As filed with the Securities and Exchange Commission on January 25, 1999.
Registration No. 333-68441
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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AMENDMENT NO. 1 TO
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
on
Form S-1 -------------- Form S-3
HUGOTON ROYALTY TRUST CROSS TIMBERS OIL COMPANY
(Exact name of co-registrant as
(Exact name of co-registrant as specified in its charter)
specified in its charter) Delaware
Texas
(State or other jurisdiction of
(State or other jurisdiction of incorporation or organization)
incorporation or organization)
58-6379215 75-2347769
(I.R.S. Employer Identification No.)
(I.R.S. Employer Identification No.)
901 Main St., 17th Floor 810 Houston Street, Suite 2000
Dallas, Texas 75202 Fort Worth, Texas 76102
(214) 508-2440 (817) 870-2800
(Address, including zip code, and (Address, including zip code, and
telephone telephone
number, including area code, of number, including area code, of
registrant's principal executive registrant's principal executive
offices) offices)
Frank G. McDonald, Esq. Bob R. Simpson
901 Main St., 17th Floor 810 Houston Street, Suite 2000
Dallas, Texas 75202 Fort Worth, Texas 76102
(214) 508-2400 (817) 870-2800
(Name, address, including zip code, (Name, address, including zip code, and
and telephone number, including area code,
telephone number, including area code, of
of agent for service)
agent for service)
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Copies to:
F. Richard Bernasek, Esq. James M. Prince, Esq.
Kelly, Hart & Hallman, P.C. Andrews & Kurth L.L.P.
201 Main Street, Suite 2500 600 Travis, Suite 4200
Fort Worth, Texas 76102 Houston, Texas 77002
(817) 332-2500 (713) 220-4300
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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. [_]
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CALCULATION OF REGISTRATION FEE
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Title of Each Class of Proposed Maximum Amount of
Securities to Be Registered Aggregate Offering Price(1) Registration Fee(2)
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Units of Beneficial
Interest.................... $172,500,000 $47,955
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(1) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457(o).
(2) $24,936.60 was paid previously.
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.
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++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
+The information in this prospectus is not complete and may be changed. We may +
+not sell these securities until the registration statement filed with the +
+Securities and Exchange Commission is effective. This prospectus is not an +
+offer to sell these securities and we are not soliciting offers to buy these +
+securities in any state where the offer or sale is not permitted. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
Subject to Completion. Dated January 25, 1999.
Hugoton Royalty Trust
15,000,000 Trust Units
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This is an initial public offering of units of beneficial interest in the
Hugoton Royalty Trust. Cross Timbers Oil Company has formed the trust and is
offering all of the trust units to be sold in this offering, and Cross Timbers
will receive all proceeds from the offering. The trust will not receive any
proceeds from the offering.
There is currently no public market for the trust units. Cross Timbers
expects that the public offering price will be between $8.00 and $10.00 per
trust unit. The trust units have been approved for listing on the New York
Stock Exchange under the symbol "HGT".
The Trust Units. Trust units are units of beneficial ownership of the trust
and represent undivided interests in the trust. They do not represent any
interest in Cross Timbers.
The Trust. The trust owns net profits interests in principally natural gas
producing properties located in the Hugoton area of Kansas and Oklahoma, the
Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The net
profits interests entitle the trust to receive 80% of the net proceeds from
the sale of production from these oil and natural gas properties owned by
Cross Timbers.
The Trust Unitholders. As a trust unitholder, you will receive monthly
distributions of cash that the trust receives for its net profits interests
from the sale of oil and natural gas produced from the underlying
properties.
See "Risk Factors" beginning on page 10 to read about certain information you
should consider before purchasing trust units.
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Neither the Securities and Exchange Commission nor any other regulatory body
has approved or disapproved of these securities or passed upon the accuracy or
adequacy of this prospectus. Any representation to the contrary is a criminal
offense.
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Per
Trust
Unit Total
----- -----
Initial public offering price....................................... $ $
Underwriting discounts.............................................. $ $
Proceeds, before expenses, to Cross Timbers......................... $ $
The underwriters may, under certain circumstances, purchase from Cross
Timbers up to an additional 2,250,000 trust units at the initial public
offering price less the underwriting discount.
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The underwriters expect to deliver the trust units against payment in New
York, New York on , 1999.
Goldman, Sachs & Co.
Lehman Brothers
Bear, Stearns & Co. Inc.
Dain Rauscher Wessels
a division of Dain Rauscher Incorporated
Donaldson, Lufkin & Jenrette
A.G. Edwards & Sons, Inc.
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Prospectus dated , 1999.
[MAP OF UNDERLYING PROPERTIES APPEARS HERE]
2
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
& Lents, Ltd., an independent engineering firm ("Miller & Lents"), provided the
estimates of proved oil and natural gas reserves at December 31, 1998 included
in this prospectus. These estimates are contained in summaries by Miller &
Lents of the reserve reports as of December 31, 1998, 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."
Hugoton Royalty Trust
Hugoton Royalty Trust was formed in December 1998 by Cross Timbers Oil
Company. Cross Timbers conveyed to the trust net profits interests in certain
oil and natural gas producing properties, referred to in this prospectus as the
"underlying properties." The net profits interests entitle the trust to receive
80% of net proceeds from the sale of oil and natural gas from these properties.
The underlying properties are located in the Hugoton area of Kansas and
Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming.
The trust will make monthly distributions of substantially all of its
income to holders of its trust units. On your federal income tax returns, you
will be required to include your proportionate share of trust net income. In
addition, you will be entitled to claim a depletion deduction and a small tax
credit relating to production from the underlying properties. The deductions
and credits will permit you to defer or reduce taxes on a significant portion
of the income you receive from the trust.
Cross Timbers will determine net proceeds monthly on a state-by-state basis.
It will collect cash received from the sale of production and deduct property
and production taxes, development and production costs and overhead. Cross
Timbers will pay to the trust 80% of the net profits remaining after deducting
those costs.
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 development and production 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 does not expect future production costs for the
underlying properties to change significantly as compared to recent historical
costs. It expects the level of development costs to decline significantly as
compared to recent historical amounts.
3
Cross Timbers' Ownership Interest
The underlying properties include Cross Timbers' undivided interests in oil
and natural gas leases and the production from existing and future wells on
those leases. Accordingly, if Cross Timbers successfully drills additional
wells on acreage covered by these leases or successfully conducts other
development activities, those activities will enhance production from the
underlying properties. The trust will benefit from increased production, net of
related development costs. Cross Timbers' interests in the underlying
properties are predominantly "working interests," which require it to bear the
costs of exploration, production and development.
Cross Timbers' retained interest in the underlying properties entitles it to
20% of the net proceeds from production. Cross Timbers believes that a 20%
ownership interest will provide incentive to operate and develop the underlying
properties in an efficient and cost effective manner. Cross Timbers is under no
obligation to continue to own the underlying properties, but currently intends
to do so.
The following chart shows the relationship of Cross Timbers, the trust and
the public trust unitholders, assuming no exercise of the underwriters' over-
allotment option.
[CHART SHOWING RELATIONSHIP OF TRUST TO CROSS TIMBERS APPEARS HERE]
The Underlying Properties
The underlying properties are located in three of the best known and most
prolific natural gas producing areas in the United States. As of December 31,
1998, proved reserves of the underlying properties were estimated at 539 Bcfe
in the Reserve Report. Approximately 30% of the proved reserves were located in
the Hugoton area of Kansas and Oklahoma, 37% were located in the Anadarko Basin
of Oklahoma and 33% were located in the Green River Basin of Wyoming. These
areas are characterized by wells with low rates of annual decline in production
and low production costs. Wells in these areas have been producing for many
years, in some cases since the 1920s. Reserve estimates for properties with
long production histories are generally more reliable than estimates for
properties with short histories.
4
Long Life of Properties
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, 1998 was 13.0 years. An index of 13.0 years shows a
long producing life for an oil and natural gas property. This compares
favorably to an average index of 9.2 years for U.S. oil and natural gas
properties of publicly reporting companies at year-end 1997. Because production
rates naturally decline over time, the reserve-to-production 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 40 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 93% of the discounted
present value of estimated future net revenues from the underlying properties.
Control of Operations
The right to operate an oil and natural gas lease is important because the
operator controls the timing and amount of discretionary expenditures for
operational and development activities. Cross Timbers operates approximately
90% of the underlying properties, based on the discounted present value of
estimated future net revenues.
History of Low Cost Reserve Additions
Cross Timbers has a record of successfully adding reserves to the underlying
properties through development at costs substantially below the industry
average. Over the last three years Cross Timbers added 187 Bcfe of proved
reserves, or 156% of production, at a cost of $0.47 per Mcfe. For publicly
reporting companies in the United States, the average industry cost of adding
oil and natural gas reserves from 1995 through 1997 was $0.96 per Mcfe.
Over the last three years proved reserve additions on existing wells on the
underlying properties included upward revisions of 23 Bcfe. These upward
revisions were due to better than projected production performance and
development results, reduced production costs, increased oil and natural gas
prices in some years, gathering system improvements and improved technology.
Cross Timbers believes that the underlying properties will experience reserve
additions in the future, but cannot assure you that this will occur.
Effect of Planned Development Program
Without development projects, the underlying properties would typically
experience a 6% to 10% annual decline in production. Cross Timbers plans
development expenditures on the underlying properties of $12 million per year
for the next four years. The Reserve Report projects that these development
expenditures will reduce the natural rate of decline in production to
approximately 4% per year.
Additional Development Opportunities
Cross Timbers believes that the underlying properties will offer economic
development projects that are not included in the Reserve Report. These
additional development opportunities could significantly increase production
and proved reserves above those projected in the Reserve Report. Additional
development opportunities could include:
. adding pipeline compression and pumps to improve production flow;
. opening new producing zones in existing wells;
5
. deepening existing wells to new producing zones;
. performing mechanical and chemical treatments to stimulate production
rates; and
. drilling additional wells.
Cross Timbers may face conflicts of interest in allocating its resources
between additional development of the underlying properties and development of
other oil and natural gas properties that it now owns or may own in the future.
Cross Timbers allocates resources for development based on expected rates of
return. The underlying properties have historically provided attractive rates
of return on development projects compared to Cross Timbers' other properties,
and are expected to continue to do so in the future.
Substantial Operating Margins
The underlying properties have historically generated substantial operating
margins. Production expenses, production and property taxes, transportation
costs and overhead on the underlying properties averaged $0.68 per Mcfe during
1998. During the same period, the sales price for oil and natural gas produced
from the underlying properties averaged $2.03 per Mcfe, providing an operating
margin of $1.35 per Mcfe.
Control of Natural Gas Gathering Systems
Cross Timbers and its affiliates operate natural gas gathering systems for
approximately 70% of the production from the underlying properties. This allows
Cross Timbers to manage gathering operations to maintain optimum natural gas
production.
Proved Reserves
Estimated proved reserves of the underlying properties are approximately 95%
natural gas and 5% oil, based on the Reserve Report. The following table
provides, as of December 31, 1998, estimated proved oil and natural gas
reserves, and undiscounted and discounted estimated future net revenues, for
the underlying properties and the net profits interests. Proved reserves in the
table are based on oil and natural gas prices realized by Cross Timbers as of
December 31, 1998, which were $11.24 per Bbl of oil and $2.01 per Mcf of
natural gas. The amounts of estimated future net revenues from proved reserves
shown in the table are before income taxes. Discounted future net revenues are
based on a discount rate of 10%, which is the rate required by the Securities
and Exchange Commission. Reserve estimates are subject to revision.
Proved Reserves
---------------------------
Estimated Future
Net Revenues from
Gas Proved Reserves
Gas Oil Equivalents ------------------------
(MMcf) (MBbls) (MMcfe) Undiscounted Discounted
------- ------- ----------- ------------ -----------
(in thousands, except
per Unit data)
Underlying properties
(100%):
Anadarko Basin......... 174,433 3,621 196,159 $258,416 $150,711
Green River Basin...... 178,970 270 180,590 242,897 104,193
Hugoton Area........... 161,670 139 162,504 173,205 92,273
------- ----- ------- -------- --------
Total................ 515,073 4,030 539,253 $674,518 $347,177
======= ===== ======= ======== ========
Underlying properties
(80%)................... 412,058 3,224 431,402 $539,615 $277,742
Net profits interests
(a)..................... 282,297 2,193 295,455 $539,615 $277,742
Per trust unit........... -- -- -- $ 13.49 $ 6.94
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(a) Proved reserves for the net profits interests are calculated by subtracting
from 80% of proved reserves of the underlying properties, reserve
quantities of a sufficient value to pay 80% of the
6
future estimated costs, before overhead and trust administrative expenses,
that are deducted in calculating net proceeds. Accordingly, proved reserves
for the net profits interests reflect quantities that are calculated after
reductions for future costs and expenses based on price and cost
assumptions used in the reserve estimates.
Producing Areas
The underlying properties consist of predominantly natural gas producing
leases located in the States of Kansas, Oklahoma and Wyoming. These productive
areas include:
. Hugoton Area. The largest natural gas producing region in North America,
the Hugoton area covers an estimated five million acres in parts of
Oklahoma, Kansas and Texas. The area has produced more than 64 trillion
cubic feet of natural gas since 1922. Wells in this area produce
primarily from formations less than 3,000 feet in depth. Wells also
produce from deeper formations at depths ranging from 3,000 to 7,000
feet. The average 1999 net daily production for the underlying
properties in this area estimated in the Reserve Report is approximately
36,700 Mcf of natural gas and 40 Bbls of oil per day.
. Anadarko Basin. Cross Timbers properties in this area are concentrated
in Major County, Oklahoma as well as the Elk City Field and other areas
in western Oklahoma. Oil and natural gas were first discovered in Major
County and the Elk City Field in the 1940s. Natural gas wells in this
region produce from a variety of productive zones and geological
structures. Principal productive zones range in depth from 6,500 to
9,400 feet. The average 1999 net daily production for the underlying
properties in this area estimated in the Reserve Report is approximately
45,000 Mcf of natural gas and 1,100 Bbls of oil per day.
. Green River Basin. Located in southwestern Wyoming, this area includes
Cross Timbers properties in the Fontenelle area. Wells in this area have
produced since the early 1970s from formations ranging in depth from
7,500 to 10,000 feet. The average 1999 net daily production for the
underlying properties in this area estimated in the Reserve Report is
approximately 30,500 Mcf of natural gas and 50 Bbls of oil per day.
7
Pro Forma Trust Distributions and Related Data
The following table contains oil and natural gas sales volumes and average
sales prices for production from the underlying properties and the calculation
of trust distributable income:
. for 1996, 1997 and 1998, based on historical net proceeds from the
underlying properties. See the audited statements of revenues and direct
operating expenses for the years ended December 31, 1996, 1997 and 1998
and the pro forma statement of distributable income for the year ended
December 31, 1998 included in this prospectus.
. for 1998, on an adjusted basis using the reduced development costs
budgeted for 1999. Cross Timbers aggressively developed the underlying
properties during 1996, 1997 and 1998, but intends to reduce development
costs to approximately $12 million per year for the next four years. The
"Adjusted 1998" data in the table are the same as the actual 1998 data,
except for the effects of reducing development costs to $12 million. The
"Adjusted 1998" data allow a comparison between the "Hypothetical 1999"
data and the 1998 data, adjusted to show the effect of the expected
reduced development expenditures during 1999.
. for 1999, on a hypothetical basis using the assumptions and methods of
calculation described under "Hypothetical Annual Cash Distributions."
These calculations were made using hypothetical realized prices of $2.00
for natural gas and $11.75 for oil, which equates to a $10.00 posted oil
price. The "Hypothetical 1999" data in the table are not a projection or
forecast of the actual or estimated results from an investment in the
trust units. They are intended only to demonstrate the calculation of
distributable income based on assumed production levels, prices and
costs. See "Hypothetical Annual Cash Distributions."
"Trust distributable income per trust unit" for each year is a pro forma
amount, assuming the net profits interests were conveyed to the trust prior
to January 1, 1996 and that trust administrative expense was $300,000
annually.
Year Ended December 31,
------------------------- Adjusted Hypothetical
1996 1997 1998 1998 1999
------- ------- ------- -------- ------------
(in thousands, except per unit data)
Underlying Properties
Sales Volumes:
Natural gas (Mcf).......... 36,143 37,172 38,535 38,535 41,027
Oil (Bbls)................. 455 470 479 479 434
Average Price:
Natural gas (per Mcf)...... $ 1.67 $ 2.21 $ 2.00 $ 2.00 $ 2.00
Oil (per Bbl).............. $ 19.95 $ 20.63 $ 14.78 $ 14.78 $ 11.75
Calculation of Distributable
Income
Revenues:
Natural gas sales.......... $60,502 $82,192 $77,124 $77,124 $82,054
Oil sales.................. 9,075 9,704 7,083 7,083 5,100
------- ------- ------- ------- -------
Total.................... 69,577 91,896 84,207 84,207 87,154
------- ------- ------- ------- -------
Costs:
Production and property
taxes and transportation.. 5,919 9,173 9,170 9,170 9,310
Production expenses........ 11,359 12,837 13,031 13,031 11,937
Development costs.......... 14,392 40,027 33,019 12,000 12,000
Overhead................... 4,557 5,354 6,198 6,198 6,200
------- ------- ------- ------- -------
Total................... 36,227 67,391 61,418 40,399 39,447
------- ------- ------- ------- -------
Net proceeds................. 33,350 24,505 22,789 43,808 47,707
Net profits percentage....... 80% 80% 80% 80% 80%
------- ------- ------- ------- -------
Trust royalty income......... 26,680 19,604 18,231 35,046 38,166
Trust administrative
expense..................... 300 300 300 300 300
------- ------- ------- ------- -------
Trust distributable income... $26,380 $19,304 $17,931 $34,746 $37,866
======= ======= ======= ======= =======
Trust distributable income
per trust unit.............. $ 0.66 $ 0.48 $ 0.45 $ 0.87 $ 0.95
======= ======= ======= ======= =======
8
The Offering
Trust units offered by Cross
Timbers................... 15,000,000
Trust units outstanding... 40,000,000
Use of proceeds........... Cross Timbers will receive all net proceeds
from this offering, which will be used to
repay indebtedness under its revolving credit
facility.
NYSE symbol............... HGT
Investing in Trust Units
Investing in these trust units differs from investing in corporate stock in
the following ways:
. 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
deductions and tax credits;
. 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.
9
RISK FACTORS
Trust Distributions Will Be Sensitive to Changing Oil and Natural Gas Prices
The trust's monthly cash distributions are highly dependent upon the prices
realized from the sale of oil and, in particular, natural gas. Oil and natural
gas prices can fluctuate widely on a month-to-month basis in response to a
variety of factors that are beyond the control of the trust and Cross Timbers.
These factors include, among others:
. weather conditions;
. the supply and price of foreign oil and natural gas;
. the level of consumer product demand;
. worldwide economic conditions;
. political conditions in the Middle East;
. government regulations;
. the price and availability of alternative fuels;
. the proximity to, and capacity of, transportation facilities; and
. worldwide energy conservation measures.
Lower oil and natural gas prices may reduce the amount of oil and natural
gas that is economic to produce and reduce net profits available to the trust.
The volatility of energy prices reduces the accuracy of estimates of future
cash distributions to trust unitholders.
Trust Distributions Are Affected by Production and Development Costs
Production and development costs on the underlying properties are deducted
in the calculation of the trust's share of net proceeds. Accordingly, higher or
lower production and development costs 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 years, see "The Net Profits Interests and the
Underlying Properties--Pro Forma Distributable Income and Oil and Natural Gas
Sales Volumes."
If development and production costs of underlying properties located in a
particular state exceed the proceeds of production from the properties, the
trust will not receive net proceeds for those properties until future proceeds
from production in that state exceed the total of the excess costs plus accrued
interest during the deficit period. Development activities may not generate
sufficient additional revenue to repay the costs.
