<PAGE>
As filed with the Securities and Exchange Commission on April 8, 1999.
Registration No. 333-68441
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------------
AMENDMENT NO. 3 TO
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
on
Form S-1 -------------- Form S-1
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)
1311
1311
(Primary Standard Industrial
(Primary Standard Industrial Classification Code Number)
Classification Code Number)
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)
--------------
Copies to:
F. Richard Bernasek, Esq. James M. Prince, Esq.
Kelly, Hart & Hallman, P.C. Andrews & Kurth L.L.P.
201 Main Street, Suite 2500 600 Travis, Suite 4200
Fort Worth, Texas 76102 Houston, Texas 77002
(817) 332-2500 (713) 220-4300
--------------
Approximate date of commencement of proposed sale to the public: As soon as
practicable after this Registration Statement becomes effective.
If the only securities being registered on this form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box. [_]
If any of the securities being registered on this Form are to be offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or
interest reinvestment plans, check the following box. [_]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following
box and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [_]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [_]
--------------
CALCULATION OF REGISTRATION FEE
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Title of Each Class of Proposed Maximum Amount of
Securities to Be Registered Aggregate Offering Price(1) Registration Fee(2)
- ------------------------------------------------------------------------------
<S> <C> <C>
Units of Beneficial
Interest.................... $172,500,000 $47,955
- ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
</TABLE>
(1) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457(o).
(2) Previously paid.
The Registrant hereby amends this Registration Statement on such date or
dates as may be necessary to delay its effective date until the Registrant
shall file a further amendment which specifically states that this Registration
Statement shall thereafter become effective in accordance with Section 8(a) of
the Securities Act of 1933 or until this Registration Statement shall become
effective on such date as the Commission, acting pursuant to said Section 8(a),
may determine.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
+The information in this preliminary prospectus is not complete and may be +
+changed. These securities may not be sold until the registration statement +
+filed with the Securities and Exchange Commission is effective. This +
+preliminary prospectus is not an offer to sell nor does it seek an offer to +
+buy these securities in any jurisdiction where the offer or sale is not +
+permitted. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
Subject to Completion. Dated April 8, 1999.
Hugoton Royalty Trust
15,000,000 Trust Units
-----------
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 $9.00 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 12 to read about certain information you
should consider before purchasing trust units.
-----------
Neither the Securities and Exchange Commission nor any other regulatory body
has approved or disapproved of these securities or passed upon the accuracy or
adequacy of this prospectus. Any representation to the contrary is a criminal
offense.
-----------
<TABLE>
<CAPTION>
Per
Trust
Unit Total
----- -----
<S> <C> <C>
Initial public offering price....................................... $ $
Underwriting discount............................................... $ $
Proceeds, before expenses, to Cross Timbers......................... $ $
</TABLE>
The underwriters may, under certain circumstances, purchase from Cross
Timbers up to an additional 2,250,000 trust units at the initial public
offering price less the underwriting discount.
-----------
The underwriters expect to deliver the trust units against payment in New
York, New York on , 1999.
Goldman, Sachs & Co.
Lehman Brothers
Bear, Stearns & Co. Inc.
Dain Rauscher Wessels
a division of Dain Rauscher Incorporated
Donaldson, Lufkin & Jenrette
A.G. Edwards & Sons, Inc.
-----------
Prospectus dated , 1999.
<PAGE>
[MAP OF UNDERLYING PROPERTIES APPEARS HERE]
2
<PAGE>
PROSPECTUS SUMMARY
This summary may not contain all of the information that is important to
you. To understand this offering fully, you should read the entire prospectus
carefully, including the risk factors and the financial statements and notes to
those statements. You will find definitions for terms relating to the oil and
natural gas business in "Glossary of Certain Oil and Natural Gas Terms." Miller
& Lents, Ltd., an independent engineering firm, 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 oil and
natural gas producing properties. We refer to Cross Timbers' interests in these
properties as the underlying properties.
The net profits interests entitle the trust to receive 80% of net proceeds
from the sale of oil and natural gas from the underlying properties. Each month
Cross Timbers will collect cash received from the sale of production and deduct
property and production taxes, development and production costs and overhead.
For distributions paid to trust unitholders through April 2000, net proceeds
from the sale of natural gas from the underlying properties corresponding to
those distributions will be computed differently. They will be computed on the
basis of gross proceeds calculated each month as the greater of either a
realized price of $2.00 per Mcf multiplied by the amount of natural gas
production, or the amount received by Cross Timbers from actual sales of
natural gas production.
Net proceeds payable to the trust depend upon production quantities, sales
prices of oil and natural gas and costs to develop and produce the oil and
natural gas. If at any time costs should exceed gross proceeds, neither the
trust nor the trust unitholders would be liable for the excess costs. However,
the trust would not receive any net proceeds until future net proceeds exceed
the total of those excess costs, plus interest at the prime rate.
Cross Timbers calculates the net proceeds from the underlying properties
separately for each of the states where they are located. Any excess costs for
underlying properties in one state will not reduce net proceeds calculated for
properties in another state.
Cross Timbers does not expect future production costs for the underlying
properties to change significantly as compared to recent historical costs. It
expects the level of development costs to decline significantly as compared to
recent historical amounts.
The trust will make monthly distributions of substantially all of its
income to holders of its trust units. On your federal income tax returns, you
will be required to include your proportionate share of trust 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.
