
-----------------------------------------------------------------------------------------------
Proved Developed Producing 2,090.7 33,606.7 117,651.3 58,362.5
-----------------------------------------------------------------------------------------------
Proved Undeveloped 107.4 1,906.6 6,682.6 2,263.4
-----------------------------------------------------------------------------------------------
TOTAL 2,198.1 35,513.3 124,333.9 60,625.9
===============================================================================================
</TABLE>
<PAGE>
[LETTERHEAD OF MILLER AND LENTS, LTD.]
Cross Timbers Oil Company March 29, 2000
Page 2
The Cross Timbers Royalty Trust interests evaluated herein are comprised of
a 75 percent net profits interest in certain Cross Timbers Oil Company working
interest properties and a 90 percent net overriding royalty interest of certain
Cross Timbers Oil Company royalty interest properties. As your instruction, the
net oil and condensate reserves and the net natural gas reserves attributable to
the Cross Timbers Royalty Trust interests were computed from 90 percent of the
Cross Timbers Oil Company interests in the royalty interest properties and from
75 percent of the Cross Timbers Oil Company interests in the working interest
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
attributed to the property.
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. Future costs of abandoning facilities
and wells and of the restoration of producing properties to satisfy
environmental standards were not deducted from total revenues as such estimates
are beyond the scope of this assignment.
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 well costs or waterflood expansions. 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. Proved undeveloped reserves in the San Juan Basin are based
on the estimated ultimate recoveries of wells in the area of the undeveloped
locations. The proved undeveloped reserve estimates for proposed waterflood
expansions were based on the performance of pilot waterfloods or waterfloods in
other areas of the fields. Volumetric estimates prepared by the unit operator
or engineering committee were employed in estimating the recovery efficiencies
of previous pilots or waterfloods, in predicting the performance of future
waterfloods, and in adjusting the predicted performance of future development
wells based on location in the field. The estimated timing of infill drilling
and waterflood expansion was provided by Cross Timbers Oil Company. As the
actual results of the infill wells and waterflood expansions become available,
our estimates of reserves may be significantly revised.
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.
<PAGE>
[LETTERHED OF MILLER AND LENTS, LTD.]
Cross Timbers Oil Company March 29, 2000
Page 3
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
Chairman [SEAL OF JAMES C. PEARSON
STATE OF TEXAS LICENSED
PROFESSIONAL ENGINEER]
JCP/mk
<PAGE>
Attachment 1
1-1-2000
Cross Timbers Royalty Trust
Net Profits Interests
SEC PRICING CASE
A. Oil Price All oil/condensate prices held constant at a posted
price of $22.75 per barrel through the life of the
property. (Adjust for gravity, transportation charges,
and crude marketing arrangements.)
B. Gas/NGL Price Estimated 12/31/99 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.
<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>
1,200,000 Trust Units
Cross Timbers Royalty Trust
---------------
PROSPECTUS
October , 2000
---------------
Lehman Brothers
Dain Rauscher Wessels
Fidelity Capital Markets
a division of National Financial Services LLC
<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................................................... $ 5,817
NASD filing fee.................................................... 2,472
Printing and Engraving Expenses.................................... 175,000
Legal Fees and Expenses............................................ 130,000
Accountants' Fees and Expenses..................................... 35,000
Miscellaneous Fees and Expenses.................................... 151,711
--------
Total.............................................................. $500,000
========
</TABLE>
Item 14. Indemnification of Directors and Officers.
Section 6.02 of the Trust Indenture provides that the trustee will be
indemnified by the trust estate 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 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 $25 million, which includes 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 --Cross Timbers Royalty Trust Restated Royalty Trust Indenture,
incorporated by reference from Exhibit 3.1 to Amendment No. 1 to the
trust's Registration Statement on Form S-1 (Reg. No. 33-44385), filed
January 24, 1992.
5.1* --Opinion of Kelly, Hart & Hallman, P.C. as to legality of the
securities registered hereby.
8.1* --Opinion of Winstead Sechrest & Minick P.C. regarding tax matters.
10.1 --Form of 90% Net Overriding Royalty Conveyance and Corrections,
incorporated by reference from Exhibits 10.1--10.4 to Amendment No. 1
to the trust's Registration Statement on Form S-1 (Reg. No. 33-
44385), filed January 24, 1992.
10.2 --Form of 75% Net Overriding Royalty Conveyance, incorporated by
reference from Exhibit 10.5 to Amendment No. 1 to the trust's
Registration Statement on Form S-1 (Reg. No. 33-44385), filed January
24, 1992.
15.1 --Awareness letter of Arthur Andersen LLP.
15.2 --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 Kelly, Hart & Hallman, P.C., (set forth in their opinion
filed as Exhibit 5.1).
23.4 --Consent of Winstead Sechrest & Minick P.C. (set forth in their
opinion filed as Exhibit 8.1).
24.1+ --Powers of attorney.
24.2 --Power of attorney.
</TABLE>
--------
* To be filed.
+ Previously filed.
Item 17. Undertakings.
The trust and the Company hereby undertake:
(a) that, for purposes of determining any liability under the Securities Act
of 1933, each filing of the trust's and 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.
II-2
<PAGE>
(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.
(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 October 6, 2000.
CROSS TIMBERS ROYALTY TRUST
By: Bank of America, N.A., as
Trustee
By: /s/ Ron E. Hooper
----------------------------------
Ron. E Hooper
Vice President
CROSS TIMBERS OIL COMPANY
By: /s/ Louis G. Baldwin
----------------------------------
Louis G. Baldwin
Executive Vice President and
Chief Financial Officer
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 October 6, 2000
______________________________________ Board and Chief Executive
Bob R. Simpson Officer (Principal
Executive Officer)
/s/ Steffen E. Palko* Director, Vice Chairman of October 6, 2000
______________________________________ the Board and President
Steffen E. Palko
/s/ J. Luther King, Jr.* Director October 6, 2000
______________________________________
J. Luther King, Jr.
/s/ Jack P. Randall* Director October 6, 2000
______________________________________
Jack P. Randall
/s/ Scott G. Sherman* Director October 6, 2000
______________________________________
Scott G. Sherman
/s/ Herbert D. Simons* Director October 6, 2000
______________________________________
Herbert D. Simons
/s/ Louis G. Baldwin Executive Vice President October 6, 2000
______________________________________ and Chief Financial
Louis G. Baldwin Officer (Principal
Financial Officer)
/s/ Bennie G. Kniffen Senior Vice President and October 6, 2000
______________________________________ 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.
15.2 --Awareness letter of Arthur Andersen LLP.
23.1 --Consent of Arthur Andersen LLP.
23.2 --Consent of Miller and Lents, Ltd.
24.2 --Power of attorney.
</TABLE>