Trust Reserve Estimates Are Uncertain
The value of the trust units will depend upon, among other things, the
reserves attributable to the trust's net profits interests. Estimating reserves
is inherently uncertain. Ultimately, actual production, revenues and
expenditures for the underlying properties will vary from estimates and those
variations could be material. Petroleum engineers consider many factors and
make assumptions in estimating reserves. Those factors and assumptions include:
. historical production from the area compared with production rates from
other 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.
10
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 Net Profits Interests and the Underlying
Properties--Oil and Natural Gas Reserves--Proved 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.
The Trust Does Not Control Operations and Development
Neither the trustee nor the trust unitholders can influence or control the
operation or future development of the underlying properties. Cross Timbers is
unable to significantly influence the operations or future development of the
underlying properties that it does not operate, which contain about 10% of the
proved reserve value of all underlying properties.
The current operators of the underlying properties, including Cross Timbers,
are under no obligation to continue operating the properties. Cross Timbers can
sell any of the underlying properties that it operates and relinquish the
ability to control or influence operations. Neither the trustee nor trust
unitholders have the right to replace an operator.
Cross Timbers May Transfer or Abandon Underlying Properties
Although it has no current intention of selling any of the underlying
properties, Cross Timbers may at any time transfer all or part of the
underlying properties. You will not be entitled to vote on any transfer, and
the trust will not receive any proceeds of the transfer. Following any material
transfer, the underlying properties will continue to be subject to the net
profits interests of the trust, but the net proceeds from the transferred
property would be calculated separately and paid by the transferee. The
transferee would be responsible for all of Cross Timbers' obligations relating
to the net profits interests on the portion of the underlying properties
transferred, and Cross Timbers would have no continuing obligation to the trust
for those properties.
Cross Timbers and any transferee may abandon any well or property if it
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 Interest 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 after 1999. Sale of all the net profits interests will
terminate the trust. The net proceeds of any sale will be distributed to the
trust unitholders.
11
Cross Timbers May Dispose of Remaining Trust Units
Cross Timbers currently owns 100% of the trust units and will sell 37.5% of
the trust units in this offering, or 43% if the underwriters' over-allotment
option is exercised in full. Cross Timbers has granted options to its executive
officers to purchase $12 million of its retained trust units at the initial
public offering price. It may use some or all of the remaining trust units it
owns for a number of corporate purposes, including:
. selling them for cash; and
. exchanging them for interests in oil and natural gas properties or
securities of oil and natural gas companies.
If Cross Timbers sells additional trust units or exchanges trust units in
connection with acquisitions or if Cross Timbers executives acquire trust units
upon exercise of options, then additional trust units will be available for
sale in the market. Cross Timbers expects these additional trust units to
increase market liquidity, but cannot presently determine whether they will
impact the market price for trust units. The release of these additional trust
units into the public market may cause the market price to decrease. See
"Selling Trust Unitholder."
Cross Timbers Will Receive Payments Deducted from Net Proceeds
Cross Timbers and some of its affiliates receive payments under existing
contracts for services relating to the underlying properties. Payments to Cross
Timbers and its affiliates will be deducted in determining net proceeds payable
to the trust. This will reduce the amounts available for distribution to the
trust unitholders. These payments will include:
. payments to Cross Timbers for production and development costs to
operate wells;
. payments to Cross Timbers affiliates for marketing, gathering,
processing and transportation services; and
. overhead fees to operate the underlying properties, which include
accounting and other administrative functions.
In addition to providing services, Cross Timbers affiliates purchase
production from the underlying properties. Approximately two-thirds of 1998 oil
and natural gas sales from the underlying properties were made to Cross Timbers
affiliates.
Cross Timbers believes that the terms of these contracts are competitive
with those that could be obtained from unrelated third parties. Cross Timbers
is permitted under the conveyance agreements creating the net profits interests
to enter into new contracts without any negotiations or other involvement by
independent third parties. Provisions in the conveyance agreements, however,
require that
. future contracts with affiliates relating to transportation, processing
or marketing of oil and natural gas cannot materially exceed charges
prevailing in the area for similar services; and
. future oil and natural gas sales contracts with affiliates must provide
that the affiliates retain not more than 2% of the proceeds from the
sale of production by the affiliates.
Cross Timbers Will Have Potential Conflicts of Interest
Because Cross Timbers has interests in oil and natural gas properties not
included in the trust, the interests of Cross Timbers and the trust unitholders
may not always be in common. For example,
. in setting budgets for development and production expenditures for Cross
Timbers' properties, including the underlying properties, Cross Timbers
may make decisions that could adversely affect future production from
the underlying properties;
12
. Cross Timbers could continue to operate an underlying property and earn
an overhead fee even though abandonment of the property might be more
beneficial to trust unitholders; and
. Cross Timbers could decide to sell or abandon some or all of the
underlying properties, and that decision may not be in the best
interests of the trust unitholders.
Except for specified matters that require approval of the trust unitholders
described in "Description of the Trust Indenture," the documents governing the
trust do not provide a mechanism for resolving these conflicting interests.
Trust Unitholders Will Have Limited Voting Rights
Your voting rights as a trust unitholder are more limited than those of
stockholders of most public corporations. For example, there is no requirement
for annual meetings of trust unitholders or for an annual or other periodic
re-election of the trustee.
Additionally, trust unitholders have no voting rights in Cross Timbers and
therefore will have no ability to influence its operations of the underlying
properties.
Trust Unitholders Will Have Limited Ability to Enforce Rights
The trust indenture does not provide you with any right to compel the
trustee to take action against Cross Timbers or any other future owner of the
underlying properties to honor the net profits interests. Rather, the trust
indenture and related trust law permit the trustee and the trust to bring
those claims. If the trustee does not take appropriate action to enforce
provisions of the net profits interests, your recourse as a trust unitholder
would likely be limited to bringing a lawsuit against the trustee to compel
the trustee to take specified actions.
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 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 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' Liability to the Trust Is Limited
The net profits interest conveyance provides that Cross Timbers will not be
liable to the trust for performing its duties in operating the underlying
properties as long as it acts in good faith. Cross Timbers has no fiduciary
duty to protect the interests of the trust.
Amendment of the Trust Indenture Requires Supermajority Vote
Trust unitholders may amend the trust indenture by a vote of the holders of
80% or more of the outstanding trust units. Any amendment will be binding on
you, regardless of whether you voted for or against the amendment. Some
provisions of the trust indenture cannot be amended without the consent of all
trust unitholders. See "Description of the Trust Indenture--Creation and
Organization of the Trust; Amendments."
13
Trust Assets Are Depleting Assets
The net proceeds payable to the trust are derived from the sale of depleting
assets. Accordingly, the portion of the distributions to trust unitholders
attributable to depletion may be considered a return of capital. The reduction
in proved reserve quantities is a common measure of the depletion. Future
maintenance and development projects on the underlying properties will affect
the quantity of proved reserves. The timing and size of these projects will
depend on the market prices of oil and natural gas. If operators of the
properties do not implement additional maintenance and development projects,
the future rate of production decline of proved reserves may be higher than the
rate currently expected by Cross Timbers. For federal income tax purposes,
depletion is reflected as a deduction, which is anticipated to be $0.73 per
trust unit in 1999, based on a trust unit purchase price of $9.00. See "Federal
Income Tax Consequences--Royalty Income and Depletion."
Tax Considerations
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 (1) depletion deductions equal to the greater of
percentage depletion or cost depletion, computed on the tax basis of
your trust units and (2) your pro rata share of other deductions of the
trust; and
. you will be allowed the tax credit for your share of qualifying natural
gas production from tight sands provided under Section 29 of the
Internal Revenue Code, subject to limitations described in this
prospectus.
See "Federal Income Tax Consequences."
Tax counsel believes that its opinion is in accordance with the present
position of the Internal Revenue Service (the "IRS") regarding grantor trusts.
Neither Cross Timbers nor the trustee has requested a ruling from the IRS
regarding these tax questions. Neither Cross Timbers nor the trust can assure
you that they would be granted such a ruling if requested or that the IRS will
continue this position in the future.
Trust unitholders should be aware of possible state tax implications of
owning trust units. See "State Tax Considerations."
14
FORWARD-LOOKING STATEMENTS
Some statements made by Cross Timbers in this prospectus under "Hypothetical
Annual Cash Distributions," statements pertaining to future development
activities and costs, and other statements contained in this prospectus are
prospective and constitute forward-looking statements. These forward-looking
statements involve known and unknown risks, uncertainties and other factors
that could cause actual results to differ materially from future results
expressed or implied by the forward-looking statements. The most significant
risks, uncertainties and other factors are discussed under "Risk Factors"
above.
USE OF PROCEEDS
The trust will not receive any proceeds from the sale of the trust units.
Cross Timbers will receive all proceeds from the sale of trust units after
deducting underwriting discounts and costs of the offering paid by Cross
Timbers. The estimated net proceeds will be approximately $ , and will
increase to $ if the underwriters exercise their over-allotment option in
full. Cross Timbers 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 based on LIBOR, currently 6.5%, and
matures on June 30, 2003. Cross Timbers incurred its bank debt to finance
recent acquisitions of oil and natural gas producing properties, purchases of
equity securities of other energy companies, repurchases of Cross Timbers
common stock, and development expenditures.
CROSS TIMBERS
Cross Timbers Oil Company is a leading United States independent energy
company. It engages in the acquisition, development and exploration of oil and
natural gas properties, and in the production, processing, marketing and
transportation of oil and natural gas in the United States. Cross Timbers
organized the trust in December 1998 and conveyed the net profits interests to
the trust in exchange for all of the trust units. Cross Timbers continues to
own the underlying properties from which the net profits interests were
conveyed.
Cross Timbers has granted to its executive officers options to purchase up
to $12 million of its retained trust units at the initial public offering
price. The executive officers will not receive any trust distributions until
their options are exercised.
Cross Timbers may form additional royalty trusts with other properties. It
may in the future dispose of some or all of the trust units of the Hugoton
Royalty Trust or any of the other royalty trusts. See "Risk Factors--Cross
Timbers May Dispose of Remaining Trust Units."
THE TRUST
The trust was formed in December 1998 by execution of the trust indenture
between NationsBank, N.A., as trustee, and Cross Timbers. In connection with
the formation of the trust, Cross Timbers carved the net profits interests from
the underlying properties and conveyed the net profits interests to the trust
in exchange for all 40,000,000 of the trust units.
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.
15
The trust will pay the trustee a fee of $35,000 per year and a fee of
$15,000 for services to terminate the trust. The trust will also incur legal,
accounting and engineering fees, printing costs and other expenses that are
deducted from the 80% of net proceeds received by the trust before
distributions are made to trust unitholders.
HYPOTHETICAL ANNUAL CASH DISTRIBUTIONS
The amount of trust revenues and cash distributions to trust unitholders
will depend on (1) natural gas prices, (2) oil prices to a lesser extent, (3)
the volume of oil and natural gas produced and sold and (4) production,
development and other costs. Cross Timbers prepared the following unaudited
tables, which demonstrate the hypothetical effect that changes in the prices
for oil and natural gas could have on trust distributions. The following tables
show:
. the hypothetical cash distributions per trust unit for calendar year
1999 on the accrual or production basis;
. the resulting hypothetical cash distributions per trust unit as a
percentage of the purchase price of the trust unit ("Hypothetical Pre-
Tax Cash Returns"); and
. the resulting hypothetical cash return following payment of all federal
income tax, net of available deductions and credits, at the highest
individual tax rate of 39.6% ("Hypothetical After-Tax Cash Returns").
The tables are based on:
. an assumed purchase price of $9.00 per trust unit;
. various hypothetical oil and natural gas sales prices, which were chosen
solely for illustrative purposes and without reference to any historical
prices;
. 1999 production, as estimated in the Reserve Report; and
. the other assumptions described below under "How the Hypothetical Tables
Were Prepared."
The tables are not a projection or forecast of the actual or estimated
results from an investment in the trust units. The purpose of the tables is to
illustrate the sensitivity of cash distributions and hypothetical cash returns
to changes in the prices of oil and natural gas. There is no assurance that the
assumptions described below will actually occur or that the prices of oil or
natural gas will not decline or increase by amounts different from those shown
in the tables.
Due to the seasonal demand for natural gas, the amount of monthly cash
distributions from the trust is expected to vary during the year. Month-to-
month distributions will also vary based on the timing of development
expenditures and the net proceeds, if any, generated by development projects.
As a result of typical production declines for oil and natural gas
properties, production estimates generally decrease from year to year.
Accordingly, the hypothetical cash distributions for 1999 production do not
indicate the amount of distributions for future years. Because payments to the
trust will be generated by depleting assets, a portion of each distribution may
represent a return of your original investment.
16
Hypothetical Cash Distributions Per Trust Unit
For Estimated 1999 Production
Hypothetical Wellhead
Hypothetical Posted Gas
Oil Price per Bbl Price per Mcf
------------------- --------------------------
$1.50 $2.00 $2.50 $3.00
----- ----- ----- -----
$10.00........................................... $0.57 $0.95 $1.32 $1.70
15.00........................................... 0.61 0.99 1.36 1.74
20.00........................................... 0.65 1.03 1.40 1.78
25.00........................................... 0.69 1.07 1.44 1.82
Hypothetical Pre-Tax Cash Returns at a Trust Unit Price of $9.00
For Estimated 1999 Production
Hypothetical Wellhead
Hypothetical Posted Gas
Oil Price per Bbl Price per Mcf
------------------- --------------------------
$1.50 $2.00 $2.50 $3.00
----- ----- ----- -----
$10.00........................................... 6.3% 10.6% 14.7% 18.9%
15.00........................................... 6.8 11.0 15.1 19.3
20.00........................................... 7.2 11.4 15.6 19.8
25.00........................................... 7.7 11.9 16.0 20.2
Hypothetical After-Tax Cash Returns at a Trust Unit Price of $9.00
For Estimated 1999 Production
Hypothetical Wellhead
Hypothetical Posted Gas
Oil Price per Bbl Price per Mcf
------------------- --------------------------
$1.50 $2.00 $2.50 $3.00
----- ----- ----- -----
$10.00........................................... 7.2% 9.8% 12.3% 14.9%
15.00........................................... 7.6 10.1 12.6 15.1
20.00........................................... 7.8 10.3 12.8 15.3
25.00........................................... 8.1 10.7 13.1 15.7
17
The following table shows the calculation of hypothetical 1999 cash
distributions per trust unit, pre-tax and after-tax cash returns, based on the
assumptions described below under "How the Hypothetical Tables Were Prepared"
and assuming a $10.00 per Bbl posted West Texas Intermediate crude oil price
($11.75 realized), a $2.00 per Mcf wellhead natural gas price and a $9.00 trust
unit purchase price:
Hypothetical 1999 Cash Distributions
(in thousands)
Trust Distributable Income:
Natural gas (41,027 MMcf).................................. $82,054
Oil (434 MBbls)............................................ 5,100
-------
Total revenues........................................... 87,154
-------
Production and property taxes and transportation........... 9,310
Production expenses........................................ 11,937
Development costs.......................................... 12,000
Overhead................................................... 6,200
-------
Total expenses........................................... 39,447
-------
Net Proceeds............................................... 47,707
Net profits percentage..................................... 80%
-------
Trust royalty income....................................... 38,166
Trust administrative expense............................... 300
-------
Trust distributable income................................. $37,866
=======
Annual
Cash
Amount Return
------ ------
Per Trust Unit (40,000,000 Trust Units):
Total cash distributions....................................... $0.95 10.6%
Cost depletion tax deduction................................... (0.73)
-----
Taxable income................................................. 0.22
Income tax rate................................................ 39.6%
-----
Income tax expense............................................. 0.09
Section 29 tax credit.......................................... (0.02)
-----
Net tax........................................................ 0.07
-----
Total cash distributions after tax............................. $0.88 9.8%
=====
How the Hypothetical Tables Were Prepared
Timing of Actual Distributions. In preparing the tables above, the revenues
and expenses of the trust were calculated based on the terms of the conveyances
creating the trust's net profits interests. These calculations are described
under "Computation of Net Proceeds," except that amounts for the tables were
calculated on an accrual or production basis rather than the cash basis
prescribed by the conveyances. As a result, the proceeds for production for the
final one or two months of 1999, and reflected in the tables above, will
actually enter into the calculation of net proceeds to be received by the trust
in 2000. Net proceeds from production during December 1998 will in fact be
distributed from the trust in 1999. Accordingly, the hypothetical cash
distributions attributable to 1999 production represent hypothetical cash
distributions from the trust from February or March 1999 through January or
February 2000.
18
Production Estimates. Production estimates for 1999 are based on the Reserve
Report. The Reserve Report assumed constant prices at December 31, 1998, based
on a West Texas Intermediate crude oil price of $9.50 ($11.24 realized) per Bbl
and the weighted average wellhead natural gas price at December 31, 1998 of
$2.01 per Mcf. Production from the underlying properties for 1999 is estimated
to be 434,000 Bbls of oil and 41,027,000 Mcf of natural gas. See "--Oil and
Natural Gas Prices" below for a description of changes in production due to
price variations. Sales for 1998 were 479,000 Bbls of oil and 38,535,000 Mcf of
natural gas. For purposes of computing the amount of Section 29 tax credit,
natural gas production from the underlying properties that qualify for the
tight sands natural gas credit is estimated to be 2,752,000 Mcf during 1999
(1,376,000 Mcf net to the trust). Differing levels of production will result in
different levels of distributions and cash returns.
Oil and Natural Gas Prices. Oil prices shown in the above tables are
hypothetical posted oil prices. Posted price is the price paid for oil at a
specific point, unadjusted for gravity, quality and transportation and
marketing costs. Published benchmark prices are typically based upon West Texas
Intermediate crude, a light, sweet oil of a particular gravity. These prices
differ from the average or actual price received for production from the
underlying properties, which takes into account those factors. Differentials
between posted oil prices and the prices actually received for the oil
production may vary significantly due to market conditions. In the above
tables, $1.75 per barrel is added to the hypothetical posted oil price to
reflect these adjustments. This addition is based on the average difference
between the posted price of West Texas Intermediate crude and the price
received for production from the underlying properties during 1998. Pro forma
average oil prices appearing in this prospectus have been adjusted for these
differentials.
Natural gas prices shown in the above tables are hypothetical wellhead
prices for natural gas. Wellhead price is the net price received for natural
gas and natural gas liquids after all deductions for transportation, marketing
and gathering. The weighted average price of natural gas production from the
underlying properties during 1998 was $2.00 per Mcf. This was approximately
$0.25 below the average of the monthly closing NYMEX natural gas futures
contract prices for the same period. However, if previously occurring location,
quality and other differentials continue in the future, there may be more
significant differences between the natural gas price received and the NYMEX
price.
The adjustments to posted oil prices and wellhead natural gas prices applied
in the hypothetical distribution and cash return tables are based upon an
analysis by Cross Timbers of the historic price differentials for production
from the underlying properties with consideration given to gravity, quality and
transportation and marketing costs that may affect these differentials in 1999.
There is no assurance that these assumed differentials will recur in 1999.
When oil and natural gas prices decline, the operators of the underlying
properties may elect to reduce or completely suspend production. No adjustments
have been made to estimated 1999 production to reflect potential reductions or
suspensions of production.
Production Expenses, Development Costs and Overhead. For 1999, Cross Timbers
estimates production expenses to be $11.9 million, development costs to be $12
million and overhead to be $6.2 million. Overhead is the estimated fee for all
properties operated by Cross Timbers that is deducted by Cross Timbers in
calculating net proceeds. For a description of production expenses and
development costs, see "Computation of Net Proceeds."
Administrative Expense. Trust administrative expense for 1999 is assumed to
be $300,000 ($0.0075 per trust unit). See "The Trust."
Hypothetical After-Tax Cash Return. Because the net profits interests are a
depleting asset, a portion of this return may be considered a return of your
original investment. The portion that would
19
be considered a return of original investment is not currently determinable.