3
<PAGE>
Cross Timbers' Ownership Interests in the Trust and the Underlying Properties
Cross Timbers' interests in the underlying properties are predominantly
"working interests," which require it to bear the costs of exploration,
production and development.
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. Cross Timbers may sell additional trust units in the future.
[CHART SHOWING THE RELATIONSHIP OF CROSS TIMBERS, THE TRUST AND THE PUBLIC
TRUST UNITHOLDERS 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
<PAGE>
Producing Areas
The underlying properties are predominantly natural gas producing leases
located in the States of Kansas, Oklahoma and Wyoming. These productive areas
consist of:
. 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.
. 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.
. 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.
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 12.9 years. An index of 12.9 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. 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.
5
<PAGE>
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 190 Bcfe of proved
reserves, or 155% of production, at a cost of $0.49 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. Cross
Timbers intends to reduce development expenditures for the underlying
properties to $12 million per year for the next four years, compared to an
average of $31 million per year for the last three years. Therefore, Cross
Timbers expects that reserve additions over the next four years will decline.
It believes, however, that its historical cost per Mcfe of reserves added
should be a good indicator of its ability to add reserves at low costs in the
future.
Over the last three years proved reserve additions on existing wells on the
underlying properties included upward revisions of 25.9 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
The underlying properties are Cross Timbers' undivided interests in oil and
natural gas leases and the production from existing and future wells on those
leases. 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 80% of the
related development costs, which will be deducted from net proceeds as they are
paid.
Without development projects, the underlying properties would typically
experience a 6% to 10% annual decline in production. The planned development
expenditures included in the reserve report are expected to reduce the natural
rate of decline in production to approximately 4% per year.
Additional Development Opportunities
Cross Timbers believes that the underlying properties will offer economic
development projects that are not included in existing proved reserves. These
additional development opportunities could significantly increase production
and proved reserves. Cross Timbers expects to implement these projects starting
in 2003, or sooner if natural gas prices increase or if production exceeds
projections in the reserve report.
Costs per Mcfe associated with reserves added through additional development
projects are expected to be in line with historical costs. Costs will be
deducted from the net profits interests as they are paid and will lower monthly
distributions. Production from these projects should increase subsequent
distributions.
Additional development opportunities are:
. adding pipeline compression and pumps to improve production flow;
. opening new producing zones in existing wells;
. deepening existing wells to new producing zones;
. performing mechanical and chemical treatments to stimulate production
rates; and
. drilling additional wells.
Cross Timbers believes each type of additional development opportunity will
be implemented in each of the productive areas over a period of years. Cross
Timbers expects annual development costs will continue to be approximately $12
million in 2003 and subsequent years. Actual development costs incurred,
however, will depend on results of development activities conducted through
2002, natural gas prices and expected rates of return.
6
<PAGE>
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. The following table shows Cross Timbers' operating margins for the
underlying properties during 1998.
<TABLE>
<CAPTION>
Per Mcfe
<S> <C>
Sales price....................................................... $1.92
-----
Expenses:
Production expenses............................................. 0.30
Production and property taxes and transportation costs.......... 0.22
Overhead........................................................ 0.15
-----
Total expenses................................................ 0.67
-----
Operating margin.................................................. $1.25
=====
</TABLE>
Cross Timbers, as operator of more than 90% of the underlying properties,
charges these expenses to itself and the other working interest owners. Except
for overhead, which is based on a fixed per-well charge to reimburse Cross
Timbers for indirect operating costs, these expenses are passed through at
Cross Timbers' cost.
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. Gas equivalents in the table are the sum of the MMcf of natural
gas and the MMcfe of the stated MBbls of oil, calculated on the basis that one
Bbl of oil is the energy equivalent of six Mcf of natural gas. The amounts of
estimated future net revenues from proved reserves shown in the table are
before income taxes. Discounted future net revenues are based on a discount
rate of 10%, which is the rate required by the Securities and Exchange
Commission. Reserve estimates are subject to revision.
7
<PAGE>
<TABLE>
<CAPTION>
PROVED RESERVES
---------------------------
ESTIMATED FUTURE
NET REVENUES FROM
GAS PROVED RESERVES
GAS OIL EQUIVALENTS ------------------------
(MMCF) (MBBLS) (MMCFE) UNDISCOUNTED DISCOUNTED
------- ------- ----------- ------------ -----------
(IN THOUSANDS, EXCEPT
PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
- --------
(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 future estimated costs,
before overhead and trust administrative expenses, that are deducted in
calculating net proceeds. Overhead was $6.3 million in 1998, and trust
adminstrative expenses are expected to be approximately $300,000 per year.
Accordingly, proved reserves for the net profits interests reflect
quantities that are calculated after reductions for future costs and
expenses based on price and cost assumptions used in the reserve estimates.
8
<PAGE>
HISTORICAL RESULTS FROM THE UNDERLYING PROPERTIES
The following table provides oil and natural gas sales volumes, average
sales prices, revenues, direct operating expenses, development costs and
overhead relating to the underlying properties for 1996, 1997 and 1998. See the
audited statements of revenues and direct operating expenses of the underlying
properties for the years ended December 31, 1996, 1997 and 1998 beginning on
page F-2 in this prospectus.