For a discussion of alternative ways of measuring the depletion of oil and
natural gas assets, see "Risk Factors--Trust Assets Are Depleting Assets."
The Hypothetical After-Tax Cash Returns on annual hypothetical cash
distributions were computed by:
. determining the amount of federal income tax that would be paid on the
cash distributions at the highest individual marginal tax rate for 1999
of 39.6%, taking into account:
-- a cost depletion tax deduction of $0.73 per trust unit; and
-- a Section 29 tax credit of $0.02 per trust unit;
. subtracting this income tax amount from the annual cash distributions;
and
. dividing the result by $9.00 per trust unit.
Cost depletion is calculated by multiplying the assumed trust unit purchase
price of $9.00 by the cost depletion rate of 8.1%. This rate was estimated by
dividing estimated 1999 production by December 31, 1998 proved reserves
estimated in the Reserve Report. Cost depletion is recaptured upon sale of the
trust units, which results in the taxation of any gain on sale as ordinary
income, as opposed to capital gain, up to the amount of cost depletion
previously deducted.
The Section 29 tax credit was based on estimated tight sands natural gas
production of 1,376,000 Mcf for the net profits interests at $0.52 per MMBtu.
The Section 29 tax credit will expire January 1, 2003.
When the hypothetical distributions are less than $0.77 per trust unit, the
Hypothetical After-Tax Cash Return would be the same or greater than the
Hypothetical Pre-Tax Cash Return because of cost depletion and the Section 29
tax credit. In all instances, each trust unitholder is assumed to have a
regular federal income tax liability sufficient to utilize the depletion
deduction and the Section 29 tax credit. Alternative minimum tax implications
have not been considered. The Section 29 tax credit cannot be used to reduce a
trust unitholder's regular tax below his tentative minimum tax, calculated as
provided in the alternative minimum tax computation rules. See "Federal Income
Tax Consequences--Section 29 Tight Sands Natural Gas Tax Credit." The effect
of state income taxes has not been taken into account in computing the
Hypothetical After-Tax Cash Return. See "State Tax Considerations."
THE NET PROFITS INTERESTS AND THE UNDERLYING PROPERTIES
General
Cross Timbers created the net profits interests through three conveyances
to the trust of 80% net profits interests carved from Cross Timbers' interests
in properties in Kansas, Oklahoma and Wyoming. The net profits interests
entitle the trust to receive 80% of the net proceeds from the sale of oil and
natural gas attributable to the underlying properties. Net proceeds equal the
gross proceeds received by Cross Timbers from the sale of production less
property and production taxes, overhead fees and production and development
costs. The small number of interests in underlying properties that are royalty
and overriding royalty interests are not subject to production and development
costs or overhead fees. For a more detailed description of net proceeds, see
"Computation of Net Proceeds."
Cross Timbers owns the underlying properties, subject to the net profits
interests conveyed to the trust. Cross Timbers may, at any time, sell all or
any portion of the underlying properties, subject to the net profits
interests. It has no present intention to do so.
20
Cross Timbers' interests in the underlying properties include its undivided
interests in oil and natural gas leases and the production from existing and
future wells on those leases. Cross Timbers' interests cover the leased acreage
and wells drilled on that acreage. When Cross Timbers drills additional wells
on the leased acreage covered by its interests, or when it deepens or opens new
producing zones in existing wells, any production from those activities is
attributable to the underlying properties. Accordingly, those activities, if
successful, will increase or replace production from the underlying properties
and increase revenues subject to the trust's net profits interest.
Cross Timbers' interest in substantially all of the underlying properties is
referred to in the oil and natural gas industry as a "working interest." A
working interest is an interest of an oil and natural gas lease entitling its
owner to receive a specified percentage of production, but requiring the owner
to bear the cost of exploring for, developing and producing oil and natural gas
from the property.
Where the working interest is held by a number of persons on a single lease,
a working interest owner is designated the lease operator by agreement. Cross
Timbers operates approximately 90% of the underlying properties based on
relative value, and major oil companies and established independent producers
operate the rest. A lease operator controls operations on the lease, including
the timing and amount of discretionary expenditures for operational and
development activities. For that reason it is desirable to operate properties,
and it is important that the operator be qualified and experienced.
21
Pro Forma Distributable Income and Oil and Natural Gas Sales Volumes
The following table provides oil and natural gas sales volumes and average
sales prices for production from the underlying properties and the calculation
of distributable income (1) for the years ended December 31, 1996, 1997 and
1998, based on historical net proceeds from the underlying properties, (2) for
the year ended December 31, 1998, adjusting development costs to $12 million
as is budgeted for 1999, and (3) for the year ended December 31, 1999, on a
hypothetical basis, as described under "Hypothetical Annual Cash
Distributions."
Year Ended December 31,
------------------------- Adjusted Hypothetical
1996 1997 1998 1998(a) 1999(b)
------- ------- ------- -------- ------------
(in thousands, except per unit data)
Underlying Properties
Sales Volumes:
Natural gas (Mcf).......... 36,143 37,172 38,535 38,535 41,027
Oil (Bbls)................. 455 470 479 479 434
Average Price:
Natural gas (per Mcf)...... $ 1.67 $ 2.21 $ 2.00 $ 2.00 $ 2.00
Oil (per Bbl).............. $ 19.95 $ 20.63 $ 14.78 $ 14.78 $ 11.75
Calculation of Distributable
Income
Revenues:
Natural gas sales.......... $60,502 $82,192 $77,124 $77,124 $82,054
Oil sales.................. 9,075 9,704 7,083 7,083 5,100
------- ------- ------- ------- -------
Total.................... 69,577 91,896 84,207 84,207 87,154
------- ------- ------- ------- -------
Costs:
Production and property
taxes and transportation.. 5,919 9,173 9,170 9,170 9,310
Production expenses........ 11,359 12,837 13,031 13,031 11,937
Development costs.......... 14,392 40,027 33,019 12,000 12,000
Overhead................... 4,557 5,354 6,198 6,198 6,200
------- ------- ------- ------- -------
Total.................... 36,227 67,391 61,418 40,399 39,447
------- ------- ------- ------- -------
Net proceeds................. 33,350 24,505 22,789 43,808 47,707
Net profits percentage....... 80% 80% 80% 80% 80%
------- ------- ------- ------- -------
Trust royalty income......... 26,680 19,604 18,231 35,046 38,166
Trust administrative
expense..................... 300 300 300 300 300
------- ------- ------- ------- -------
Trust distributable
income(c)................... $26,380 $19,304 $17,931 $34,746 $37,866
======= ======= ======= ======= =======
Trust distributable income
per trust unit(c)........... $ 0.66 $ 0.48 $ 0.45 $ 0.87 $ 0.95
======= ======= ======= ======= =======
- --------
(a) Based on the statement of revenues and direct operating expenses for the
underlying properties for the year ended December 31, 1998, with the
exception that development costs are assumed to be $12 million, as is
budgeted for 1999.
(b) Based on the assumptions and methods of calculation described under
"Hypothetical Annual Cash Distributions" and using hypothetical prices of
$2.00 for natural gas and $10.00 ($11.75 realized) for oil. The
hypothetical amounts are not a projection or forecast of the actual or
estimated results from an investment in the trust units. They are intended
only to demonstrate distributable income based on assumed prices and
costs.
(c) On a pro forma basis, assuming the net profits interests were conveyed to
the trust prior to January 1, 1996 and that trust administration expenses
were $300,000 annually.
Discussion and Analysis of Pro Forma Distributable Income
Trust royalty income from the net profits interests was $26,680,000 for
1996, $19,604,000 for 1997 and $18,231,000 for 1998. The changes in royalty
income were primarily related to changes in volumes, prices and development
costs. Natural gas sales were 89% of total revenues for the three-year period
ended December 31, 1998. Trust royalty income is recorded when received by the
trust, which is the month following receipt by Cross Timbers, and generally
two months after the related oil and natural gas production.
22
Volumes. Natural gas sales volumes from the underlying properties increased
3% from 1996 to 1997, and 4% from 1997 to 1998. Oil sales volumes from the
underlying properties increased 4% from 1996 to 1997, and 2% from 1997 to 1998.
The increases were primarily attributable to development projects.
Prices. The average natural gas price increased 32% from $1.67 per Mcf in
1996 to $2.21 in 1997, and decreased 10% from 1997 to $2.00 in 1998. The 1996
prices were at the beginning of an upturn in natural gas prices that lasted
through the summer of 1998. The average oil price increased 3% from $19.95 per
Bbl in 1996 to $20.63 in 1997, and decreased 28% from 1997 to $14.78 in 1998.
The lower 1998 oil prices were caused by increased global production without a
corresponding increase in consumption.
Costs. Total costs deducted in the calculation of royalty income increased
86% from $36,227,000 in 1996 to $67,391,000 in 1997, followed by a 9% decrease
to $61,418,000 in 1998. The primary reason for the fluctuation among the three
years was the timing of development projects. Many of the underlying properties
were purchased by Cross Timbers in 1995 and 1996, leading to large development
expenditures in 1997 and 1998. Development costs rose 178% from $14,392,000 in
1996 to $40,027,000 in 1997, and decreased 18% to $33,019,000 in 1998 as
development projects were completed. Cross Timbers expects development costs to
be $12,000,000 per year for the next four years.
Production expense rose 13% from $11,359,000 in 1996 to $12,837,000 in 1997,
and increased 2% to $13,031,000 from 1997 to 1998. Most of the increase was
related to the timing of major remedial projects such as workovers and
subsurface maintenance and to increases in production volumes. On a per Mcfe
basis, production costs declined from $0.32 in 1997 to $0.31 in 1998.
Production and property taxes and transportation costs have generally
fluctuated in relation to revenue levels.
Overhead expenses charged to the underlying properties by Cross Timbers were
$4,557,000 for 1996, $5,354,000 for 1997 and $6,198,000 for 1998. Fluctuations
resulted from changes in the number of active operated wells and the increase
in overhead rates per well.
Producing Acreage and Well Counts
For the following data, "gross" refers to the total wells or acres in which
Cross Timbers owns a working interest and "net" refers to gross wells or acres
multiplied by the percentage working interest owned by Cross Timbers. Although
many of Cross Timbers' wells produce both oil and natural gas, a well is
categorized as an oil well or a natural gas well based upon the ratio of oil to
natural gas production.
The underlying properties are interests in developed properties located
primarily in natural gas producing regions of Kansas, Oklahoma and Wyoming. The
following is a summary of the approximate producing acreage of the underlying
properties at December 31, 1998. Undeveloped acreage is not significant.
Gross Net
------- -------
Hugoton Area.................................................... 217,590 200,390
Anadarko Basin.................................................. 152,042 113,946
Green River Basin............................................... 42,654 28,841
------- -------
Total........................................................... 412,286 343,177
======= =======
23
The following is a summary of the producing wells on the underlying
properties as of December 31, 1998:
Operated Non-Operated
Wells Wells Total
------------- ------------- -------------
Gross Net Gross Net Gross Net
----- ------- ------------- ----- -------
Natural gas........................... 1,005 913.5 253 59.8 1,258 973.3
Oil................................... 140 124.1 7 1.5 147 125.6
----- ------- ----- ------ ----- -------
Total................................. 1,145 1,037.6 260 61.3 1,405 1,098.9
===== ======= ===== ====== ===== =======
The following is a summary of the number of development wells drilled by
Cross Timbers on the underlying properties during the years indicated:
Year Ended December 31
--------------------------------
1996 1997 1998
---------- ---------- ----------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
Completed:
Natural gas wells (a)......................... 39 30.9 79 68.8 64 43.7
Oil wells..................................... 2 2.0 1 1.0 -- --
Non-productive................................. -- -- 2 1.5 1 1.0
--- ---- --- ---- --- ----
Total (b)...................................... 41 32.9 82 71.3 65 44.7
=== ==== === ==== === ====
- --------
(a) One gross (0.5 net) natural gas well drilled in 1997 was an exploratory
well.
(b) Included in totals are 9 gross (3.2 net) in 1996, 8 gross (1.5 net) in 1997
and 25 gross (8.8 net) in 1998 wells drilled on non-operated interests.
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:
Year Ended December 31
-----------------------
1996 1997 1998
------- ------- -------
Sales prices:
Natural gas (per Mcf)................................ $ 1.67 $ 2.21 $ 2.00
Oil (per Bbl)........................................ 19.95 20.63 14.78
Production costs per Mcfe............................. 0.29 0.32 0.31
Production and property taxes and transportation costs
per Mcfe............................................. 0.15 0.23 0.22
Major Producing Areas
Hugoton Area
Natural gas was discovered in 1922 in the Hugoton area, the largest natural
gas producing area in North America, covering parts of Texas, Oklahoma and
Kansas with an estimated five million productive acres. The Permian-aged Chase
formation is the major productive formation in the Hugoton area, ranging in
depth from 2,700 to 2,900 feet. There are more than 7,200 Chase wells currently
producing. More than 64 trillion cubic feet of natural gas have been produced
from the Hugoton area.
24
Additional productive formations in the Hugoton area include the Council
Grove between 2,950 and 3,400 feet, the Chester between 6,350 and 6,700 feet
and the Morrow between 6,000 and 6,300 feet. Cross Timbers is actively
exploring and developing these additional formations on the underlying
properties.
Cross Timbers' projected 1999 net production from the underlying properties
in the Hugoton area averages approximately 36,700 Mcf of natural gas per day
and 40 Bbls of oil per day.
Cross Timbers delivers approximately 70% of its Hugoton natural gas
production to a gathering and processing system operated by a subsidiary. This
system collects 71% of its throughput from underlying properties, which, in
recent months, has been approximately 26,000 Mcf per day net to Cross Timbers'
interest from 243 wells. The subsidiary purchases the natural gas from Cross
Timbers at the wellhead, gathers and transports the natural gas to its plant,
treats and processes the natural gas at the plant, and then transports it to
the marketing pipelines. Cross Timbers sells the natural gas to the subsidiary
under long-term contracts at a price equal to 80% to 85% of the price received
by the subsidiary for the natural gas. The price is adjusted based upon the Btu
content of the natural gas. The subsidiary sells the natural gas to a marketing
affiliate of Cross Timbers based upon the average price of several published
indices, but does not pay a marketing fee. The price paid by the marketing
affiliate includes a deduction for any pipeline access fees incurred by the
marketing subsidiary. Pipeline access fees currently are approximately $0.02
per Mcf.
Other Hugoton natural gas production is delivered under a third party
contract. Under the contract, Cross Timbers receives 74.5% of the net proceeds
received from the sale of the residue natural gas and liquids.
In the Hugoton area, Cross Timbers' development plans include:
. additional compression to lower line pressures;
. pumping unit installations;
. opening new producing zones of existing wells;
. drilling additional wells; and
. deeper drilling of existing wells to new producing zones.
Cross Timbers plans to develop the Chase formation primarily through infill
drilling of up to 40 wells in Kansas. If new legislation is enacted in Oklahoma
allowing for reduced spacing and Cross Timbers receives regulatory approval, it
will have approximately 200 potential infill well locations in Oklahoma. Cross
Timbers also plans to develop the other formations, including the Council
Grove, Chester, Morrow and St Louis formations that underlie the 79,500 net
acres held by production by the Chase formation wells. Cross Timbers has
participated in 3-D seismic shoots covering 30,000 acres of Cross Timbers' net
acreage position beneath the Chase formation.
Cross Timbers drilled 12 gross (10.9 net) wells in 1997, and 17 gross (10.5
net) wells in 1998, to the Chester, Council Grove and Chase formations, all of
which were successfully completed.
Anadarko Basin
Cross Timbers' projected average 1999 daily production from the underlying
properties in the Anadarko Basin is 45,000 Mcf of natural gas and 1,100 Bbls of
oil. Two of the principal areas within this basin are the Major County area and
the Elk City Field.
25
Major County Area. Cross Timbers is one of the largest producers in the
Ringwood, Northwest Okeene and Cheyenne Valley fields in Major County,
Oklahoma. Projected average 1999 net daily natural gas production from the
underlying properties is approximately 33,800 Mcf and oil production is
approximately 920 Bbls.
Oil and natural gas were first discovered in the Major County area in 1945.
The fields in the Major County area are characterized by oil and natural gas
production from a variety of structural and stratigraphic traps. Productive
zones range from 6,500 to 9,400 feet and include the Oswego, Red Fork, Chester,
Manning, Mississippian, Hunton and Arbuckle formations.
A gathering subsidiary of the Company operates a 300-mile gathering system
and pipeline in the Major County area. The gathering subsidiary and a third-
party processor purchase natural gas produced at the wellhead from Cross
Timbers and other producers in the area under life of production contracts. The
gathering subsidiary gathers and transports the natural gas to a third-party
processor, which processes the natural gas and pays Cross Timbers and other
producers for at least 50% of the liquids processed. After the natural gas is
processed, the gathering subsidiary transports the natural gas via a 26-mile
pipeline to a connection with other pipelines. The gathering subsidiary sells
the residue natural gas to the marketing subsidiary of Cross Timbers based upon
the average price of several published indices. The gathering subsidiary pays
this price to Cross Timbers less a gathering fee of $.313 per Mcf of residue
natural gas. This gathering fee was previously approved by the Federal Energy
Regulatory Commission when the gathering subsidiary was regulated. In recent
months, the gathering system has been collecting approximately 25,500 Mcf per
day from over 400 wells, 70% of which Cross Timbers operates. Estimated
capacity of the gathering system is 40,000 Mcf per day. The gathering
subsidiary also provides contract operating services to properties in Woodward
County, collecting approximately 80,000 Mcf per month from 25 wells, for a
historical average fee of approximately $.125 per Mcf.
Cross Timbers also sells natural gas to its marketing subsidiary, which then
sells the natural gas to third parties. The price paid to Cross Timbers is
based upon the average price of several published indices, but does not include
a deduction for any marketing fees. The price paid by the marketing affiliate
includes a deduction for any transportation fees charged by the third party.
Cross Timbers plans to develop the Major County area primarily through:
. mechanical treatments to stimulate production rates;
. opening new producing zones in existing wells;
. deepening existing wells to new producing zones; and
. drilling additional wells.
Cross Timbers drilled 25 gross (20.3 net) wells in 1997, and 23 gross (16.3
net) wells in 1998, in the western portion of Major County, targeted at the
Mississippian and Chester formations. All of these wells were successfully
completed.
Elk City Field. The Elk City Field is located in Beckham and Washita
counties of Western Oklahoma. Projected average 1999 net production of
underlying properties in the Elk City Field is approximately 4,200 Mcf of
natural gas and 130 Bbls of oil per day.
The Elk City Field was discovered in 1947 and has been extensively
developed. Production is from the Hoxbar (9,500 feet), Atoka (13,100 feet) and
Morrow (15,500 feet) zones. Cross Timbers has increased production primarily by
adding mechanical treatments to stimulate production rates and opening new
producing zones in existing wells. Opportunities remain for additional
development in the field. Cross Timbers added significant additional reserves
through recent recompletions to the Atoka Formation.
26
A third party processes natural gas from the Elk City Field and pays Cross
Timbers 80% of the proceeds received from the sale of the liquids. Cross
Timbers sells the residue natural gas to its marketing subsidiary, which pays
Cross Timbers the average price of several published indices.
Green River Basin
The Green River Basin is located in southwestern Wyoming. Cross Timbers'
projected 1999 average net daily production from the underlying properties in
the Fontenelle field is approximately 30,500 Mcf of natural gas and 50 Bbls of
oil. Natural gas was discovered in the Fontenelle area in the early 1970s. The
producing reservoirs are the Cretaceous-aged Frontier and Dakota sandstones at
depths ranging from 7,500 to 10,000 feet.
Cross Timbers markets the natural gas produced from the Fontenelle Unit and
nearby properties, under three different marketing arrangements. Under the
agreement covering 70% of the natural gas sold, Cross Timbers compresses the
natural gas on the lease, transports it off the lease and compresses the
natural gas again prior to entry into the natural gas plant pipeline. The
pipeline transports the natural gas 35 miles to the natural gas plant, where
the natural gas is processed, then redelivered to Cross Timbers and sold to
Cross Timbers' marketing subsidiary. The owner of the natural gas plant and
related pipeline charges Cross Timbers for operational fuel and processing. In
1998 the fuel charge was about 4% per MMBtu delivered and the processing fee
was $0.0792 per MMBtu. In 1999 Cross Timbers anticipates the fuel charge to be
2.5% to 3% and the processing fee to be $0.05 per MMBtu. The marketing
subsidiary then sells the residue natural gas based upon a spot sales price,
and pays Cross Timbers the net proceeds that the marketing subsidiary receives.
The marketing subsidiary does not receive a marketing fee. Condensate is sold
at the lease to an independent third party at market rates. The natural gas not
sold under the above arrangement is sold either under a similar arrangement
where the fee is $.145 per MMBtu, or under a contract where Cross Timbers
directly sells the natural gas to a third party on the lease at an adjusted
index price.
Cross Timbers drilled 35 gross (34 net) wells in 1997 and 16 gross (16 net)
wells in 1998 in the Fontenelle Unit, all of which were successfully completed.
During 1997, Cross Timbers installed additional pipeline compression to lower
overall field operating pressures and improve overall field performance. Cross
Timbers also completed an interconnect to another pipeline in the southeastern
part of the Fontenelle field that added an additional market for natural gas.
Potential development activities for the fields in this area include:
. additional compression to lower line pressures;
. opening new producing zones of existing wells;
. deepening existing wells to new producing zones; and
. drilling additional wells.
Oil and Natural Gas Reserves
Miller & Lents estimated oil and natural gas reserves attributable to the
net profits interests as of December 31, 1998. Numerous uncertainties are
inherent in estimating reserve volumes and values, and the estimates are
subject to change as additional information becomes available. The reserves
actually recovered and the timing of production of the reserves may vary
significantly from the original estimates.
Miller & Lents calculated reserve quantities and revenues for the net
profits interests from projections of reserves and revenues attributable to the
combined interests of the trust and Cross Timbers in the underlying properties.
Because the trust owns net profits interests and not a specific
27
ownership percentage of the oil and natural gas reserve quantities, proved
reserves for the trust's net profits interests are calculated by subtracting
from 80% of proved reserves of the underlying properties, reserve quantities of
a sufficient value to pay 80% of the future estimated production and
development costs, excluding overhead. Accordingly, proved reserves for the net
profits interests reflect quantities that are calculated after reductions for
future costs and expenses based on the price and cost assumptions used in the
reserve estimates.
The standardized measure of discounted future net cash flows and changes in
discounted cash flows presented below were prepared using assumptions required
by the Financial Accounting Standards Board. These assumptions include the use
of year-end prices for oil and natural 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 accurate basis for estimating future revenues or reserve data. Future
net cash flows are discounted at an annual rate of 10%. There is no provision
for federal income taxes because future net revenues are not subject to
taxation at the trust level.
Oil prices used to determine the standardized measure at December 31, 1998
were based on West Texas Intermediate crude prices of $9.50 ($11.24 realized)
per Bbl. The weighted average December 31, 1998 wellhead natural gas price used
to determine the standardized measure was $2.01 per Mcf.
Proved Reserves
The following table shows proved reserves, proved developed reserves, future
net revenues and discounted present value of future net revenues at December
31, 1998 for the underlying properties, 80% of the underlying properties and
the net profits interests.
80% of Net
Underlying Underlying Profits
Properties Properties Interests
---------- ---------- ---------
(in thousands)
Proved reserves
Natural gas (Mcf)............................ 515,073 412,058 282,297
Oil (Bbls)................................... 4,030 3,224 2,193
Natural gas Equivalents (Mcfe)............... 539,253 431,402 295,455
Proved developed reserves
Natural gas (Mcf)............................ 435,328 348,262 249,215
Oil (Bbls)................................... 3,368 2,694 1,934
Natural gas Equivalents (Mcfe)............... 455,536 364,429 260,819
Future net revenues............................ $674,518 $539,615 $539,615
Present value discounted at 10% per annum...... $347,177 $277,742 $277,742
The following table summarizes the changes in estimated pro forma proved
reserves attributable to the net profits interests and the changes in estimated
proved reserves of the underlying properties for the periods indicated. The
data is presented assuming the underlying properties were acquired and the net
profits interests were created prior to December 31, 1995 and the trust was
formed at that date. Reserve estimates for underlying properties that Cross
Timbers acquired between 1996 and 1998 are not available prior to the date
acquired. For purposes of calculating quantities of estimated proved reserves
of these properties as of December 31, 1995, 1996 and 1997, proved
28
reserves are assumed to equal reserves at the acquisition date plus production
between December 31, 1995, 1996 or 1997 and the acquisition date.
Net Profits Interests
Underlying Properties (Pro Forma)
---------------------------- ----------------------------
Gas Gas
Gas Oil Equivalents Gas Oil Equivalents
(Mcf) (Bbls) (Mcfe) (Mcf) (Bbls) (Mcfe)
------- ------ ----------- ------- ------ -----------
(in thousands)
Balance, December 31,
1995................... 445,836 4,442 472,488 251,306 2,481 266,192
Revisions, extensions,
discoveries and
additions............ 47,432 577 50,894 53,978 608 57,626
Production............ (36,143) (455) (38,873) (15,148) (191) (16,294)
------- ----- ------- ------- ----- -------
Balance, December 31,
1996................... 457,125 4,564 484,509 290,136 2,898 307,524
Revisions, extensions,
discoveries and
additions............ 68,837 180 69,917 (2,303) (356) (4,439)
Production............ (37,172) (470) (39,992) (8,809) (111) (9,475)
------- ----- ------- ------- ----- -------
Balance, December 31,
1997................... 488,790 4,274 514,434 279,024 2,431 293,610
Revisions, extensions,
discoveries and
additions............ 64,818 235 66,228 12,636 (122) 11,904
Production............ (38,535) (479) (41,409) (9,363) (116) (10,059)
------- ----- ------- ------- ----- -------
Balance, December 31,
1998................... 515,073 4,030 539,253 282,297 2,193 295,455
======= ===== ======= ======= ===== =======
Proved Developed Reserves
Balance, December 31,
1995................... 384,588 3,633 406,386 222,155 2,096 234,731
Balance, December 31,
1996................... 401,784 3,966 425,580 259,281 2,564 274,665
Balance, December 31,
1997................... 417,912 3,574 439,356 249,148 2,136 261,964
Balance, December 31,
1998................... 435,328 3,368 455,536 249,215 1,934 260,819
Cross Timbers expects to spend $12 million per year for the next four years
to develop the underlying properties and expects that development activities
will moderate the rate of decline of proved reserves.
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
The following table provides the summary calculation of the standardized
measure of discounted future net cash flows of the underlying properties and
net profits interests as of December 31, 1998:
Net
Underlying Profits
Properties Interests
---------- ---------
(in thousands)
Future cash flows.......................................... $1,087,660 $595,301
Future costs:
Production............................................... 364,930 55,686
Development.............................................. 48,212 --
---------- --------
Future net cash flows...................................... 674,518 539,615
10% discount factor........................................ 327,341 261,873
---------- --------
Standardized measure....................................... $ 347,177 $277,742
========== ========
29
Regulation
Natural Gas Regulation. The availability, terms and cost of transportation
significantly affect sales of natural gas. The interstate transportation and
sale for resale of natural gas is subject to federal regulation, including
transportation rates, storage tariffs and various other matters, primarily by
the Federal Energy Regulatory Commission ("FERC"). Federal and state
regulations govern the price and terms for access to natural gas pipeline
transportation. The FERC's regulations for interstate natural gas transmission
in some circumstances may also affect the intrastate transportation of natural
gas.
While natural gas prices are currently unregulated, Congress historically
has been active in the area of natural gas regulation. Cross Timbers cannot
predict whether new legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the various state
legislatures, and what effect, if any, the proposals might have on the
operations of the underlying properties.
Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at market prices. The FERC implemented regulations on
January 1, 1995, to establish an indexing system for transportation rates for
oil that could increase the cost of transporting oil to the purchaser. Cross
Timbers is not able to predict what effect, if any, these regulations might
have.
Environmental Regulation. Companies that are engaged in the oil and gas
industry are affected by federal, state and local laws regulating the discharge
of materials into the environment. Those laws may impact operations of the
underlying properties. Cross Timbers believes that it is in substantial
compliance with the environmental laws and regulations that apply to the
operations of the underlying properties. Cross Timbers has not previously
incurred material expenses in complying with environmental laws and regulations
that affect its operations of the underlying properties. It does not currently
expect that future compliance will have a material adverse effect on the trust
or the monthly distributions.
State Regulation. The various states 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. States may regulate
rates of production and may establish maximum daily production allowables from
both oil and gas wells based on market demand or resource conservation, or
both.
Other Regulation. The Mineral Management Service of the United States
Department of Interior is evaluating existing methods of settling royalties on
federal and Native American oil and gas leases. A portion of the underlying
properties, primarily those located in Wyoming, involve federal leases.
Although the final rules could cause an increase in the federal royalties to be
paid on these properties and, correspondingly, decrease the revenue to Cross
Timbers and the trust from these properties, Cross Timbers does not believe
that the proposed rule changes will have a significant detrimental effect on
the distributions from the trust.
The petroleum industry is also subject to compliance with various other
federal, state and local regulations and laws. Some of those laws relate to
occupational safety, resource conservation and equal employment opportunity.
Cross Timbers does not believe that compliance with these laws will have a
material adverse effect upon the trust unitholders.
30
Title to Properties
Cross Timbers believes that its title to the underlying properties is, and
the trust's title to the net profits interest will be, good and defensible in
accordance with standards generally accepted in the oil and gas industry.
The underlying properties are typically subject, in one degree or another,
to one or more of the following:
. royalties, overriding royalties and other burdens, under oil and gas
leases;
. contractual obligations (including, in some cases, development
obligations) arising under operating agreements, farmout agreements,
production sales contracts and other agreements that may affect the
properties or their titles;
. liens that arise in the normal course of operations, such as those for
unpaid taxes, statutory liens securing unpaid suppliers and contractors
and contractual liens under operating agreements;
. pooling, unitization and commutation agreements, declarations and
orders; and
. easements, restrictions, rights-of-way and other matters that commonly
affect property.
To the extent that these burdens and obligations affect Cross Timbers'
rights to production and the value of production from the underlying
properties, they have been taken into account in calculating the trust's
interests and in estimating the size and the value of the reserves attributable
to the net profits interests. Cross Timbers believes that the burdens and
obligations affecting the underlying properties and the net profits interests
are conventional in the industry for similar properties. Cross Timbers also
believes that the burdens and obligations do not in the aggregate materially
interfere with the use of the underlying properties and will not materially
adversely affect the value of the net profits interests.
Although the matter is not entirely free from doubt, Cross Timbers believes
that the net profits interests should constitute real property interests under
Oklahoma and Wyoming law, but not under Kansas law. Cross Timbers will record
the conveyances in the appropriate real property records of Kansas, Oklahoma
and Wyoming, the states in which the underlying properties are located. If
during the term of the trust Cross Timbers should become a debtor in a
bankruptcy proceeding, it is not entirely clear that the net profits interests
would be treated as real property interests under the laws of Oklahoma and
Wyoming, and they would not be so treated under Kansas law. If a determination
were made in a bankruptcy proceeding 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
would not be required to perform its obligations under the net profits interest
and the trust would seek damages as one of Cross Timbers' unsecured creditors.
Although no assurance can be given, Cross Timbers does not believe that the net
profits interests should be subject to rejection in a bankruptcy proceeding as
executory contracts.
Marketing
A subsidiary of Cross Timbers markets Cross Timbers' natural gas production
and the natural gas output of the gathering and processing systems operated by
other Cross Timbers subsidiaries. The natural gas is sold on a monthly basis to
third parties for the best available price, although Cross Timbers occasionally
enters into forward contracts for future deliveries. Oil production is
generally marketed at the
31
wellhead to third parties at the best available price. The marketing subsidiary
may arrange to accumulate oil from a number of different locations and
transport it to a central point where the greater volume will provide a higher
price, net of the transportation costs. Cross Timbers arranges for some of its
natural gas to be processed by unaffiliated third parties and markets the
natural gas liquids from that processing in a similar manner as it markets its
oil. The natural gas attributable to the underlying properties will be marketed
under the existing sales contracts. Contracts covering production from the
Major County area are for the life of the lease, and the contract for the
majority of production from the Hugoton area expires in 2004. If new contracts
are entered into with unaffiliated third parties, the proceeds from sales under
those new contracts will be included in gross proceeds from the underlying
properties. If new contracts are entered into with the marketing subsidiary, it
may charge Cross Timbers a fee that may not exceed 2% of the sales price of the
oil and natural gas received from unaffiliated third parties. The sales price
is net of any deductions for transportation from the wellhead to the
unaffiliated third parties and any gravity or quality adjustments.
Year 2000
"Year 2000," or the ability of computer systems to process dates with years
beyond 1999, affects almost all companies and organizations. Computer systems
that are not Year 2000 compliant by January 1, 2000 may cause material adverse
effects to companies and organizations that rely upon those systems. The
trust's timely receipt of royalty income and disbursement of distributable
income to trust unitholders will largely depend upon performance of computer
systems of Cross Timbers, the trust's transfer agent and other third parties.
These third parties include oil and natural gas purchasers and significant
service providers such as natural gas plant and gathering system operators.
Because the trust will not use the trustee's computer systems to any
significant degree, the trustee's Year 2000 compliance should not significantly
affect the trust.
Cross Timbers is in the process of reviewing its computer systems and
computer-controlled field equipment and making the necessary modifications for
Year 2000 compliance. Cross Timbers has completed most of the modifications of
its primary accounting and land computer programs and is currently testing
these modifications. Some of Cross Timbers' critical field equipment, such as
natural gas compressors, are partially controlled or regulated by embedded
computer chips. Cross Timbers is in the process of reviewing this equipment.
Remediation and testing of all Cross Timbers' computer systems and equipment is
expected to be completed by June 1999. Based on its review, remediation efforts
and the results of testing to date, Cross Timbers does not believe that timely
modification of its computer systems for Year 2000 compliance represents a
material risk to the trust. Cross Timbers' costs related to Year 2000
compliance efforts to date have not been material, and it expects that future
costs will not be material. The trust will not incur any of Cross Timbers' Year
2000 costs.
Cross Timbers has identified significant third parties whose Year 2000
compliance could affect Cross Timbers, and is in the process of formally
inquiring about their Year 2000 status. Despite its efforts to assure that such
third parties are Year 2000 compliant, Cross Timbers cannot provide assurance
that all significant third parties will achieve compliance in a timely manner.
A third party's failure to achieve Year 2000 compliance could have a material
adverse effect on Cross Timbers' operations and cash flow, and therefore have a
material adverse impact on timely trust distributions to trust unitholders. For
example a third party might fail to deliver revenue related to the trust's net
profits interest to Cross Timbers, or Cross Timbers might fail to deliver the
income of the net profits interest to the trust. In these situations, the
trustee would be unable to make distributions of those amounts to trust
unitholders on a timely basis.The potential effect of Year 2000 non-compliance
by third parties is currently unknown.
Cross Timbers is currently developing contingency plans in the event of
potential problems resulting from failure of Cross Timbers' or significant
third parties' computer systems on January 1,
32
2000. No contingency plans have been completed to date. Cross Timbers expects
these contingency plans to be completed by September 1999.
Litigation
Cross Timbers is a defendant in two lawsuits that could, if adversely
determined, decrease the net proceeds from certain of the underlying
properties.
A class action lawsuit, Booth, et al. v. Cross Timbers Oil Company, was
filed on April 3, 1998 in the District Court of Dewey County, Oklahoma by
royalty owners of natural gas wells in Oklahoma. The plaintiffs allege that
since 1991 Cross Timbers has underpaid royalty owners as a result of
(1) reducing royalties for improper charges for production, marketing,
gathering, processing and transportation costs and (2) selling natural gas
through affiliated companies at prices less favorable than those paid by third
parties. Cross Timbers believes that it has strong defenses to this lawsuit and
intends to vigorously defend its position. However, if a judgment or settlement
increased the amount of future royalty payments, the trust would bear its
proportionate share of the increased royalties through reduced net proceeds.
The amount of any reduction in net proceeds is not presently determinable, but
is not expected to be material.
A second lawsuit, United States of America ex rel. Grynberg v. Cross Timbers
Oil Company, et al., was filed in the United States District Court for the
Western District of Oklahoma. This action alleges that in computing royalties
payable for natural gas produced from federal leases and lands owned by Native
Americans, Cross Timbers has mismeasured the volume of natural gas and
wrongfully analyzed its heating content. The suit, which was brought under the
qui tam provisions of the U.S. False Claims Act, seeks treble damages for the
unpaid royalties, with interest, civil penalties and an order for Cross Timbers
to cease the allegedly improper measuring practices. This lawsuit is one of
more than 75 suits filed nationwide by the same plaintiff alleging similar
claims against over 300 producers and pipeline companies. Royalties paid by
Cross Timbers for production from underlying properties on federal and Native
American lands during 1998 totalled approximately $2.8 million. Cross Timbers
believes that the allegations of this lawsuit are without merit. However, an
order to change measuring practices or a related settlement could adversely
affect the trust by reducing net proceeds in the future by an indeterminable
amount.
Damages relating to production prior to the formation of the trust will be
borne by Cross Timbers.
COMPUTATION OF NET PROCEEDS
The provisions governing the computation of the net proceeds are detailed
and extensive. The following description of the net profits interests and the
computation of net proceeds is subject to and qualified by the more detailed
provisions of the conveyances of the net profits interests that are filed as
exhibits to the registration statement. See "Available Information."
Net Profits Interests
The net profits interests are defined net profits interests carved from the
underlying properties. Each net profits interest entitles the trust to receive
80% of the net proceeds from the sale of oil and natural gas produced from the
underlying properties.
The amounts paid to the trust for the net profits interests are based on the
definitions of "gross proceeds" and "net proceeds" set forth in the conveyances
and described below. Under the conveyances, net proceeds are computed monthly
(a "Computation Period"). Cross Timbers pays 80% of the aggregate net proceeds
attributable to a Computation Period to the trust on or before the
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last business day of the month following the Computation Period. Cross Timbers
will not pay to the trust interest on the net proceeds held by Cross Timbers
prior to payment to the trust. The trustee makes distributions to trust
unitholders monthly. See "Description of the Trust Units--Distributions and
Income Computations."
Net proceeds equal the excess of gross proceeds over production costs and
excess production costs attributable to a prior Computation Period. For
royalty and overriding royalty interests, production costs are zero.
Gross proceeds means the amounts received by Cross Timbers from sales of
oil and natural gas produced from the underlying properties, after deducting:
. all general property (ad valorem), production, severance, sales,
gathering, excise and other taxes and gathering costs if they are
deducted or excluded from the proceeds of sales; 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 (1) consideration for the transfer or sale
of any underlying property by Cross Timbers or any subsequent owner to any new
owner or (2) any amount for oil and natural gas lost in production or
marketing or used by the owner of the underlying properties in drilling,
production and plant operations. Gross proceeds includes payments for future
production if they are not subject to repayment in the event of insufficient
subsequent production.
Production costs means, on a cash basis, generally 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 to the extent not
deducted 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;
. 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.
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As is customary in the oil and natural gas industry, Cross Timbers charges
an overhead fee to operate the underlying properties. The operating activities
include various engineering, accounting and administrative functions. The fee
is based on a monthly charge per active operated well, and it totalled $6.2
million in 1998 for all underlying properties operated by Cross Timbers. 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 three separate
conveyances, one for each of Kansas, Oklahoma and Wyoming, the three states in
which the underlying properties are located. Net proceeds are calculated
separately for the underlying properties covered by each conveyance, so excess
production costs in one state do not reduce net proceeds from the others.