<TABLE>
<CAPTION>
1996 1997 1998
---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C>
Sales Volumes:
Natural gas (Mcf).................... 36,708 38,126 38,819
Oil (Bbls)........................... 450 477 490
Average Prices:
Natural gas (per Mcf)................ $ 1.84 $ 2.20 $ 1.89
Oil (per Bbl)........................ $ 21.20 $ 19.60 $ 13.25
Revenues:
Gas sales............................ $ 67,530 $ 84,024 $ 73,559
Oil sales............................ 9,544 9,360 6,496
---------- ---------- ----------
Total.............................. 77,074 93,384 80,055
---------- ---------- ----------
Direct Operating Expenses:
Production and property taxes and
transportation...................... 6,697 9,557 9,069
Production expenses.................. 12,650 12,989 12,767
---------- ---------- ----------
Total.............................. 19,347 22,546 21,836
---------- ---------- ----------
Excess of Revenues over Direct
Operating Expenses................... $57,727 $70,838 $58,219
========== ========== ==========
Development costs..................... $21,497 $41,078 $30,497
========== ========== ==========
Overhead.............................. $ 4,665 $ 5,278 $ 6,312
========== ========== ==========
</TABLE>
9
<PAGE>
1999 PROJECTED DISTRIBUTABLE INCOME
The following table provides projected oil and natural gas sales volumes per
the reserve report, assumed sales prices, and calculation of trust
distributable income for 1999 after deducting estimated costs. The calculations
assume realized prices of $2.00 per Mcf of natural gas and $11.75 per Bbl of
oil, which equates to a $10.00 posted price. The projections were prepared by
Cross Timbers as its best estimate of 1999 distributable income, on an accrual
or production basis, based on these pricing assumptions and other assumptions
that are described in "Projected Cash Distributions--Significant Assumptions
Used to Prepare the 1999 Projected Distributable Income." Because the
projections are prepared on an accrual or production basis for calendar year
1999, the projections represent an estimate of cash distributable income for
March 1999 through February 2000. The projections and the assumptions on which
they are based are subject to significant uncertainties, many of which are
beyond the control of Cross Timbers or the trust. ACTUAL 1999 DISTRIBUTABLE
INCOME, THEREFORE, COULD VARY SIGNIFICANTLY BASED UPON CHANGES IN ANY OF THESE
ASSUMPTIONS. Distributable income is particularly sensitive to oil and natural
gas prices. See "Projected Cash Distributions--Sensitivity of 1999 Projected
Cash Distributions to Oil and Natural Gas Prices" which shows estimated effects
to distributable income from changes in oil and natural gas prices. As a result
of typical production declines for oil and natural gas properties, production
estimates generally decrease from year to year. In addition, the provision for
computing net proceeds that provides for effective minimum realized natural gas
prices of $2.00 per Mcf will not apply to distributions paid after April 2000.
See "Computation of Net Proceeds--Net Profits Interests." ACCORDINGLY, THE
PROJECTED 1999 CASH DISTRIBUTIONS ARE NOT NECESSARILY INDICATIVE 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. See "Risk Factors--Trust Assets Are Depleting
Assets."
<TABLE>
<CAPTION>
(IN THOUSANDS,
EXCEPT PER UNIT DATA)
<S> <C> <C>
Underlying Properties
Sales Volumes:
Natural gas (Mcf).............. 41,027
Oil (Bbls)..................... 434
Assumed Sales Price:
Natural gas (per Mcf).......... $ 2.00
Oil (per Bbl).................. $ 11.75
Calculation of Distributable
Income
Revenues:
Natural gas sales.............. $82,054
Oil sales...................... 5,100
-------
Total........................ 87,154
-------
Costs:
Production and property taxes
and transportation............ 9,310
Production expenses............ 11,917
Development costs.............. 12,000
Overhead....................... 6,300
-------
Total........................ 39,527
-------
Net proceeds..................... 47,627
Net profits percentage........... 80%
-------
Trust royalty income............. 38,102
Trust administrative expense..... 300
-------
Trust distributable income....... $37,802
=======
<CAPTION>
CASH DISTRIBUTION
AS A PERCENTAGE OF
AMOUNT $9.50 TRUST UNIT PRICE
------ ----------------------
<S> <C> <C>
Per Trust Unit (40,000,000 Trust
Units):
Total cash distributions......... $ 0.95 10.0%
Cost depletion tax deduction..... (0.78)
-------
Taxable income................... 0.17
Income tax rate.................. 39.6%
-------
Income tax expense............... 0.07
Section 29 tax credit............ (0.02)
-------
Net tax.......................... 0.05
-------
Total cash distributions after
tax............................. $ 0.90 9.5%
=======
</TABLE>
10
<PAGE>
THE OFFERING
Trust units offered by Cross 15,000,000
Timbers........................
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 are owed a fiduciary duty by the trustee, but not by
Cross Timbers;
. 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.
11
<PAGE>
RISK FACTORS
TRUST DISTRIBUTIONS WILL BE SENSITIVE TO CHANGING OIL AND NATURAL GAS PRICES
The trust's monthly cash distributions are highly dependent upon the prices
realized from the sale of oil and, 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;
. the price and availability of alternative fuels;
. the proximity to, and capacity of, transportation facilities; and
. worldwide energy conservation measures.
Moreover, government regulations, such as regulation of natural gas
transportation and price controls, can affect product prices in the long term.