Cash distributions generally will include one month's net proceeds less
related trustee expenses and administrative charges. However, the first
distribution, which will be made in April 1999 to record holders as of March
31, 1999, will include net proceeds received, less trustee's expenses, during
the period December 1, 1998 through February 28, 1999. This initial
distribution will also be adjusted to exclude any development charges on the
underlying properties incurred through December 31, 1998, which Cross Timbers
will bear.
Additional Provisions
If a controversy arises as to the sales price of any oil or natural gas,
then for purposes of determining gross proceeds:
. amounts withheld or placed in escrow by a purchaser are not considered
to be received by the owner of the underlying property until actually
collected;
. amounts received by the owner of the underlying property and promptly
deposited with a nonaffiliated escrow agent will not be considered to
have been received until disbursed to it by the escrow agent; and
. 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 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 to assign 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. The conveyances
35
have been recorded in the appropriate real property records to give notice of
the net profits interests to Cross Timbers' creditors and transferees.
Upon notice from Cross Timbers, the trust is required to sell for cash net
profits interests that relate to underlying properties which Cross Timbers is
selling to an unaffiliated party. These types of sales may not exceed in any
calendar year 1% of the discounted present value of estimated future net
revenues for the proved reserves of the underlying properties allocated to the
trust's net profits interests, as set forth in the most recent reserve report.
The trust will receive 80% of the net proceeds from a sale.
As an operator of an underlying property, Cross Timbers may enter into
farmout, operating, participation, joint venture and other similar agreements
covering the property if Cross Timbers believes it to be advantageous to the
working interests owners of the property. The net profits interest held by the
trust would then be calculated on the interest retained by Cross Timbers under
the agreement and not on Cross Timbers' original interest before modification
by the agreement. Cross Timbers may enter into any of these agreements without
the consent or approval of the trustee or any trust unitholder. However, Cross
Timbers' interest in entering into any of these types of agreements should be
parallel with that of trust unitholders because of Cross Timbers' retained 20%
net profits interest in the underlying properties.
Cross Timbers 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 must maintain books and records sufficient to determine the
amounts payable for the net profits interests. Quarterly and annually, Cross
Timbers must deliver to the trustee a statement of the computation of the net
proceeds for each Computation Period. Cross Timbers will cause the annual
computation of net proceeds to be audited. The audit cost will be borne by the
trust.
FEDERAL INCOME TAX CONSEQUENCES
This section summarizes 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 dealing with the tax consequences of ownership of trust
units but will rely on the opinion of Butler & Binion, L.L.P. ("Tax Counsel")
regarding the classification of the trust and certain federal income tax
consequences described below, which will be confirmed at the time of the
closing. Tax Counsel 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 the opinion.
Summary of Legal Opinions
Tax Counsel is of the opinion that, for federal income tax purposes,
. the trust will be treated as a grantor trust and not a business entity
taxable as a partnership or a corporation,
36
. the income from the net profits interests will be royalty income subject
to an allowance for depletion, and
. subject to the limitations described below, a trust unitholder will be
allowed a Section 29 tax credit with respect to his share of qualifying
natural gas production from tight sands attributable to the net profits
interests.
Tax Counsel advises that, unless noted otherwise, legal conclusions stated in
this section constitute the opinion of Tax Counsel.
No ruling is being requested from the IRS with respect to the trust or trust
unitholders. Therefore, the IRS could challenge the opinions and statements set
forth herein (which do not bind the IRS or the courts), and the IRS could win
in court if it did challenge these matters.
Classification and Taxation of the Trust
In the opinion of Tax Counsel, under current law, the trust will be taxable
as a grantor trust and not as a business entity. As a grantor trust, the trust
will not be subject to tax at the trust level. For tax purposes, the grantors,
who in this case are the trust unitholders, will be considered to own the
trust's income and principal as though no trust were in existence. A grantor
trust simply files an information return, reporting all items of income, credit
or deductions 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 Tax Counsel, the trust was determined to be an unincorporated
business entity, it would be taxable as a partnership unless it elected to be
taxed as a corporation. The principal tax consequence of the trust's being
treated as a partnership for tax purposes would be that all trust unitholders
would report their share of income from the trust on the accrual method of
accounting regardless of their own method of accounting.
Direct Taxation of Trust Unitholders
Since the trust will be treated as a grantor trust for federal income tax
purposes, each trust unitholder will be taxed directly on his share of trust
income and will be entitled to claim his share of trust deductions. Each trust
unitholder will recognize taxable income when the trust receives or accrues it,
even if it is not distributed until later. Trust unitholders will report their
trust income and expenses consistent with their method of accounting and their
tax year.
Reporting of Trust Income and Expenses
The trustee intends to treat each royalty payment it receives as the taxable
income of the trust unitholders who own trust units on the day of receipt
(i.e., the last business day of each calendar month). Similarly, the trustee
intends to pay expenses only on the day it receives a royalty payment and to
treat all expenses paid on a royalty receipt day as the expenses of the trust
unitholder to whom the royalty income received on that date is distributed. In
most cases, therefore, the income and expenses of the trust for a period will
be reported as belonging to the trust unitholder to whom the distribution for
that period is made and the amount of the distribution for a trust unit will
generally equal the net income allocated to that trust unit, determined without
regard to depletion. This correlation may not exist if, for example, the
trustee were to establish a cash reserve to pay estimated future expenses or
pay an expense with borrowed funds. Moreover, it is possible that the IRS would
attempt to impute income to persons who are trust unitholders when a royalty
payment on the net profits interests accrued, to disallow the deduction of
administrative expenses to persons who were not trust unitholders when the
expenses were incurred, or both. 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.
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Royalty Income and Depletion
In the opinion of Tax Counsel, the income from the net profits interests
will be royalty income qualifying for an allowance for depletion. The depletion
allowance must be computed separately by each trust unitholder for each oil or
gas property (within the meaning of Section 614 of the Internal Revenue Code of
1986, as amended (the "Code")). Tax Counsel understands that the IRS is
presently taking the position that a net profits interest carved from multiple
properties is a single property for depletion purposes. Accordingly, the trust
intends to take the position that each net profits interest transferred to the
trust by a conveyance is a single property for depletion purposes. It would
change this position if a different method were established by the IRS or the
courts.
The deduction for depletion is determined annually and is the greater of
cost depletion or, if allowable, percentage depletion. Royalty income from
production attributable to trust units owned by "independent producers" will
qualify for percentage depletion. An individual or entity with production of
the equivalent of 1,000 barrels of oil per day or less is an "independent
producer." Percentage depletion is a statutory allowance equal to 15% of the
gross income from production from a property, subject to a net income
limitation of 100% of the taxable income from the property, computed without
regard to depletion deductions and certain loss carrybacks. The depletion
deduction attributable to percentage depletion for a taxable year is limited to
65% of the taxpayer's taxable income for the year before allowance of
"independent producers" percentage depletion. Unlike cost depletion, percentage
depletion is not limited to the adjusted tax basis of the property, although it
reduces the adjusted tax basis (but not below zero).
Cross Timbers believes that trust unitholders who purchase trust units in
this offering will derive a substantially greater benefit from cost depletion
than from percentage depletion.
In computing cost depletion for each property for any year, the adjusted tax
basis of the property at the beginning of the year is divided by the estimated
total units (e.g., Bbls of oil or Mcf of gas) recoverable from the property to
determine the per-unit allowance for the property. The per-unit allowance is
then multiplied by the number of units produced and sold from the property
during the year. Cost depletion for a property cannot exceed the adjusted tax
basis of the property. Since the trust will be taxed as a grantor trust, each
trust unitholder will be deemed to own an undivided interest in the net profits
interests and other assets, if any, of the trust and will compute cost
depletion using his basis in his trust units. Information will be provided to
each trust unitholder reflecting how his basis should be allocated among each
property represented by his trust units. To the extent the depletion tax
deduction exceeds cash distributions per trust unit, that excess can be
deducted from the taxpayer's other sources of taxable income.
Other Income and Expenses
It is anticipated that the only other income of the trust will be interest
income earned on funds held as a reserve. Other expenses of the trust will
include any state and local taxes imposed on the trust and administrative
expenses of the trustee. Although the issue has not been finally resolved, Tax
Counsel 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 aggregate more than 2% of adjusted gross income.
Alternative Minimum Tax
All taxpayers are subject to an alternative minimum tax. Alternative minimum
taxable income ("AMTI") 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 the
aggregate percentage depletion deductions for an oil or gas property over the
adjusted
38
tax basis of the property. The alternative minimum tax rate for noncorporate
taxpayers (other than married persons filing separately) is 26% up to $175,000
and 28% over $175,000 of AMTI exceeding an exemption amount, which varies
between $45,000 and zero. Alternative minimum tax ("AMT") is the excess of a
taxpayer's "tentative minimum tax" for a tax year over his "regular" tax for
that year. The tentative minimum tax is determined by multiplying the excess of
AMTI over the applicable exemption amount by 26% up to $175,000 and 28% over
$175,000 and subtracting the AMT foreign tax credit. Reduced maximum AMT tax
rates apply to net capital gains and certain other gains.
Since the effect of the AMT varies depending upon each trust unitholder's
personal tax and financial position, each prospective investor is advised to
consult with his own tax advisor concerning the effect of the AMT on him.
Section 29 Tight Sands Natural Gas Tax Credit
Some of the natural gas production attributable to the net profits interests
is produced from tight sands formations. Subject to certain statutory
requirements, taxpayers are entitled to the Section 29 tax credit for
production and sale of certain natural gas produced from tight formations
("tight sands"). The Section 29 tax credit applies to tight sands natural gas
produced and sold to an unrelated party prior to January 1, 2003 from wells
drilled prior to January 1, 1993 and after November 5, 1990 or after December
31, 1979 if the formation was dedicated to interstate commerce, within the
meaning of the Natural Gas Policy Act of 1978, prior to April 20, 1977. The
Section 29 tax credit for qualifying tight sands natural gas is equal to $3.00
per barrel of oil equivalent (i.e., 5.8 MMBtu), or approximately $.52 per
MMBtu. The credit is reduced by a formula computation as the price of oil
("reference price") rises above an inflation adjusted amount. Because the
calendar year 1998 reference price did not exceed the inflation adjusted
amount, the credit was not reduced in 1998 and is not expected to be reduced in
1999. In the opinion of Tax Counsel, if the requisite statutory requirements
are met, the trust unitholders will be eligible to claim the Section 29 tax
credit for sales of qualified tight sands natural gas production included in
the calculation of the net profits interests. Cross Timbers believes that all
of the statutory requirements have been or will be met on substantially all of
the tight sands wells.
The Section 29 tax credit allowable for any taxable year cannot exceed the
excess, if any, 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 credit for prior year minimum tax
liability. 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 preceding sentence. There is no provision for the carryback or
carryforward of the Section 29 tax credit in any other circumstances. Hence, a
trust unitholder may not receive the full benefit of the tax credit depending
on his particular circumstances.
Non-Passive Activity Income and Loss
The income and expenses of the trust and the Section 29 tax credit will not
be taken into account in computing the passive activity losses and income under
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 Tight
Sands Natural Gas Tax Credit" above.
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Unrelated Business Taxable Income
Certain organizations that are generally exempt from tax under Code Section
501 are subject to tax on certain types of business income defined in Code
Section 512 as unrelated business income. In the opinion of Tax Counsel, 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 Code
Section 514(b). In general, a trust unit would be debt-financed if the trust
unitholder 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.
Gain or loss on the sale of trust units by a trust unitholder who is not a
dealer of the trust units will 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.
A portion of the long-term gain will be treated as ordinary income to the
extent of the depletion recapture amount explained below. 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. Upon the sale of the trust units, a trust unitholder must treat
as ordinary income his depletion recapture amount, which is an amount equal to
the lesser of (1) the gain on such sale or (2) the sum of the prior depletion
deductions taken on the trust units, but not in excess of the initial basis of
the trust units. It is possible that the IRS would take the position that a
portion of the sales proceeds is ordinary income to the extent of any accrued
income at the time of sale allocable to the trust units sold, but which has not
been distributed to the selling trust unitholder.
Taxation of Foreign Holders
Unless the election described below is made, a nonresident alien individual,
foreign corporation, or foreign estate or trust (a "Foreign holder") will be
subject to federal income withholding tax on his share of gross royalty income
from the net profits interests at a 30% rate, or lower treaty rate if
applicable and proper evidence is supplied to the withholding agent, without
any deductions. Gain realized on a sale of a trust unit by a Foreign holder
will be subject to federal income tax only if:
. the gain is otherwise effectively connected with business conducted by
the Foreign holder in the United States;
. the Foreign holder is an individual who is present in the United States
for at least 183 days in the year of the sale;
. the Foreign holder owns 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.
The trust unitholders who are Foreign holders may elect under 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
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 Code Section 884. To claim the
deductions allowable in computing net income, including cost depletion, an
electing Foreign holder will have to file a United
40
States income tax return. To avoid withholding, an electing Foreign holder will
have to 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: (1) the trust unitholder is an individual or other
noncorporate taxpayer and (2) the trust unitholder fails to comply with certain
reporting procedures.
Tax Shelter Registration
The Company does not believe that the trust will meet the requirements to
register as a "tax shelter" under Code Section 6111. However, it is possible
that those requirements may be met for any trust unitholders whose investment
base is reduced by borrowing. To avoid any potential difficulty, the trust will
be registered as a tax shelter with the IRS. The trustee will furnish the tax
shelter registration number to each transferee of trust units and 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 annual
reports in order to permit computation of their tax liability. See "Description
of the Trust Units--Periodic Reports."
STATE TAX CONSIDERATIONS
The following is a brief summary of information regarding 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 on
these matters.
Income Tax Considerations
Wyoming presently does not have a state income tax on resident or
nonresident individuals. Kansas and Oklahoma impose income taxes on residents
and, for certain types of income, nonresidents. Trust unitholders may also be
subject to taxation by their state of residence on income derived from the
trust.
Kansas tax counsel, Morris, Laing, Evans, Brock & Kennedy, Chartered, is of
the opinion that, although there is no determinative precedent and Kansas
taxing authorities may adopt a different view:
. the activities of the trust and the trustee, as permitted under the
Indenture and the conveyance, will not subject either the trust or the
trustee to income taxation by the State of Kansas; and
. a trust unitholder who is not a Kansas resident will not be subject to
Kansas income tax and will not be required to file a Kansas income tax
return, if
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-- the trust unitholder does not use his trust units or his indirect
interest in the net profits interest in conducting a trade,
business, profession or occupation in Kansas, and
-- the trust unitholder is not subject to Kansas income tax for some
other reason.
In providing this opinion, Kansas tax counsel has assumed, among other things,
that the trust:
. will not own any property in Kansas other than the net profits
interests;
. will not conduct any activities in Kansas other than ownership of the
net profits interests for the benefit of trust unitholders; and
. is a grantor trust for federal income tax purposes.
The income tax law of Oklahoma is based on federal income tax laws. Assuming
the trust is taxed as a grantor trust for federal income tax purposes, the
trust unitholders will be subject to Oklahoma income tax on their share of
income from the Oklahoma net profits interests. It is uncertain whether trust
unitholders who are nonresidents of Oklahoma will be taxed in that state on
gains from sales of trust units.
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 for their share of income of the trust allocable to states
imposing an income tax on that income.
Probate and Property Considerations
Kansas tax counsel is also of the opinion that under Kansas law, except as
noted below, the trust units will be treated the same as other securities. They
will be treated as interests in intangible personal property located where the
trust unitholder resides rather than as interests in tangible property in
Kansas.
However, if the certificate representing a trust unit is physically located
in Kansas at the time of the death of the owner who is not a Kansas resident,
the Kansas courts by statute have jurisdiction to probate and administer the
trust unit. In that event, unless Kansas courts determine otherwise, the estate
tax and devolution of title laws of Kansas would apply to the trust unit. This
could make inheritance and related matters pertaining to trust units held by
Kansas non-residents more onerous than if the trust units were treated as
interests in intangible personal property located in the state of the owner's
residence.
The trust units may constitute real property or an interest in real property
under the inheritance, estate and probate laws of Oklahoma and Wyoming. If the
trust units are held to be real property or an interest in real property under
the laws of those states, the trust units may be subject to devolution, probate
and administration and estate taxes under the laws of those states.
ERISA CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended ("ERISA"),
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 Code provides similar requirements and standards which
are applicable to these types of plans and to individual retirement accounts,
whether or not subject to ERISA (collectively, "Qualified Plans").
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
42
.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 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 Code. These regulations
provide that the underlying assets of an entity will not be considered "plan
assets" if the equity interests in the entity are a publicly offered security.
Cross Timbers expects that at the time of the sale of the trust units in this
offering, they will be publicly offered securities. Fiduciaries, however, will
need to determine whether the acquisition of trust units is a nonexempt
prohibited transaction under the general requirements of ERISA Section 406 and
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 Code of their acquisition and ownership of
trust units.
DESCRIPTION OF THE TRUST INDENTURE
The following information and the information included under "Description
of the Trust Units" summarize 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 created the net profits interests and conveyed them to the
trust in exchange for 40,000,000 trust units.
Cross Timbers organized the trust under Texas law to acquire and hold the
net profits interests for the benefit of the trust unitholders. Neither the
trust nor the trustee has any control over or responsibility for costs
relating to the operation of the underlying properties. Neither Cross Timbers
nor other operators of the underlying properties have any contractual
commitments to the trust to conduct further drilling on or to maintain their
ownership interest in any of these properties. For a description of the
underlying properties and other information relating to them, see "The Net
Profits Interests and the Underlying Properties."
The beneficial interest in the trust is divided into 40,000,000 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--
43
. increase the power of the trustee to engage in business or investment
activities;
. alter the rights of the trust unitholders as among themselves; and
. 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 cash and
temporary investments being held for the payment of expenses and liabilities
and for distribution to the trust unitholders. You will find information
relating to the assets of the trust in "The Net Profits Interests and the
Underlying Properties."
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 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 and
cash, and it may not engage in any investment activity except investing cash on
hand.
At the request of Cross Timbers, the trustee must sell net profits interests
relating to the underlying properties sold by Cross Timbers to an unaffiliated
third party if in any calendar year the net profits interests sold do not
exceed 1% of the discounted present value of estimated future net revenues for
the proved reserves of the trust's net profits interests, as set forth in the
most recent reserve report.
The trustee may sell the net profits interests in any of the following
circumstances:
. the sale does not involve a material part of the trust's assets and is
in the best interests of the trust unitholders. A majority of the trust
units represented at a meeting of the trust unitholders where a quorum
is present must approve the sale; or
44
. the sale is in the best interests of the trust unitholders, constitutes
a material part of the trust's assets and holders representing 80% of
the outstanding trust units 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 the net proceeds from any sale of the net
profits interests to the trust unitholders.
The trustee may require any trust unitholder to dispose of his trust units
if an administrative or judicial proceeding seeks to cancel or forfeit any of
the property in which the trust holds an interest because of the nationality or
any other status of that trust unitholder. If a trust unitholder fails to
dispose of his trust units, the trustee has the right to purchase them and to
borrow funds to make that purchase.
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 (1) the net profits interests become working interests, or (2)
the trust becomes an operating business.
Liabilities of the Trust
Because the trust does not conduct an active business and the trustee has
little power to incur obligations, Cross Timbers expects that the trust will
only incur liabilities for routine administrative expenses. These might include
the trustee's fees and accounting, engineering, legal and other professional
fees.
Fiduciary 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 will not make business decisions affecting the assets of the
trust. Therefore, substantially all of the trustee's functions under the trust
indenture are expected to be ministerial in nature. See "--Duties and Limited
Powers of the Trustee," above. Under Texas law, the trustee may not profit from
any transaction with the trust. The trust indenture, however, provides that the
trustee may:
. charge for its services as trustee;
. retain funds to pay for future expenses and deposit them in its own
account;
. lend funds at commercial rates to the trust to pay the trust's expenses;
and
. seek reimbursement from the trust for its out-of-pocket expenses.
In discharging its fiduciary duty 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 constituting 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
45
indemnified for any liability or cost that it incurs in the administration of
the trust, except in cases of fraud, gross negligence or bad faith. The trustee
will have a lien on the assets of the trust as security for this
indemnification and its compensation earned as trustee. The trustee is entitled
to indemnification from trust assets or, to the extent that trust assets are
insufficient, from Cross Timbers. Trust unitholders will not be liable to the
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 its
failure 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 after 1999;
. the holders of 80% or more of the outstanding trust units vote in favor
of termination; or
. the trust violates the "rule against perpetuities."
The trustee would then sell all of the trust's assets, either by private
sale or public auction, and distribute the net proceeds of the sale to the
trust unitholders.
Dispute Resolution
Any dispute, controversy or claim that may arise between Cross Timbers and
the trustee relating to the trust will be submitted to binding arbitration
before a tribunal of three arbitrators.
Compensation of the 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.
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 with respect to each of his
trust units as every other trust unitholder has with respect to his units. The
trust has 40,000,000 trust units outstanding.
46
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 at the end of the
last business day of the month (the "monthly record date") will receive a pro-
rata distribution no later than 10 business days after the monthly record date.
The first distribution will be made around April 10, 1999 to trust unitholders
owning trust units on March 31, 1999.
Unless otherwise advised by counsel or the IRS, the trustee will treat the
income and expenses of the trust for each month as belonging to the trust
unitholders of record on the monthly record date. Trust unitholders will
recognize income and expenses for tax purposes in the month the trust receives
or pays those amounts, rather than in the month the trust distributes them.
Minor variances may occur. For example, the trustee could establish a reserve
in one month that would not result in a tax deduction until a later month. The
trustee could also make a payment in one month that would be amortized for tax
purposes over several months. See "Federal Income Tax Consequences."
Transfer of Trust Units
Trust unitholders may transfer their trust units by sending their trust unit
certificate to the trustee along with a transfer form that is properly
completed. The trustee will not require either the transferor or transferee to
pay a service charge for any transfer of a trust unit. The trustee may require
payment of any tax or other governmental charge imposed for a transfer. The
trustee may treat the owner of any trust unit as shown by its records as the
owner of the trust unit. The trustee will not be considered to know about any
claim or demand on a trust unit by any party except the record owner. A person
who acquires a trust unit after any monthly record date will not be entitled to
the distribution relating to that monthly record date. Texas law will govern
all matters affecting the title, ownership, warranty or transfer of trust
units.
Periodic Reports
The trustee will mail to trust unitholders quarterly reports showing the
assets, liabilities, receipts and disbursements of the trust for each quarter
except the fourth quarter. No later than 120 days following the end of each
year, the trustee will mail to the trust unitholders an annual report
containing audited financial statements of the trust.
The trustee will file all required trust federal and state income tax and
information returns. The trustee will prepare and mail to trust unitholders
quarterly and 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 must ensure that all contractual liabilities of the trust are
limited to the assets of the trust. The trustee will be liable for its failure
to do so. Texas law is unclear whether a trust unitholder would be responsible
for a liability that exceeds the net assets of the trust and the trustee.
Because of the value and passive nature of the trust assets and the
restrictions in the Indenture on the power of the trustee to incur liabilities,
Cross Timbers believes it is unlikely that a trust unitholder would incur any
liability from the trust based on its ownership of trust units.
47
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, when a majority of the
trust units held by the trust unitholders at a meeting where there is a quorum
approve a matter, it is approved. This is true, even if a majority of the total
trust units did not approve it. The affirmative vote of the holders of 80% of
the outstanding trust units is required to
. terminate the trust,
. amend the Trust Indenture, or
. approve the sale of all or any material part of the assets of the trust.
The trustee must consent before all or any part of the trust assets can be
sold except in connection with the termination of the trust or limited sales
directed by Cross Timbers in conjunction with its sale of underlying
properties. The trustee may be removed, with or without cause, by the vote of
the holders of a majority of the outstanding trust units.
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.
Trust Units Common Stock
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
income tax; trust unitholders their income, and their
are directly subject to stockholders are taxed on
income tax on their dividends.
proportionate shares of trust
net income, adjusted for tax
deductions and credits.
Distributions
Substantially all trust Stockholders receive
income is distributed to dividends at the discretion
trust unitholders. of the board of directors.
Business Interest is limited to A corporation conducts an
and Assets specific assets with a finite active business for an
economic life. unlimited term and can
reinvest its earnings and
raise additional capital to
expand.
Limited Texas law and the laws of Corporate laws provide that a
Liability other states do not stockholder is not liable for
specifically provide for the obligations and
limited liability of trust liabilities of the
unitholders. However, due to corporation, subject to
the size and nature of the limited exceptions.
trust assets, liability in
excess of the trust
unitholders' investment is
extremely unlikely.
48
SELLING TRUST UNITHOLDER
Cross Timbers currently owns 100% of the 40,000,000 outstanding trust units.
It is offering 15,000,000 trust units in this offering, or 17,250,000 trust
units if the underwriters exercise their over-allotment option in full.
Cross Timbers has reserved $12 million of trust units for issuance in Cross
Timbers' 1998 Royalty Trust Option Plan. It has granted options covering all
trust units in the plan to its executive officers at an exercise price equal to
the public offering price in this offering. The options are exercisable for a
period of three years, beginning at the date of grant. Assuming the sale of all
trust units offered in this offering and the exercise in full of the
underwriters' over-allotment option, after taking into account the trust units
reserved for the plan, Cross Timbers will have trust units, or % of the
outstanding trust units available for future sale or distribution.
Cross Timbers has announced that it may form additional royalty trusts with
other properties. It may exchange trust units for oil and natural gas
properties or use them for other corporate purposes.
Prior to this offering there has been no public market for the trust units.
Cross Timbers cannot predict the effect on future market prices, if any, of
market sales of trust units or the availability of trust units for sale if it
disposes of its remaining trust units. Nevertheless, sales of substantial
amounts of trust units in the public market could adversely affect prevailing
market prices.
LEGAL MATTERS
Counsel for Cross Timbers, Kelly, Hart & Hallman, P.C., Fort Worth, Texas,
will give a legal opinion that the trust units are valid and fully paid without
further consideration. Counsel for the underwriters, Andrews & Kurth L.L.P.,
Houston, Texas, will give a legal opinion to the underwriters regarding other
matters related to this offering. Butler & Binion, L.L.P., Houston, Texas, will
give the tax opinion set forth in the section of this prospectus captioned
"Federal Income Tax Consequences." Morris, Laing, Evans, Brock & Kennedy,
Chartered, Wichita, Kansas, will give the Kansas tax opinion set forth in the
section of this prospectus captioned "State Tax Considerations." Certain
members of Kelly, Hart & Hallman, P.C. currently own approximately 23,200
shares of common stock of Cross Timbers, and certain partners of Butler &
Binion, L.L.P. own 95,985 shares of common stock of Cross Timbers.
EXPERTS
Certain information appearing in this prospectus regarding the December 31,
1998 estimated quantities of reserves of the underlying properties and net
profits interests owned by the trust, the future net revenues from those
reserves and their present value is based on estimates of the reserves and
present values prepared by or derived from estimates prepared by Miller and
Lents, Ltd. independent petroleum engineers.
The financial statements of Cross Timbers incorporated by reference in this
prospectus, and statements of revenues and direct operating expenses of the
underlying properties and the statement of assets and trust corpus of Hugoton
Royalty Trust included in this Prospectus and elsewhere in the registration
statement, have been audited by Arthur Andersen LLP, independent public
accountants, as indicated in their reports with respect thereto, and are
included herein in reliance upon the authority of said firm as experts in
accounting and auditing.
49
AVAILABLE INFORMATION
Cross Timbers files annual, quarterly and current reports, proxy statements
and other information with the SEC. You may read and copy any of these reports,
statements or other information at the SEC's public reference room at 450 Fifth
Street, N.W., Washington, D.C. 20549. You may request copies of these
documents, upon payment of a duplicating fee, by writing to the SEC at the
address in the previous sentence. To obtain information on the operation of the
public reference rooms you may call the SEC at (800) SEC-0330. Cross Timbers'
filings are also available to the public on the SEC Internet Web site at
http://www.sec.gov.
The SEC allows Cross Timbers to "incorporate by reference" information Cross
Timbers files with it, which means that Cross Timbers can disclose important
information to you by referring you to those documents. The information
incorporated by reference is considered to be part of this prospectus.
Cross Timbers incorporates by reference in this prospectus the following
documents:
. Its Annual Report on Form 10-K for the year ended December 31, 1997;
. Its Quarterly Reports on Form 10-Q for the quarters ended March 31,
1998, June 30, 1998, and September 30, 1998, and on Form 10 Q/A dated
September 30, 1998;
. Its Current Reports on Form 8-K dated February 12, 1998, February 16,
1998 (Amendment No. 1 to Report dated December 1, 1997), February 18,
1998, February 25, 1998, April 13, 1998, April 17, 1998, April 21, 1998,
April 24, 1998, May 19,1998, July 2, 1998 (Amendment No. 1 to Report
dated April 24, 1998), August 26, 1998, and December 21, 1998; and
. all other documents filed by it pursuant to Section 13(a) or 15(d) of
the Securities Exchange Act of 1934 after the date of this prospectus
and prior to termination of the offering of the trust units.
Information that Cross Timbers files later with the SEC will automatically
update the information in this prospectus. In all cases, you should rely on the
later information over different information included or incorporated by
reference in this prospectus.
As a recipient of this prospectus, you may request a copy of any document
Cross Timbers incorporates by reference, except exhibits to the documents that
are not specifically incorporated by reference, at no cost to you by writing or
calling Cross Timbers at 810 Houston Street, Suite 2000, Fort Worth, Texas
76102, Attention: Investor Relations, telephone (817) 870-2800.
NationsBank, N.A. is trustee of the trust. The trustee's address is 901 Main
Street, 17th Floor, Dallas, Texas 75202, and its telephone number is (214) 508-
2400.
50
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.
Bcfe -- One billion cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.
Btu -- A British Thermal Unit, a common unit of energy measurement.
Estimated Future Net Revenues -- Also referred to as "estimated future net cash
flows." The result of applying current prices of oil and natural gas to
estimated future production from oil and natural gas proved reserves, reduced
by estimated future expenditures, based on current costs to be incurred, in
developing and producing the proved reserves, excluding overhead. Estimated
future net revenues do not include the effects of the tight sands natural gas
tax credit, since the trust is not a taxable entity and the credit goes
directly to the trust unitholders.
MBbl -- One thousand Bbl.
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.
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.
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.
51
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 or Overriding 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 or overriding royalty interest owner has no right to consent to
or approve the operation and development of the property, while the owners of
the working interest have the exclusive right to exploit the mineral on the
land.
Standardized Measure of Discounted Future Net Cash Flows -- Also referred to
herein as "standardized measure." It is the present value of estimated future
net revenues computed by discounting estimated future net revenues at a rate of
10% annually.
Working Interest -- A real property interest entitling the owner to receive a
specified percentage of the proceeds of the sale of oil and natural gas
production or a percentage of the production, but requiring the owner of the
working interest to bear the cost to explore for, develop and produce such oil
and natural gas. A working interest owner who owns a portion of the working
interest may participate either as operator or by voting his percentage
interest to approve or disapprove the appointment of an operator and certain
activities in connection with the development and operation of a property.
52
INDEX TO FINANCIAL STATEMENTS
Underlying Properties
Report of Independent Public Accountants................................ F-2
Statements of Revenues and Direct Operating Expenses for the Years Ended
December 31, 1996, 1997 and 1998....................................... F-3
Notes to Financial Statements........................................... F-4
Hugoton Royalty Trust
Report of Independent Public Accountants................................ F-8
Statement of Assets and Trust Corpus as of December 31, 1998............ F-9
Note to Statement of Assets and Trust Corpus............................ F-10
Pro Forma Statement of Distributable Income for the Year Ended
December 31, 1998 (Unaudited).......................................... F-11
Notes to Pro Forma Statement of Distributable Income (Unaudited)........ F-12
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
Cross Timbers Oil Company:
We have audited the accompanying statements of revenues and direct operating
expenses of the Underlying Properties of Cross Timbers Oil Company ("the
Company") for each of the three years in the period ended December 31, 1998.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statement. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
The accompanying statements of revenue and direct operating expenses have
been prepared on the cash basis of accounting, as described in Note 2, and are
not intended to be a presentation in conformity with generally accepted
accounting principles.
In our opinion, the statements referred to above present fairly, in all
material respects, the revenues and direct operating expenses of the Underlying
Properties for each of the three years in the period ended December 31, 1998,
in conformity with the basis of accounting described above and in Note 2.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
January 22, 1999
F-2
UNDERLYING PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
For the Years Ended December 31, 1996, 1997 and 1998
1996 1997 1998
------- ------- -------
(in thousands)
Revenues
Gas sales............................................. $60,502 $82,192 $77,124
Oil sales............................................. 9,075 9,704 7,083
------- ------- -------
Total............................................... 69,577 91,896 84,207
------- ------- -------
Direct Operating Expenses
Production and property taxes and transportation...... 5,919 9,173 9,170
Production expenses................................... 11,359 12,837 13,031
------- ------- -------
Total............................................... 17,278 22,010 22,201
------- ------- -------
Excess of Revenues over Direct Operating Expenses....... $52,299 $69,886 $62,006
======= ======= =======
See Accompanying Notes to Financial Statements.
F-3
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS
1. UNDERLYING PROPERTIES
The Underlying Properties are predominantly working interests in producing
properties currently owned by Cross Timbers Oil Company ("Company") in the
Hugoton Area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the
Green River Basin of Wyoming. The Company conveyed 80% defined net profits
interests ("Net Profits Interests") in the Underlying Properties to the Hugoton
Royalty Trust ("Trust") as of December 1998. Estimated proved reserves
attributable to the Underlying Properties are approximately 5% oil and 95%
natural gas, based on discounted present value of estimated future net revenues
as of December 31, 1998. See Note 5.
All of the Underlying Properties were acquired by the Company from 1986
through 1998. Significant property acquisitions were made by the Company during
the three-year period presented in the accompanying financial statements. The
statements include the historical revenues and direct operating expenses from
these acquired properties for all years presented.
2. BASIS OF PRESENTATION
The statements of revenues and direct operating expenses of the Underlying
Properties were derived from the historical accounting records of the Company
(and prior owners for acquisitions occurring during the three-year period
presented), and are presented on the cash basis of accounting before the
effects of conveyance of the Net Profits Interests. The statements do not
include depreciation, depletion and amortization, general and administrative or
interest expenses.
Amounts are included in the accompanying financial statements in the period
Net Proceeds are distributed by the Company to the Trust, which is the month
subsequent to the month received by the Company. Accordingly, the financial
statements for the year ended December 31 include amounts received by the
Company from December through the following November.
Royalty income of the Trust is determined based on the defined 80% net
profits interest percentage of Net Proceeds of the Underlying Properties. The
computation also includes deductions for capital development expenditures on
the properties of $14,392,000 in 1996, $40,027,000 in 1997 and $33,019,000 in
1998, as well as an overhead charge totalling $4,557,000 in 1996, $5,354,000 in
1997, and $6,198,000 in 1998. Accordingly, royalty income of the Trust is
materially different from the excess of revenues over direct operating expenses
from the Underlying Properties.
3. RELATED PARTY TRANSACTIONS
The Company sells a significant portion of natural gas production from the
Underlying Properties to certain of the Company's wholly owned subsidiaries,
generally at amounts approximating monthly spot market prices. Most of the
production from the Hugoton area is sold under a contract to Timberland
Gathering & Processing Company, Inc. ("TGPC"). Much of the natural gas
production in Major County, Oklahoma is sold to Ringwood Gathering Company
("RGC") which retains a $0.313 per Mcf gathering fee. TGPC and RGC sell natural
gas to Cross Timbers Energy Services, Inc. ("CTES") which markets natural gas
to third parties. The Company sells directly to CTES most natural gas
production not sold directly to TGPC or RGC.
F-4
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS--(Continued)
Sales from the Underlying Properties to the Company's wholly owned
subsidiaries are as follows (in thousands):
1996 1997 1998
------- ------- -------
TGPC................................................. $12,348 $16,429 $14,519
RGC.................................................. 6,768 8,436 6,421
CTES................................................. 12,167 32,294 33,878
4. CONTINGENCIES
The Company is a defendant in two separate lawsuits that could, if adversely
determined, decrease future revenues from certain of the Underlying Properties.
Damages relating to production prior to the formation of the Trust will be
borne by the Company.
A class action lawsuit, Booth, et al. v. Cross Timbers Oil Company, was filed
on April 3, 1998 in the District Court of Dewey County, Oklahoma by royalty
owners of natural gas wells in Oklahoma. The plaintiffs allege that since 1991
the Company has underpaid royalty owners as a result of (1) reducing royalties
for improper charges for production, marketing, gathering, processing and
transportation costs and (2) selling natural gas through affiliated companies
at prices less favorable from those paid by third parties. The Company believes
that it has strong defenses to this lawsuit and intends to vigorously defend
its position. However, if a judgment or settlement increased the amount of
future royalty payments, revenues from the Underlying Properties will be
reduced. The amount of any reduction in such revenues is not presently
determinable, but is not expected to be material to the Trust's distributable
income, financial position or liquidity.
A second lawsuit, United States of America ex rel. Grynberg v. Cross Timbers
Oil Company, et al., was filed in the United States District Court for the
Western District of Oklahoma. This action alleges that in computing royalties
payable for natural gas produced from federal leases and lands owned by Native
Americans, the Company has mismeasured the volume of natural gas and wrongfully
analyzed its heating content. The suit, which was brought under the qui tam
provisions of the U.S. False Claims Act, seeks treble damages for the unpaid
royalties (with interest), civil penalties and an order for the Company to
cease the allegedly improper measuring practices. This lawsuit is one of more
that 75 suits filed nationwide by the same plaintiff alleging similar claims
against over 300 producers and pipeline companies. Royalties paid by the
Company for production from Underlying Properties on federal and Native
American lands for 1998 totalled approximately $2.8 million. The Company
believes that the allegations of this lawsuit are without merit. However, an
order to change measuring practices or a related settlement could adversely
affect future revenues from the Underlying Properties by an amount that is not
presently determinable, but is not expected to be material to the Trust's
distributable income, financial position or liquidity.
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)
Proved oil and natural gas reserves of the Underlying Properties have been
estimated as of December 31, 1998 by independent petroleum engineers. The
reserve estimates provided for the Underlying Properties are before the effects
of conveying the defined net profits interests to the Trust. In accordance with
Statement of Financial Accounting Standards No. 69, estimates of future net
revenues from proved reserves have been prepared using year-end oil and natural
gas prices and current costs to produce and develop the proved reserves,
excluding overhead. The standardized measure of future net cash flows from oil
and natural gas reserves is calculated based on discounting such future net
cash flows at an annual rate of 10%.
F-5
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS--(Continued)
Year-end posted West Texas Intermediate crude oil prices were $18.00 per barrel
for 1995, $24.25 per barrel for 1996, $15.50 per barrel for 1997, and $9.50 per
barrel for 1998. Year-end weighted average spot natural gas prices were $1.76
per Mcf for 1995, $2.84 per Mcf for 1996, $2.01 per Mcf for 1997, and $2.01 per
Mcf for 1998.