Lower oil and natural gas prices may reduce the amount of oil and natural
gas that is economic to produce and 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 Underlying Properties--
Historical Results from the Underlying Properties."
If development and production costs of underlying properties located in a
particular state exceed the proceeds of production from the properties, the
trust will not receive net proceeds for those properties until future proceeds
from production in that state exceed the total of the excess costs plus accrued
interest during the deficit period. Development activities may not generate
sufficient additional revenue to repay the costs.
TRUST RESERVE ESTIMATES ARE UNCERTAIN
The value of the trust units will depend upon, among other things, the
reserves attributable to the trust's net profits interests. Estimating reserves
is inherently uncertain. Ultimately, actual production, revenues and
expenditures for the underlying properties will vary from estimates and those
variations could be material. Petroleum engineers consider many factors and
make assumptions in estimating reserves. Those factors and assumptions include:
. historical production from the area compared with production rates from
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.
12
<PAGE>
Changes in these assumptions can materially change reserve estimates.
The trust's reserve quantities and revenues are based on estimates of
reserves and revenues for the underlying properties. The method of allocating a
portion of those reserves to the trust is complicated because the trust holds
an interest in net profits and does not own a specific percentage of the oil
and natural gas reserves. See "The Underlying Properties--Oil and Natural Gas
Reserves" for a discussion of the method of allocating proved reserves to the
trust.
PRODUCTION RISKS CAN ADVERSELY AFFECT TRUST DISTRIBUTIONS
The occurrence of drilling, production or transportation accidents at any of
the underlying properties will reduce trust distributions by the amount of
uninsured costs. These accidents may result in personal injuries, property
damage, damage to productive formations or equipment and environmental damages.
Any uninsured costs would be deducted as a production cost in calculating net
proceeds payable to the trust.
THE TRUST DOES NOT CONTROL OPERATIONS AND DEVELOPMENT
Neither the trustee nor the trust unitholders can influence or control the
operation or future development of the underlying properties. Cross Timbers is
unable to significantly influence the operations or future development of the
underlying properties that it does not operate, 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 has been advised by the Staff of the SEC
that the Staff believes that a transferee of the underlying properties, by
virtue of the transfer, would be obligated to file reports under the Securities
Exchange Act of 1934.
Cross Timbers or any transferee may abandon any well or property if it
reasonably believes that the well or property can no longer produce in
commercially economic quantities. This could result in termination of the net
profits interest relating to the abandoned well.
NET PROFITS INTERESTS CAN BE SOLD OR THE TRUST MAY BE TERMINATED
The trustee must sell the net profits interests if the holders of 80% or
more of the trust units approve the sale or vote to 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.
13
<PAGE>
Cross Timbers' Disposal of Its Remaining Trust Units May Temporarily Reduce the
Trust Unit Market Price
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. Although Cross Timbers expects these additional trust units
will increase market liquidity, the sale of additional trust units may also
temporarily reduce the market price of the trust units. See "Selling Trust
Unitholder."
Cross Timbers May Enter Into Contracts that Are Not Negotiated in Arm's-Length
Transactions
Cross Timbers and some of its affiliates receive payments under existing
contracts for services relating to the underlying properties. 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:
. reimbursements to Cross Timbers for production and development costs to
operate wells;
. payments to Cross Timbers' affiliates for marketing, processing and
transportation services, from which Cross Timbers expects to net
approximately $875,000 in 1999; and
. overhead fees to operate the underlying properties, including
engineering, accounting and administrative functions, which Cross
Timbers expects will be approximately $6.3 million in 1999.
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 marketing, processing and transportation 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 marketing, processing or
transportation 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.
14
<PAGE>
CROSS TIMBERS MAY HAVE INTERESTS THAT ARE DIFFERENT FROM YOURS
Because Cross Timbers has interests in oil and natural gas properties not
included in the trust, Cross Timbers may have interests that are different from
yours. For example,
. in setting budgets for development and production expenditures for Cross
Timbers' properties, including the underlying properties, Cross Timbers
may make decisions that could adversely affect future production from
the underlying properties; these decisions could include reducing
development expenditures on underlying properties, which could cause oil
and natural gas production to decline at a faster rate and result in
lower future trust distributions;
. Cross Timbers could continue to operate an underlying property and
continue to earn an overhead fee even though abandonment of the property
might result in more net profits being available to trust unitholders;
and
. Cross Timbers could decide to sell or abandon some or all of the
underlying properties, and that decision may not be in the best
interests of the trust unitholders; for example, Cross Timbers might
sell some or all of the underlying properties to a third party who could
reduce development expenditures on those properties, or Cross Timbers
might abandon a marginal well that otherwise would continue to produce a
net profit to the trust.
Cross Timbers, however, will be liable to the trust for decisions it makes
regarding the underlying properties if it acts in bad faith.
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 and related trust law permit the trustee and the trust
to sue Cross Timbers or any other future owner of the underlying properties to
honor the net profits interests. If the trustee does not take appropriate
action to enforce provisions of the net profits interests, your recourse as a
trust unitholder would likely be limited to bringing a lawsuit against the
trustee to compel the trustee to take specified actions. You probably would not
be able to sue Cross Timbers or any future owner of the underlying properties.
LIMITED LIABILITY OF TRUST UNITHOLDERS IS UNCERTAIN
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.
15
<PAGE>
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.