The standardized measure of future net cash flows is not intended to
represent the fair value of the Underlying Properties. Numerous uncertainties
are inherent in estimating volumes and values of proved reserves and in
projecting future production rates and timing of development expenditures. Such
reserve estimates are subject to change as additional information becomes
available. The reserves actually recovered and the timing of production may be
substantially different from the original estimates. Also, because natural gas
prices are influenced by seasonal demand, use of year-end prices, as required
by the Financial Accounting Standards Board, may not be representative in
estimating future revenues or reserve data.
Reserve estimates for Underlying Properties that were acquired between 1996
and 1998 are not available for periods prior to the date they were acquired by
the Company. Estimated proved reserves and the related standardized measure of
these properties were calculated as of December 31, 1995, 1996 and 1997, by
adding production prior to the date acquired to estimates as of the acquisition
dates.
Gas (Mcf) Oil (Bbls)
Proved Reserves --------- ----------
(in thousands)
Balance, December 31, 1995.............................. 445,836 4,442
Revisions............................................. 20,301 432
Extensions, discoveries and other additions........... 27,131 145
Production............................................ (36,143) (455)
------- -----
Balance, December 31, 1996.............................. 457,125 4,564
Revisions............................................. (15,557) (305)
Extensions, discoveries and other additions........... 84,394 485
Production............................................ (37,172) (470)
------- -----
Balance, December 31, 1997.............................. 488,790 4,274
Revisions............................................. 17,798 (24)
Extensions, discoveries and other additions........... 47,020 259
Production............................................ (38,535) (479)
------- -----
Balance, December 31, 1998.............................. 515,073 4,030
======= =====
Proved Developed Reserves
Gas (Mcf) Oil (Bbls)
--------- ----------
(in thousands)
December 31, 1995....................................... 384,588 3,633
======= =====
December 31, 1996....................................... 401,784 3,966
======= =====
December 31, 1997....................................... 417,912 3,574
======= =====
December 31, 1998....................................... 435,328 3,368
======= =====
F-6
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS--(Continued)
Standardized Measure of Discounted
Future Net Cash Flows Relating to
Proved Reserves
December 31,
----------------------------------
1996 1997 1998
---------- ---------- ----------
(in thousands)
Future cash inflows.................... $1,414,852 $1,057,023 $1,087,660
Future costs:
Production........................... 357,049 326,325 364,930
Development.......................... 30,894 42,460 48,212
---------- ---------- ----------
Future net cash flows.................. 1,026,909 688,238 674,518
10% discount factor.................... 467,687 322,301 327,341
---------- ---------- ----------
Standardized measure of discounted
future net cash flows................. $ 559,222 $ 365,937 $ 347,177
========== ========== ==========
Changes in Standardized Measure of
Discounted Future Net Cash Flows from
Proved Reserves
December 31,
----------------------------------
1996 1997 1998
---------- ---------- ----------
(in thousands)
Standardized measure, beginning of
year.................................. $ 273,032 $ 559,222 $ 365,937
---------- ---------- ----------
Revisions:
Prices and costs..................... 241,743 (212,920) (27,206)
Quantity estimates................... 47,520 5,585 11,161
Accretion of discount................ 24,457 50,574 33,464
Future development costs............. (18,620) (48,471) (33,542)
Production rates and other........... (544) (1,076) (827)
---------- ---------- ----------
Net revisions...................... 294,556 (206,308) (16,950)
Extensions, discoveries and other
additions............................. 29,541 42,882 27,177
Production............................. (52,299) (69,886) (62,006)
Development costs...................... 14,392 40,027 33,019
---------- ---------- ----------
Net change........................... 286,190 (193,285) (18,760)
---------- ---------- ----------
Standardized measure, end of year...... $ 559,222 $ 365,937 $ 347,177
========== ========== ==========
F-7
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
Hugoton Royalty Trust:
We have audited the accompanying statement of assets and trust corpus of
Hugoton Royalty Trust as of December 31, 1998. This financial statement is the
responsibility of the management of Cross Timbers Oil Company. Our
responsibility is to express an opinion on this financial statement based on
our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statement is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statement. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the statement referred to above presents fairly, in all
material respects, the assets and trust corpus of Hugoton Royalty Trust as of
December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
January 25, 1999
F-8
HUGOTON ROYALTY TRUST
STATEMENT OF ASSETS AND TRUST CORPUS
December 31, 1998
(in thousands)
Cash........................................................... $ 1
Net overriding royalty interests in oil and gas properties..... 247,067
--------
Total Assets................................................. $247,068
========
Trust Corpus (40,000,000 units of beneficial interest
authorized and outstanding)................................... $247,068
========
See Accompanying Note to Statement of Assets and Trust Corpus.
F-9
HUGOTON ROYALTY TRUST
NOTE TO STATEMENT OF ASSETS AND TRUST CORPUS
1. TRUST ORGANIZATION
Hugoton Royalty Trust ("Trust") is a grantor trust that was created as of
December 1, 1998 by Cross Timbers Oil Company ("Company"). The Trust was formed
to hold net overriding royalty interests equivalent to 80% defined net profits
interests in certain producing oil and gas properties in Kansas, Oklahoma and
Wyoming that were conveyed by the Company effective December 1, 1998 in
exchange for 40 million units of beneficial interest in the Trust ("Units").
The net overriding royalty interests are reflected in the accompanying
statement of assets and trust corpus at the Company's historical net book value
at the date of conveyance. The Company uses the successful efforts method of
accounting.
The Trust will terminate upon the first occurrence of: (a) disposition of all
net overriding royalty interests pursuant to terms of the Trust Indenture, (b)
when gross proceeds attributable to the Underlying Properties are less than $1
million per year for each of two successive years after 1999, or (c) a vote of
at least 80% of the Trust Unitholders to terminate the Trust in accordance with
provisions of the Trust Indenture.
F-10
HUGOTON ROYALTY TRUST
PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)
For the Year Ended December 31, 1998
(in thousands, except for per Unit amounts)
Gross Proceeds
Gas revenues......................................................... $77,124
Oil revenues......................................................... 7,083
-------
Total Revenues...................................................... 84,207
Production and property taxes and transportation..................... 9,170
-------
Total.............................................................. 75,037
-------
Production and Development Costs
Production........................................................... 13,031
Development (Note 2)................................................. 33,019
-------
Total.............................................................. 46,050
-------
Net proceeds before overhead........................................... 28,987
Overhead (Note 2)...................................................... 6,198
-------
Net proceeds........................................................... 22,789
Net profits percentage................................................. 80%
-------
Trust royalty income................................................... 18,231
Administrative expense................................................. 300
-------
Distributable income................................................... $17,931
=======
Distributable income per Unit (40,000,000 Trust Units issued and
outstanding--Note 1)................................................. $ 0.45
=======
See Accompanying Notes to Unaudited Pro Forma Statement of Distributable
Income.
F-11
HUGOTON ROYALTY TRUST
NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)
1. BASIS OF PRESENTATION
The pro forma statement of distributable income of the Trust for the year
ended December 31, 1998 has been prepared on a cash basis of accounting from
the historical results (successful efforts method of accounting) of operations
of the properties out of which the Net Profits Interests were carved and the
following assumptions made:
a. The Trust was formed and the Net Profits Interests were conveyed to
the Trust effective December 1, 1997.
A significant property acquisition was made by the Company during the
year ended December 31, 1998. The pro forma statement of distributable
income includes the historical revenues and expenses of this acquisition.
b. Net proceeds related to the Net Profits Interests are received and
recorded as royalty income by the Trust in the month following their
receipt by the Company from the Underlying Properties.
Generally the Trust will receive and record royalty income two months
after the month of production. This basis for recognizing royalty income
differs from generally accepted accounting principles which requires that
revenues be accrued in the month of production.
c. Royalty income is calculated based on 80% of the Net Proceeds from the
Underlying Properties. Net Proceeds is a defined term in the Net Profits
Interests conveyance to the Trust.
d. Administrative expense is estimated to be $300,000 annually. Such
expense generally would include Trustee fees and costs incurred by the
Trustee to administer the Trust and report Trust results to Unitholders,
including the expense of attorneys, independent auditors, reservoir
engineers, printing and mailing.
2. PRO FORMA ADJUSTMENTS
The following pro forma adjustments were made to the historical direct
operating expenses of the Underlying Properties to present pro forma
distributable income for the year ended December 31, 1998:
a. Historical development costs of $33,019,000 were deducted.
b. An overhead charge by the Company totalling $6,198,000 was deducted.
This charge, based on a monthly count of active wells operated by the
Company, is specified by the terms of the Net Profits Interest conveyance
to the Trust. Such charge is deducted in the computation of Net Proceeds
and represents reimbursement to the Company for costs associated with
monitoring the Underlying Properties.
3. FEDERAL INCOME TAXES
As a grantor trust, the Trust will not be required to pay federal income
taxes. Accordingly, the accompanying pro forma statement of distributable
income does not include a provision for federal income taxes.
F-12
HUGOTON ROYALTY TRUST
NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)--(Continued)
4. CONTINGENCIES
The Company is a defendant in two separate lawsuits that could, if adversely
determined, decrease future Trust distributable income. Damages relating to
production prior to the formation of the Trust will be borne by the Company.
A class action lawsuit, Booth, et al. v. Cross Timbers Oil Company, was
filed on April 3, 1998 in the District Court of Dewey County, Oklahoma by
royalty owners of natural gas wells in Oklahoma. The plaintiffs allege that
since 1991 the Company has underpaid royalty owners as a result of (1) reducing
royalties for improper charges for production, marketing, gathering, processing
and transportation costs and (2) selling natural gas through affiliated
companies at prices less favorable from those paid by third parties. The
Company believes that it has strong defenses to this lawsuit and intends to
vigorously defend its position. However, if a judgment or settlement increased
the amount of future royalty payments, the Trust would bear its proportionate
share of the increased royalties through reduced Net Proceeds. The amount of
any reduction in Net Proceeds is not presently determinable, but is not
expected to be material to the Trust's distributable income, financial position
or liquidity.
A second lawsuit, United States of America ex rel. Grynberg v. Cross Timbers
Oil Company, et al., was filed in the United States District Court for the
Western District of Oklahoma. This action alleges that in computing royalties
payable for natural gas produced from federal leases and lands owned by Native
Americans, the Company has mismeasured the volume of natural gas and wrongfully
analyzed its heating content. The suit, which was brought under the qui tam
provisions of the U.S. False Claims Act, seeks treble damages for the unpaid
royalties (with interest), civil penalties and an order for the Company to
cease the allegedly improper measuring practices. This lawsuit is one of more
than 75 suits filed nationwide by the same plaintiff alleging similar claims
against over 300 producers and pipeline companies. Royalties paid by the
Company for production from Underlying Properties on federal and Native
American lands during 1998 totalled approximately $2.8 million. The Company
believes that the allegations of this lawsuit are without merit. However, an
order to change measuring practices or a related settlement could adversely
affect the Trust by reducing Net Proceeds in the future by an amount that is
presently not determinable, but is not expected to be material to the Trust's
distributable income, financial position or liquidity.
5. PRO FORMA SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
Proved oil and natural gas reserves of the Trust have been estimated as of
December 31, 1998 by independent petroleum engineers. In accordance with
Statement of Financial Accounting Standards No. 69, estimates of future net
revenues from proved reserves have been prepared using year-end oil and natural
gas prices and current costs to produce and develop the proved reserves. The
standardized measure of future net cash flows from oil and natural gas reserves
is calculated based on discounting such future net cash flows at an annual rate
of 10%. Year-end posted West Texas Intermediate crude oil prices were $15.50
and $9.50 per barrel for 1997 and 1998, respectively. Year-end weighted average
spot gas prices were $2.01 per Mcf for each of 1997 and 1998. As the Trust is
not subject to taxation at the trust level, no provision is included for
federal income taxes.
Reserve quantities and revenues for the Net Profits Interests were estimated
from projections of reserves and revenues attributable to the Underlying
Properties. Since the Trust has a defined net profits interests, the Trust does
not own a specific ownership percentage of the oil and natural gas reserve or
production quantities. Accordingly, reserves and production allocated to the
Trust pertaining to its 80%
F-13
HUGOTON ROYALTY TRUST
NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)--(Continued)
net profits interest in the working interest properties have effectively been
reduced to reflect recovery of the Trust's 80% portion of applicable production
and development costs, excluding overhead and trust administrative expenses.
Because Trust reserve quantities are determined using an allocation formula,
any fluctuations in actual or assumed prices or costs will result in revisions
to the estimated reserve quantities allocated to the Net Profits Interests.
The standardized measure of future net cash flows is not intended to
represent the fair value of the Trust. Numerous uncertainties are inherent in
estimating volumes and values of proved reserves and in projecting future
production rates and timing of development expenditures. Such reserve estimates
are subject to change as additional information becomes available. The reserves
actually recovered and the timing of production may be substantially different
from the original estimates. Also, because natural gas prices are influenced by
seasonal demand, use of year-end prices, as required by the Financial
Accounting Standards Board, may not be representative in estimating future
revenues or reserve data.
Gas (Mcf) Oil (Bbls)
--------- ----------
(in thousands)
Proved Reserves
Balance, January 1, 1998................................ 279,024 2,431
Revisions ............................................ (11,541) (255)
Extensions, discoveries and other additions........... 24,177 133
Production............................................ (9,363) (116)
------- -----
Balance, December 31, 1998.............................. 282,297 2,193
======= =====
Proved Developed Reserves
January 1, 1998......................................... 249,148 2,136
======= =====
December 31, 1998....................................... 249,215 1,934
======= =====
Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Reserves at December 31, 1998
(in thousands)
Future cash inflows.......................................... $595,301
Future production taxes and transportation................... 55,686
--------
Future net cash flows........................................ 539,615
10% discount factor.......................................... 261,873
--------
Standardized measure of discounted future net cash flows..... $277,742
========
Changes in Standardized Measure of Discounted Future Net Cash
Flows from Proved Reserves
(in thousands)
Standardized measure, January 1, 1998........................ $292,749
--------
Extensions, discoveries and other additions.................. 21,742
Trust royalty income ........................................ (18,231)
Changes in prices and other.................................. (45,289)
Accretion of discount........................................ 26,771
--------
(15,007)
--------
Standardized measure, December 31, 1998...................... $277,742
========
F-14
UNDERWRITING
Cross Timbers and the underwriters named below (the "Underwriters") have
entered into an underwriting agreement with respect to the trust units being
offered. Subject to certain conditions, each Underwriter has severally agreed
to purchase the number of trust units indicated in the following table.
Goldman, Sachs & Co., Lehman Brothers Inc., Bear, Stearns & Co., Inc., Dain
Rauscher Wessels, a division of Dain Rauscher Incorporated, Donaldson, Lufkin &
Jenrette Securities Corporation and A. G. Edwards & Sons, Inc. are
representatives of the Underwriters.
Number of
Underwriter Trust Units
----------- -----------
Goldman, Sachs & Co ...........................................
Lehman Brothers Inc. ..........................................
Bear, Stearns & Co. Inc........................................
Dain Rauscher Wessels, a division of Dain Rauscher
Incorporated............................................
Donaldson, Lufkin & Jenrette Securities Corporation............
A.G. Edwards & Sons, Inc.......................................
----------
Total........................................................ 15,000,000
==========
If the Underwriters sell more trust units than the total number shown in the
table above, the Underwriters have an option to buy up to an additional
2,250,000 trust units from Cross Timbers to cover such sales. They may exercise
that option for 30 days. If any trust units are purchased pursuant to this
option, the Underwriters will severally purchase trust units in approximately
the same proportion shown in the table above.
The following table shows the per trust unit and total underwriting
discounts and commissions to be paid to the Underwriters by Cross Timbers.
These amounts are shown assuming both no exercise and full exercise of the
Underwriters' option to purchase 2,250,000 additional trust units.
Paid by Cross Timbers
-------------------------
No Exercise Full Exercise
----------- -------------
Per trust unit....................................... $ $
Total................................................ $ $
Trust units sold by the Underwriters to the public will initially be offered
at the initial public offering price shown on the cover of this prospectus. Any
trust units sold by the Underwriters to securities dealers may be sold at a
discount of up to $ per trust unit from the initial public offering price. Any
such securities dealers may resell any trust units purchased from the
Underwriters to certain other brokers or dealers at a discount of up to $ per
trust unit from the initial public offering price. If all the trust units are
not sold at the initial offering price, the representatives may change the
offering price and the other selling terms.
Cross Timbers and its executive officers have agreed with the Underwriters
not to dispose of or hedge any of their trust units or securities convertible
into or exchangeable for trust units during the period from the date of this
prospectus continuing through the date 180 days after the date of this
prospectus, except with the prior written consent of the representatives. This
agreement does not apply to any existing employee benefit plans.
Prior to the Offering, there has been no public market for the trust units.
The initial public offering price has been negotiated among Cross Timbers and
the representatives. Among the factors to be considered in determining the
initial public offering price of the trust units, in addition to prevailing
market conditions, will be estimates of distributions to trust unitholders and
overall quality of the underlying properties.
U-1
The trust units have been approved for listing on the New York Stock
Exchange under the symbol "HGT." In order to meet one of the requirements for
listing the trust units on the New York Stock Exchange, the Underwriters have
undertaken to sell lots of 100 or more trust units to a minimum of 2,000
beneficial holders.
In connection with the Offering, the Underwriters may purchase and sell
trust units in the open market. These transactions may include short sales,
stabilizing transactions and purchases to cover positions created by short
sales. Short sales involve the sale by the Underwriters of a greater number of
trust units than they are required to purchase in the Offering. Stabilizing
transactions consist of certain bids or purchases made for the purpose of
preventing or retarding a decline in the market price of the trust units while
the Offering is in progress.
The Underwriters also may impose a penalty bid. This occurs when a
particular Underwriter repays to the Underwriters a portion of the underwriting
discount it received because the representatives repurchased trust units sold
by or for the account of such Underwriter in stabilizing or short covering
transactions.
These activities by the Underwriters may stabilize, maintain or otherwise
affect the marketprice of the trust units. As a result, the price of the trust
units may be higher than the price that otherwise might exist in the open
market. If these activities are commenced, they may be discontinued by the
Underwriters at any time. These transactions may be effected on the New York
Stock Exchange, in the over-the-counter market or otherwise.
The Underwriters do not expect sales to discretionary accounts to exceed
five percent of the total number of trust units offered.
Cross Timbers estimates that total expenses of the Offering, other than
underwriting discounts and commissions, will be approximately $650,000.
Cross Timbers and the trust have agreed to indemnify the several
Underwriters against certain liabilities, including liabilities under the
Securities Act of 1933. The trust's indemnity obligations are limited to the
assets of the trust, and neither the trustee nor any unitholder will have any
obligation to indemnify the Underwriters.
U-2
EXHIBIT A
[LETTERHEAD OF MILLER & LENTS, LTD. APPEARS HERE]
January 20, 1999
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, TX 76102
Re: Underlying Properties (100%)
Relating to the Hugoton Royalty Trust
As of January 1, 1999
SEC Pricing Case
Gentlemen:
At your request, we estimated the proved reserves and future net revenue as of
January 1, 1999, attributable to the Cross Timbers Oil Company interest in
certain oil and gas properties prior to inclusion in the Hugoton Royalty Trust,
i.e., Underlying Properties (100%). The properties consist of approximately
1,679 wells and are located primarily in Kansas, Oklahoma, and Wyoming. The
aggregate results of our evaluations are as follows:
- -----------------------------------------------------------------------------------------------------------
Net Reserves as of 1/1/99 Future Net Revenue
-----------------------------------------------------------------------
Oil and
Condensate, Gas, Undiscounted, Discounted at
Reserves Category MBbls. MMcf M$ 10% Per Year, M$
- -----------------------------------------------------------------------------------------------------------
Kansas
- -----------------------------------------------------------------------------------------------------------
Proved Developed Producing 50.6 46,123.6 45,306.6 24,767.3
- -----------------------------------------------------------------------------------------------------------
Proved Nonproducing 0.0 499.1 344.5 176.3
- -----------------------------------------------------------------------------------------------------------
Proved Undeveloped 0.0 3,996.2 1,698.7 510.6
- -----------------------------------------------------------------------------------------------------------
Subtotal 50.6 50,618.9 47,349.7 25,454.1
- -----------------------------------------------------------------------------------------------------------
Oklahoma
- -----------------------------------------------------------------------------------------------------------
Proved Developed Producing 2,901.2 235,076.2 328,413.8 192,126.8
- -----------------------------------------------------------------------------------------------------------
Proved Nonproducing 206.9 14,281.9 20,685.8 12,219.8
- -----------------------------------------------------------------------------------------------------------
Proved Undeveloped 601.3 36,125.9 35,171.7 13,182.5
- -----------------------------------------------------------------------------------------------------------
Subtotal 3,709.3 285,484.0 384,271.3 217,529.1
- -----------------------------------------------------------------------------------------------------------
Wyoming
- -----------------------------------------------------------------------------------------------------------
Proved Developed Producing 189.2 132,662.1 186,849.2 88,540.8
- -----------------------------------------------------------------------------------------------------------
Proved Nonproducing 20.6 6,685.6 10,812.6 5,173.7
- -----------------------------------------------------------------------------------------------------------
Proved Undeveloped 60.3 39,622.6 45,235.3 10,479.0
- -----------------------------------------------------------------------------------------------------------
Subtotal 270.1 178,970.3 242,897.1 104,193.5
- -----------------------------------------------------------------------------------------------------------
Total Underlying Properties (100%)
- -----------------------------------------------------------------------------------------------------------
Proved Developed Producing 3,140.9 413,861.8 560,569.6 305,434.9
- -----------------------------------------------------------------------------------------------------------
Proved Nonproducing 227.5 21,466.6 31,842.8 17,569.7
- -----------------------------------------------------------------------------------------------------------
Proved Undeveloped 661.5 79,744.7 82,105.7 24,172.1
- -----------------------------------------------------------------------------------------------------------
TOTAL 4,029.9 515,073.1 674,518.1 347,176.7
- -----------------------------------------------------------------------------------------------------------
MILLER AND LENTS, LTD.
Cross Timbers Oil Company January 20, 1999
Page 2
We performed evaluations, which are designated as the SEC Pricing Case,
using price, expense, and gas production curtailment premises specified by you
and described in detail on Attachment 1.
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 state and reserve
category. 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 the individual properties. Projections of individual property
future production and net revenue are included in separate volumes to this
report. These exhibits and volumes should not be relied upon independently of
this narrative.
The proved developed producing reserves and production forecasts were
estimated by production decline extrapolations, water-oil ratio trends, P/Z
declines, or in a few cases, by volumetric calculations. For some properties
with insufficient performance history to establish trends, we estimated future
production by analogy with other properties with similar characteristics. The
past performance trends of many properties were influenced by production
curtailments, workovers, waterfloods, and/or infill drilling. Actual future
production may require that our estimated trends be significantly altered.
The estimated proved undeveloped reserves require significant capital
expenditures such as drilling and completion costs. The proved undeveloped
reserve estimates for infill wells are based on analogies to similar infill
wells in the same field and/or the production histories of offset wells in the
same field.
Reserve estimates from volumetric calculations and from analogies are often
less certain than reserve estimates based on well performance obtained over a
period during which a substantial portion of the reserves was produced.
With the exception of a few properties, the data employed in our
determinations of proved reserves and future net income were provided by Cross
Timbers Oil Company. We obtained pressure and production information from
independent sources for some properties that had insufficient data from Cross
Timbers Oil Company to employ as bases for reserve estimates. The current
expenses for each lease were obtained from operating statements provided by
Cross Timbers Oil Company except for certain leases where Cross Timbers Oil
Company deducted items considered by Cross Timbers Oil Company to be
nonrecurring expenditures. No overhead was included for those properties
operated by Cross Timbers Oil Company. For some properties, such as large
waterfloods, Cross Timbers Oil Company assumed a decline in variable operating
costs due to depleting production which was derived by forecasting a decrease in
the property well count. None of the data provided to us by Cross Timbers Oil
Company,
MILLER AND LENTS, LTD.
Cross Timbers Oil Company January 20, 1999
Page 3
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/ Karen F. Loving
-------------------------------
Karen F. Loving
Vice President
KFL/hsd
Attachment 1
1-1-99
Underlying Properties (100%)
Relating to the
Hugoton Royalty Trust
SEC PRICING CASE
A. Oil Price All oil/condensate prices held constant at $9.50 per
barrel through the life of the property. (Adjust for
gravity, transportation charges, and crude marketing
arrangements.)
B. Gas Price Estimated 1/1/99 price held constant through the life
of the property.
C. Operating Costs Current expenses held constant through the life of the
property.
D. Curtailment For curtailed gas wells, curtailed rates were based on
the first six months of 1998 rate as a percent of 1998
capacity, then relieved over a two-year period, i.e.,
100% at 1/1/01.
E. Discount Rate 10% per year.
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.
EXHIBIT B
[LETTERHEAD OF MILLER & LENTS, LTD. APPEARS HERE]
January 20, 1999
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, TX 76102
Re: Hugoton Royalty Trust
80% Net Profits Interests
As of January 1, 1999
SEC Pricing Case
Gentlemen:
At your request, we estimated the proved reserves and future net revenue as of
January 1, 1999, attributable to the Hugoton Royalty Trust interest in certain
oil and gas properties that consist of approximately 1,679 wells located
primarily in Kansas, Oklahoma, and Wyoming. The aggregate results of our
evaluations are as follows:
Net Reserves as of 1/1/99 Future Net Revenue
------------------------------------------------------------------------
Oil and
Condensate, Gas, Undiscounted, Discounted at
Reserves Category MBbls. MMcf M$ 10% Per Year, M$
- -------------------------------------------------------------------------------------------------------
Kansas
- -------------------------------------------------------------------------------------------------------
Proved Developed Producing 28.4 25,987.1 36,245.2 19,813.8
- -------------------------------------------------------------------------------------------------------
Proved Nonproducing 0.0 240.4 275.6 141.0
- -------------------------------------------------------------------------------------------------------
Proved Undeveloped 0.0 1,141.6 1,359.0 408.5
- -------------------------------------------------------------------------------------------------------
Subtotal 28.4 27,369.1 37,879.8 20,363.3
- -------------------------------------------------------------------------------------------------------
Oklahoma
- -------------------------------------------------------------------------------------------------------
Proved Developed Producing 1,667.2 135,345.9 262,731.0 153,701.5
- -------------------------------------------------------------------------------------------------------
Proved Nonproducing 117.9 8,140.8 16,548.6 9,775.8
- -------------------------------------------------------------------------------------------------------
Proved Undeveloped 231.7 13,898.2 28,137.4 10,546.0
- -------------------------------------------------------------------------------------------------------
Subtotal 2,016.8 157,384.9 307,417.0 174,023.3
- -------------------------------------------------------------------------------------------------------
Wyoming
- -------------------------------------------------------------------------------------------------------
Proved Developed Producing 107.4 75,219.7 149,479.4 70,832.7
- -------------------------------------------------------------------------------------------------------
Proved Nonproducing 13.2 4,280.7 8,650.1 4,139.0
- -------------------------------------------------------------------------------------------------------
Proved Undeveloped 27.5 18,042.9 36,188.2 8,383.2
- -------------------------------------------------------------------------------------------------------
Subtotal 148.1 97,543.3 194,317.7 83,354.9
- -------------------------------------------------------------------------------------------------------
Total Hugoton Royalty Trust
- -------------------------------------------------------------------------------------------------------
Proved Developed Producing 1,803.0 236,552.7 448,455.6 244,348.0
- -------------------------------------------------------------------------------------------------------
Proved Nonproducing 131.1 12,661.9 25,474.3 14,055.8
- -------------------------------------------------------------------------------------------------------
Proved Undeveloped 259.2 33,082.7 65,684.6 19,337.7
- -------------------------------------------------------------------------------------------------------
TOTAL 2,193.3 282,297.3 539,614.5 277,741.5
- -------------------------------------------------------------------------------------------------------
MILLER AND LENTS, LTD.
Cross Timbers Oil Company January 20, 1999
Page 2
We performed evaluations, which are designated as the SEC Pricing Case,
using price, expense, and gas production curtailment premises specified by you
and described in detail on Attachment 1.
The Hugoton Royalty Trust interests evaluated herein are comprised of an 80
percent net overriding royalty interest of certain Cross Timbers Oil Company
properties. At your instruction, the net oil and condensate reserves and the
net natural gas reserves attributable to the Hugoton Royalty Trust interests
were computed from 80 percent of the Cross Timbers Oil Company interests in
those properties after adjustment for the estimated reserves attributable to the
future operating expenses and capital costs. As a result of this procedure, a
change in the future costs, or prices, or capital expenditures different from
those projected herein may result in a change in the computed reserves to the
net interests even if there are no revisions or additions to the gross reserves
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.
Following Attachment 2 is a list of exhibits which include annual
projections of future production and net revenue for each state and reserve
category. Also included in the exhibits are one-line summaries for the total
royalty trust and for each state showing the proved reserves and future net
revenue for the individual properties. Projections of individual property
future production and net revenue are included in separate volumes to this
report. These exhibits and volumes should not be relied upon independently of
this narrative.
The proved developed producing reserves and production forecasts were
estimated by production decline extrapolations, water-oil ratio trends, P/Z
declines, or in a few cases, by volumetric calculations. For some properties
with insufficient performance history to establish trends, we estimated future
production by analogy with other properties with similar characteristics. The
past performance trends of many properties were influenced by production
curtailments, workovers, waterfloods, and/or infill drilling. Actual future
production may require that our estimated trends be significantly altered.
The estimated proved undeveloped reserves require significant capital
expenditures such as drilling and completion costs. The proved undeveloped
reserve estimates for infill wells are based on analogies to similar infill
wells in the same field and/or the production histories of offset wells in the
same field.
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.
MILLER AND LENTS, LTD.
Cross Timbers Oil Company January 20, 1999
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/ Karen F. Loving
----------------------------
Karen F. Loving
Vice President
KFL/hsd
Attachment 1
1-1-99
Hugoton Royalty Trust
80% Net Profits Interests
SEC PRICING CASE
A. Oil Price All oil/condensate prices held constant at $9.50 per
barrel through the life of the property. (Adjust for
gravity, transportation charges, and crude marketing
arrangements.)
B. Gas Price Estimated 1/1/99 price held constant through the life
of the property.
C. Operating Costs Current expenses held constant through the life of the
property.
D. Curtailment For curtailed gas wells, curtailed rates were based on
the first six months of 1998 rate as a percent of 1998
capacity, then relieved over a two-year period, i.e.,
100% at 1/1/01.
E. Discount Rate 10% per year.
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.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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
Page
----
Prospectus Summary......................................................... 3
Risk Factors............................................................... 10
Forward Looking Statements................................................. 15
Use of Proceeds............................................................ 15
Cross Timbers.............................................................. 15
The Trust.................................................................. 15
Hypothetical Annual Cash Distributions..................................... 16
The Net Profits Interests and the Underlying Properties.................... 20
Computation of Net Proceeds................................................ 33
Federal Income Tax Consequences............................................ 36
State Tax Considerations................................................... 41
ERISA Considerations....................................................... 42
Description of the Trust Indenture......................................... 43
Description of the Trust Units............................................. 46
Selling Trust Unitholder................................................... 49
Legal Matters.............................................................. 49
Experts.................................................................... 49
Available Information...................................................... 50
Glossary of Certain Oil and Natural Gas Terms.............................. 51
Index to Financial Statements.............................................. F-1
Underwriting............................................................... U-1
---------------
Through and including , 1999 (the 25th day after the date of this
prospectus), all dealers effecting transactions in these securities, whether or
not participating in this offering, may be required to deliver a prospectus.
This is in addition to a dealer's obligation to deliver a prospectus when
acting as an underwriter and with respect to an unsold allotment or
subscription.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
15,000,000 Trust Units
Hugoton Royalty Trust
---------------
PROSPECTUS
---------------
Goldman, Sachs & Co.
Lehman Brothers
Bear, Stearns & Co. Inc.
Dain Rauscher Wessels
a division of Dain Rauscher Incorporated
Donaldson, Lufkin & Jenrette
A.G. Edwards & Sons, Inc.
Representatives of the Underwriters
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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 14. 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 the Company in
connection with the offer and sale of the securities offered hereby:
Registration Fee................................................... $ 47,955
NASD Filing Fee.................................................... 17,750
Printing and Engraving Expenses.................................... 200,000
Legal Fees and Expenses............................................ 175,000
Accountants' Fees and Expenses..................................... 60,000
Miscellaneous Fees and Expenses.................................... 149,295
--------
Total.............................................................. $650,000
========
Item 15. Indemnification of Directors and Officers.
Section 6.02 of the Trust Indenture provides that the trustee will be
indemnified by the trust estate or, if Trust assets are insufficient, by Cross
Timbers Oil Company, a Delaware corporation (the "Company"), against any and
all liability and expenses incurred by it individually or as Trustee in the
administration of the trust and the trust estate, except for any liability or
expense resulting from fraud or gross negligence or acts or omissions in bad
faith.
The Company is incorporated in Delaware. Under Section 145 of the Delaware
General Corporation Law (the "DGCL"), a Delaware corporation has the power,
under specified circumstances, to indemnify its directors, officers, employees
and agents in connection with actions, suits or proceedings brought against
them by a third party or in the right of the corporation, by reason that they
were or are such directors, officers, employees or agents, against expenses and
liabilities incurred in any such action, suit or proceeding so long as they
acted in good faith and in a manner that they reasonably believed to be in, or
not opposed to, the best interests of such corporation, and with respect to any
criminal action, that they had no reasonable cause to believe their conduct was
unlawful. With respect to suits by or in the right of such corporation,
however, indemnification is generally limited to attorneys' fees and other
expenses and is not available if such person is adjudged to be liable to such
corporation unless the court determines that indemnification is appropriate. A
Delaware corporation also has the power to purchase and maintain insurance for
such persons. Article Nine of the Certificate of Incorporation of the Company
permits indemnification of directors and officers to the fullest extent
permitted by Section 145 of the DGCL. Reference is made to the Certificate of
Incorporation of the Company.
Section 102(b)(7) of the DGCL provides that a certificate of incorporation
may contain a provision eliminating or limiting the personal liability of a
director to the corporation or its stockholders for monetary damages for breach
of fiduciary duty as a director, provided that such provisions may not
eliminate or limit the liability of a director (i) for any breach of the
director's duty of loyalty to the corporation or its stockholders, (ii) for
acts or omissions not in good faith or which involve intentional misconduct or
a knowing violation of law, (iii) under Section 174 (relating to liability for
unauthorized acquisitions or redemptions of, or dividends on, capital stock) of
the DGCL or (iv) for any transaction from which the director derived an
improper personal benefit. Article Ten of the Company's Certificate of
Incorporation contains such a provision.
II-1
The above discussion of the Company's Certificate of Incorporation and of
Sections 102(b)(7) and 145 of the DGCL is not intended to be exhaustive and is
qualified in its entirety by such Certificate of Incorporation and statutes.
Additionally, the Company has acquired directors' and officers' insurance in
the amount of $10 million.
Item 16. Exhibits.
Exhibit
Number Description
------- -----------
1.1 --Form of Underwriting Agreement.
4.1* --Hugoton Royalty Trust Indenture.
5.1 --Opinion of Kelly, Hart & Hallman, P.C. as to legality of the
securities registered hereby.
8.1 --Opinion of Butler & Binion, L.L.P. regarding federal income tax
matters.
8.2 --Opinion of Morris, Laing, Evans, Brock & Kennedy, Chartered as to
Kansas State tax matters.
10.1 --Form of 80% Net Overriding Royalty Conveyance--Kansas.
10.2 --Form of 80% Net Overriding Royalty Conveyance--Oklahoma.
10.3 --Form of 80% Net Overriding Royalty Conveyance--Wyoming.
15.1 --Awareness letter of Arthur Andersen LLP.
23.1 --Consent of Arthur Andersen LLP.
23.2 --Consent of Kelly, Hart & Hallman, P.C. (set forth in their opinion
filed as Exhibit 5.1).
23.3 --Consent of Butler & Binion, L.L.P. (set forth in their opinion filed
as Exhibit 8.1).
23.4 --Consent of Morris, Laing, Evans, Brock & Kennedy, Chartered (set
forth in their opinion filed as Exhibit 8.2).
23.5 --Consent of Miller & Lents.
24.1* --Powers of attorney (set forth on the signature page of the original
filing).
27.1 --Financial Data Schedule.
- --------
* Previously filed.
Item 17. Undertakings.
The Company hereby undertakes:
(a) that, for purposes of determining any liability under the Securities Act
of 1933, each filing of the Company's annual reports pursuant to Section 13(a)
or 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each
filing of an employee benefit plan's annual report pursuant to Section 15(d) of
the Securities Exchange Act of 1934) that is incorporated by reference in the
Registration Statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
(b) to provide to the underwriters at the closing specified in the
underwriting agreement certificates in such denominations and registered in
such names as required by the underwriters to permit prompt delivery to each
purchaser.
(c) for purposes of determining any liability under the Securities Act of
1933, the information omitted from the form of prospectus filed as part of this
registration statement in reliance upon Rule 430A and contained in a form of
prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h)
under the Securities Act shall be deemed a part of this registration statement
as of the time it was declared effective.
II-2
(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 Company has
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 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 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
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 January 25,
1999.
CROSS TIMBERS OIL COMPANY,
By /s/ J. Richard Seeds
-----------------------------------
J. Richard Seeds
Executive Vice President
HUGOTON ROYALTY TRUST
By CROSS TIMBERS OIL COMPANY, as
sponsor
By /s/ J. Richard Seeds
-------------------------------
J. Richard Seeds
Executive Vice President
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.
/s/ Bob R. Simpson* Director, Chairman of the January 25, 1999
______________________________________ Board and Chief Executive
Bob R. Simpson Officer (Principal
Executive Officer)
/s/ Steffen E. Palko* Director, Vice Chairman of January 25, 1999
______________________________________ the Board and President
Steffen E. Palko
/s/ J. Richard Seeds Director, Executive Vice January 25, 1999
______________________________________ President
J. Richard Seeds
/s/ J. Luther King, Jr.* Director January 25, 1999
______________________________________
J. Luther King, Jr.
/s/ Jack P. Randall* Director January 25, 1999
______________________________________
Jack P. Randall
/s/ Scott G. Sherman* Director January 25, 1999
______________________________________
Scott G. Sherman
/s/ Louis G. Baldwin Senior Vice President and January 25, 1999
______________________________________ Chief Financial Officer
Louis G. Baldwin (Principal Financial
Officer)
/s/ Bennie G. Kniffen Senior Vice President and January 25, 1999
______________________________________ Controller (Principal
Bennie G. Kniffen Accounting Officer)
/s/ J. Richard Seeds
*By:
------------------------------
J. Richard Seeds
Attorney-in-Fact
II-4
EXHIBIT INDEX
Exhibit
Number Description
------- -----------
1.1 --Form of Underwriting Agreement.
5.1 --Opinion of Kelly, Hart & Hallman, P.C. as to legality of the
securities registered hereby.
8.1 --Opinion of Butler & Binion, L.L.P. regarding federal income tax
matters.
8.2 --Opinion of Morris, Laing, Evans, Brock & Kennedy, Chartered as to
Kansas State tax matters.
10.1 --Form of 80% Net Overriding Royalty Conveyance--Kansas.
10.2 --Form of 80% Net Overriding Royalty Conveyance--Oklahoma.
10.3 --Form of 80% Net Overriding Royalty Conveyance--Wyoming.
15.1 --Awareness letter of Arthur Andersen LLP.
23.1 --Consent of Arthur Andersen LLP.
23.5 --Consent of Miller & Lents.
27.1 --Financial Data Schedule.