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 $0.78 per
trust unit in 1999, based on a trust unit purchase price of $9.50. See "Federal
Income Tax Consequences--Royalty Income and Depletion."
CROSS TIMBERS IS A DEFENDANT IN LITIGATION REGARDING ROYALTIES
Cross Timbers is a defendant in a class action lawsuit alleging underpayment
of royalties due to royalty owners. The plaintiffs allege that underpayments
resulted from improper charges for production, marketing, gathering, processing
and transportation costs and through the sales of natural gas to affiliated
companies at less favorable prices than those paid by third parties. If Cross
Timbers is required to pay increased amounts for past royalties, future
payments to the trust would be reduced by the trust's proportionate share of
these amounts attributable to production after December 1, 1998. See the
description of the Booth litigation in "The Underlying Properties--Litigation."
Cross Timbers is also a defendant in a lawsuit that alleges that Cross
Timbers has underpaid royalties by mismeasuring the natural gas produced from
federal leases and lands owned by Native Americans. If Cross Timbers is found
liable, it could be subject to substantial damages and penalties. In that case
future payments to the trust would be reduced by the trust's proportionate
share of the damages attributable to production after December 1, 1998. See the
description of the U.S.A. ex rel Grynberg litigation in "The Underlying
Properties--Litigation."
AN IRS RULING WILL NOT BE REQUESTED
The trust has received an opinion of tax counsel that the trust is a
"grantor trust" for federal income tax purposes. This means that:
. you will be taxed directly on your pro rata share of the net income of
the trust, regardless of whether all of that net income is distributed
to you;
. you will be allowed depletion deductions equal to the greater of
percentage depletion or cost depletion, computed on the tax basis of
your trust units, and your pro rata share of other deductions of the
trust; and
. you will be allowed the tax credit 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.
16
<PAGE>
See "Federal Income Tax Consequences."
Tax counsel believes that its opinion is in accordance with the present
position of 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."
FORWARD-LOOKING STATEMENTS
Some statements made by Cross Timbers in this prospectus under "Projected
Cash Distributions," statements pertaining to future development activities and
costs, and other statements contained in this prospectus are prospective and
constitute forward-looking statements. These forward-looking statements involve
known and unknown risks, uncertainties and other factors that could cause
actual results to differ materially from future results expressed or implied by
the forward-looking statements. The most significant risks, uncertainties and
other factors are discussed under "Risk Factors" above.
USE OF PROCEEDS
The trust will not receive any proceeds from the sale of the trust units.
Cross Timbers will receive all proceeds from the sale of trust units after
deducting underwriting discounts and costs of the offering paid by Cross
Timbers. The estimated net proceeds will be approximately $131.9 million,
assuming an offering price of $9.50 per trust unit, and will increase to $151.8
million 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.
Management of Cross Timbers has been involved in the formation of three
publicly traded royalty trusts. The trusts are the Cross Timbers Royalty Trust
formed in 1992 and the Permian Basin Royalty Trust and the San Juan Basin
Royalty Trust formed in 1980. Cross Timbers may form additional royalty trusts
with other properties. It may in the future dispose of some or all of the trust
17
<PAGE>
units of the Hugoton Royalty Trust or any of the other royalty trusts. See
"Risk Factors--Cross Timbers' Disposal of Its Remaining Trust Units May
Temporarily Reduce the Trust Unit Market Price."
For additional information regarding Cross Timbers, see "Information About
Cross Timbers Oil Company" beginning on page CT-1.
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.
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.
PROJECTED CASH DISTRIBUTIONS
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. For a
more detailed description of net proceeds, see "Computation of Net Proceeds."
The amount of trust revenues and cash distributions to trust unitholders
will depend on:
. natural gas prices;
. oil prices to a lesser extent;
. the volume of oil and natural gas produced and sold; and
. production, development and other costs.
18
<PAGE>
1999 PROJECTED DISTRIBUTABLE INCOME
The following table provides projected oil and natural gas sales volumes per
the reserve report, assumed sales prices, and calculation of trust
distributable income for 1999 after deducting estimated costs. The calculations
assume realized prices of $2.00 per Mcf of natural gas and $11.75 per Bbl of
oil, which equates to a $10.00 posted price. The projections were prepared by
Cross Timbers as its best estimate of 1999 distributable income, on an accrual
or production basis, based on these pricing assumptions and other assumptions
that are described in "--Significant Assumptions Used to Prepare the 1999
Projected Distributable Income." Because the projections are prepared on an
accrual or production basis for calendar year 1999, the projections represent
an estimate of cash distributable income for March 1999 through February 2000.
The projections and the assumptions on which they are based are subject to
significant uncertainties, many of which are beyond the control of Cross
Timbers or the trust. ACTUAL 1999 DISTRIBUTABLE INCOME, THEREFORE, COULD VARY
SIGNIFICANTLY BASED UPON CHANGES IN ANY OF THESE ASSUMPTIONS. Distributable
income is particularly sensitive to oil and natural gas prices. See "--
Sensitivity of 1999 Projected Cash Distributions to Oil and Natural Gas Prices"
which shows estimated effects to distributable income from changes in oil and
natural gas prices. As a result of typical production declines for oil and
natural gas properties, production estimates generally decrease from year to
year. In addition, the provision for computing net proceeds that provides for
effective minimum realized natural gas prices of $2.00 per Mcf will not apply
to distributions paid after April 2000. See "Computation of Net Proceeds--Net
Profits Interests." ACCORDINGLY, THE PROJECTED 1999 CASH DISTRIBUTIONS ARE NOT
NECESSARILY INDICATIVE 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. See "Risk Factors--Trust
Assets Are Depleting Assets."
<TABLE>
<CAPTION>
(IN THOUSANDS,
EXCEPT PER
UNIT DATA)
<S> <C> <C>
Underlying Properties
Sales Volumes:
Natural gas (Mcf)..................... 41,027
Oil (Bbls)............................ 434
Assumed Sales Price:
Natural gas (per Mcf)................. $ 2.00
Oil (per Bbl)......................... $ 11.75
Calculation of Distributable Income
Revenues:
Natural gas sales..................... $82,054
Oil sales............................. 5,100
-------
Total............................... 87,154
-------
Costs:
Production and property taxes and
transportation....................... 9,310
Production expenses................... 11,917
Development costs..................... 12,000
Overhead.............................. 6,300
-------
Total............................... 39,527
-------
Net proceeds............................ 47,627
Net profits percentage.................. 80%
-------
Trust royalty income.................... 38,102
Trust administrative expense............ 300
-------
Trust distributable income.............. $37,802
=======
<CAPTION>
CASH DISTRIBUTION
AS A PERCENTAGE OF
AMOUNT $9.50 TRUST UNIT PRICE
------ ----------------------
<S> <C> <C>
Per Trust Unit (40,000,000 Trust Units):
Total cash distributions............... $ 0.95 10.0%
Cost depletion tax deduction........... (0.78)
-------
Taxable income......................... 0.17
Income tax rate........................ 39.6%
-------
Income tax expense..................... 0.07
Section 29 tax credit.................. (0.02)
-------
Net tax................................ 0.05
-------
Total cash distributions after tax..... $ 0.90 9.5%
=======
</TABLE>
19
<PAGE>
SENSITIVITY OF 1999 PROJECTED CASH DISTRIBUTIONS TO OIL AND NATURAL GAS PRICES
Cross Timbers prepared the following unaudited tables, which demonstrate the
estimated effect that changes in the prices for oil and natural gas could have
on trust distributions. The following tables show:
. the projected cash distributions per trust unit for calendar year 1999
on the accrual or production basis;
. the resulting projected cash distributions per trust unit as a
percentage of the purchase price of the trust unit; and
. the resulting projected cash distributions per trust unit as a
percentage of the purchase price of the trust unit, after payment of all
federal income tax, net of available deductions and credits, at the
highest individual tax rate of 39.6%.
For distributions paid to trust unitholders through April 2000, the
computation of net proceeds provides for effective minimum wellhead natural gas
prices of $2.00 per Mcf. See "Computation of Net Proceeds--Net Profits
Interests." The tables show the effect of natural gas prices below $2.00 as if
that provision for computing net proceeds were not in effect.
THE TABLES ARE NOT A PROJECTION OR FORECAST OF THE ACTUAL OR ESTIMATED
RESULTS FROM AN INVESTMENT IN THE TRUST UNITS. THE PURPOSE OF THE TABLES IS TO
ILLUSTRATE THE SENSITIVITY OF CASH DISTRIBUTIONS AND CASH DISTRIBUTIONS AS A
PERCENTAGE OF TRUST UNIT PURCHASE PRICE TO CHANGES IN THE PRICES OF OIL AND
NATURAL GAS. THERE IS NO ASSURANCE THAT THE ASSUMPTIONS DESCRIBED BELOW WILL
ACTUALLY OCCUR OR THAT THE PRICES OF OIL OR NATURAL GAS WILL NOT CHANGE BY
AMOUNTS DIFFERENT FROM THOSE SHOWN IN THE TABLES.
Due to the seasonal demand for natural gas, the amount of monthly cash
distributions from the trust is expected to vary during the year. Month-to-
month distributions will also vary based on the timing of development
expenditures and the net proceeds, if any, generated by development projects.
SENSITIVITY OF PROJECTED TOTAL 1999 CASH DISTRIBUTIONS PER TRUST UNIT
<TABLE>
<CAPTION>
POSTED OIL PRICE WELLHEAD GAS PRICE
PER BBL PER MCF
---------------- --------------------------
$1.50 $2.00 $2.50 $3.00
----- ----- ----- -----
<S> <C> <C> <C> <C>
$10.00........................................... $0.57 $0.95 $1.32 $1.70
15.00........................................... 0.61 0.98 1.36 1.74
20.00........................................... 0.65 1.02 1.40 1.78
25.00........................................... 0.69 1.06 1.44 1.82
SENSITIVITY OF PROJECTED PRE-TAX CASH DISTRIBUTIONS AS A PERCENTAGE
OF TRUST UNIT PRICE OF $9.50
<CAPTION>
POSTED OIL PRICE WELLHEAD GAS PRICE
PER BBL PER MCF
---------------- --------------------------
$1.50 $2.00 $2.50 $3.00
----- ----- ----- -----
<S> <C> <C> <C> <C>
$10.00........................................... 6.0% 10.0% 13.9% 17.9%
15.00........................................... 6.4 10.3 14.3 18.3
20.00........................................... 6.8 10.7 14.7 18.7
25.00........................................... 7.3 11.2 15.2 19.2
SENSITIVITY OF PROJECTED AFTER-TAX CASH DISTRIBUTIONS AS A PERCENTAGE
OF TRUST UNIT PRICE OF $9.50
<CAPTION>
POSTED OIL PRICE WELLHEAD GAS PRICE
PER BBL PER MCF
----------------- --------------------------
$1.50 $2.00 $2.50 $3.00
----- ----- ----- -----
<S> <C> <C> <C> <C>
$10.00........................................... 7.1% 9.5% 11.9% 14.3%
15.00........................................... 7.4 9.7 12.1 14.5
20.00........................................... 7.6 9.9 12.3 14.7
25.00........................................... 7.9 10.2 12.6 15.1
</TABLE>
20
<PAGE>
SIGNIFICANT ASSUMPTIONS USED TO PREPARE THE 1999 PROJECTED DISTRIBUTABLE INCOME
Timing of Actual Distributions. In preparing the 1999 projected distributable
income and sensitivity tables above, the revenues and expenses of the trust
were calculated based on the terms of the conveyances creating the trust's net
profits interests. These calculations are described under "Computation of Net
Proceeds," except that amounts for the projection and tables were calculated on
an accrual or production basis rather than the cash basis prescribed by the
conveyances. As a result, the proceeds for production for the final two months
of 1999, and reflected in the projection and tables, will actually enter into
the calculation of net proceeds to be received by the trust in 2000. Net
proceeds from production during December 1998 will in fact be distributed from
the trust in 1999. Accordingly, the cash distributions attributable to
estimated 1999 production represent projected cash distributable income from
the trust for the period March 1999 through February 2000.
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 on a cash basis were 479,000 Bbls of oil and
38,535,000 Mcf of natural gas. For purposes of computing the amount of tax
credit under Section 29 of the Internal Revenue Code, natural gas production
from the underlying properties that qualify for the tight sands natural gas tax
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 assumed in the 1999 projected
distributable income estimate and shown in the tables are based on 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
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 assumed in the 1999 projected distributable income
estimate and shown in the tables are based on wellhead prices for natural gas.
The 1999 projected distributable income estimate assumes wellhead natural gas
prices of $2.00 per Mcf. 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 $1.89 per Mcf. This was approximately
$0.22 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 above 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.
21
<PAGE>
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 $6.3 million. Overhead is the estimated fee for all
properties operated by Cross Timbers that is deducted by Cross Timbers in
calculating net proceeds. For a description of production expenses 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."
Projected After-Tax Cash Distributions as a Percentage of Trust Unit Price
of $9.50. Because the net profits interests are a depleting asset, a portion
of this distribution may be considered a return of your original investment.
The portion that would be considered a return of original investment is not
determinable until the trust unit is sold by a trust unitholder. For a
discussion of alternative ways of measuring the depletion of oil and natural
gas assets, see "Risk Factors--Trust Assets Are Depleting Assets."
The Projected After-Tax Cash Distributions as a Percentage of Trust Unit
Price of $9.50 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 $0.78 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 $9.50 per trust unit.
Cost depletion is calculated by multiplying the assumed trust unit purchase
price of $9.50 by the cost depletion rate of 8.2%. 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 distributions are less than $0.82 per trust unit, the Projected
After-Tax Cash Distributions as a Percentage of Trust Unit Price of $9.50
would be the same or greater than the Projected Pre-Tax Cash Distributions as
a Percentage of Trust Unit Price 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
Projected After-Tax Cash Distributions as a Percentage of Trust Unit Price of
$9.50. See "State Tax Considerations."
22
<PAGE>
THE UNDERLYING PROPERTIES
Cross Timbers owns the underlying properties, subject to the net profits
interests conveyed to the trust. Cross Timbers may, at any time, sell all or
any portion of the underlying properties, subject to the net profits interests.
It has no present intention to do so.
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.
Historical Results from the Underlying Properties
The following table provides oil and natural gas sales volumes, average
sales prices, revenues, direct operating expenses, development costs and
overhead relating to the underlying properties for 1996, 1997 and 1998. See the
audited statements of revenues and direct operating expenses of the underlying
properties for the years ended December 31, 1996, 1997 and 1998 beginning on
page F-2 in this prospectus.
<TABLE>
<CAPTION>
1996 1997 1998
---------- ---------- ----------
(in thousands, except per unit data)
<S> <C> <C> <C> <C>
Sales Volumes:
Natural gas (Mcf).................... 36,708 38,126 38,819
Oil (Bbls)........................... 450 477 490
Average Prices:
Natural gas (per Mcf)................ $ 1.84 $ 2.20 $ 1.89
Oil (per Bbl)........................ $ 21.20 $ 19.60 $ 13.25
Revenues:
Gas sales............................ $ 67,530 $ 84,024 $ 73,559
Oil sales............................ 9,544 9,360 6,496
---------- ---------- ----------
Total.............................. 77,074 93,384 80,055
---------- ---------- ----------
Direct Operating Expenses:
Production and property taxes and
transportation...................... 6,697 9,557 9,069
Production expenses.................. 12,650 12,989 12,767
---------- ---------- ----------
Total.............................. 19,347 22,546 21,836
---------- ---------- ----------
Excess of Revenues over Direct
Operating Expenses................... $57,727 $70,838 $58,219
========== ========== ==========
Development costs..................... $21,497 $41,078 $30,497
========== ========== ==========
Overhead.............................. $ 4,665 $ 5,278 $ 6,312
========== ========== ==========
</TABLE>
23
<PAGE>
Discussion and Analysis of Historical Results from the Underlying Properties
Excess of revenues over direct operating expenses from the underlying
properties was $57,727,000 for 1996, $70,838,000 for 1997 and $58,219,000 for
1998. The changes in excess of revenues over direct operating expenses were
primarily related to changes in volumes and prices. Natural gas sales were 90%
of total revenues for the three-year period ended December 31, 1998.
Volumes. Natural gas sales volumes from the underlying properties increased
4% from 1996 to 1997, and 2% from 1997 to 1998. Oil sales volumes from the
underlying properties increased 6% from 1996 to 1997, and 3% from 1997 to 1998.
The increases were primarily attributable to development projects.
Prices. The average natural gas price increased 20% from $1.84 per Mcf in
1996 to $2.20 in 1997, and decreased 14% from 1997 to $1.89 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 decreased 8% from $21.20 per
Bbl in 1996 to $19.60 in 1997, and decreased 32% from 1997 to $13.25 in 1998.
The lower 1998 oil prices were caused by increased global production without a
corresponding increase in consumption.
Direct operating expenses. Direct operating expenses increased 17% from
$19,347,000 in 1996 to $22,546,000 in 1997, followed by a 3% decrease to
$21,836,000 in 1998. The primary reason for the fluctuation among the three
years was the change in production taxes associated with oil and gas revenue
fluctuations.
Production expenses rose 3% from $12,650,000 in 1996 to $12,989,000 in 1997,
and decreased 2% to $12,767,000 from 1997 to 1998. Most of the fluctuation was
related to the timing of major remedial projects such as workovers and
subsurface maintenance and to increases in production volumes. On a per Mcfe
basis, production costs declined from $0.32 in 1996 and 1997 to $0.31 in 1998.
Production and property taxes and transportation costs have generally
fluctuated in relation to revenue levels.
Development costs. 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 91% from $21,497,000 in 1996 to $41,078,000 in
1997, and decreased 26% to $30,497,000 in 1998 as major development projects
were completed. Cross Timbers expects development costs to be $12,000,000 per
year for the next four years.
Overhead. Overhead charged to the underlying properties by Cross Timbers was
$4,665,000 for 1996, $5,278,000 for 1997 and $6,312,000 for 1998. Fluctuations
resulted from changes in the number of active operated wells and the increase
in overhead rates per well.
24
<PAGE>
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.
<TABLE>
<CAPTION>
Gross Net
------- -------
<S> <C> <C>
Hugoton Area.................................................... 217,590 200,390
Anadarko Basin.................................................. 152,042 113,946
Green River Basin............................................... 42,654 28,841
------- -------
Total........................................................... 412,286 343,177
======= =======
</TABLE>
The following is a summary of the producing wells on the underlying
properties as of December 31, 1998:
<TABLE>
<CAPTION>
Operated Non-Operated
Wells Wells Total
------------- ------------- -------------
Gross Net Gross Net Gross Net
----- ------- ------------- ----- -------
<S> <C> <C> <C> <C> <C> <C>
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
===== ======= ===== ====== ===== =======
</TABLE>
The following is a summary of the number of wells drilled by Cross Timbers
on the underlying properties during the last three years. Unless otherwise
indicated, all wells drilled are developmental.
<TABLE>
<CAPTION>
Year Ended December 31
--------------------------------
1996 1997 1998
---------- ---------- ----------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Completed:
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
=== ==== === ==== === ====
</TABLE>
- --------
(a) One gross (0.5 net) natural gas well drilled in 1997 and four gross (3.0
net) gas wells drilled in 1998 were exploratory wells.
(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.
25
<PAGE>
Oil and Natural Gas Sales Prices and Production Costs
The following table shows the average sales prices per Bbl of oil and Mcf of
natural gas produced and the production costs, production and property taxes
and transportation costs per Mcfe for the underlying properties:
<TABLE>
<CAPTION>
Year Ended December 31
-----------------------
1996 1997 1998
------- ------- -------
<S> <C> <C> <C>
Sales prices:
Natural gas (per Mcf)................................ $ 1.84 $ 2.20 $ 1.89
Oil (per Bbl)........................................ 21.20 19.60 13.25
Production costs per Mcfe............................. 0.32 0.32 0.31
Production and property taxes and transportation costs
per Mcfe............................................. 0.17 0.23 0.22
</TABLE>
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.
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;
26
<PAGE>
. 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 15 gross (12.0
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.
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.
27
<PAGE>
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 18 gross (14.0
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.
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 20 gross (20 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
28
<PAGE>
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
underlying properties 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 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.
During 1998, Cross Timbers filed estimates of oil and gas reserves as of
December 31, 1997 with the U.S. Department of Energy on Form EIA-23. These
estimates are consistent with the reserves reported in this prospectus for the
underlying properties as of December 31, 1997, with the exception that Form
EIA-23 includes only reserves from properties that had been acquired and were
operated by Cross Timbers at that date. Neither Cross Timbers nor the trust has
reported reserves for the net profits interests with any Federal authority or
agency prior to the filing of this prospectus.
29
<PAGE>
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.
<TABLE>
<CAPTION>
80% of Net
Underlying Underlying Profits
Properties Properties Interests
---------- ---------- ---------
(in thousands)
<S> <C> <C> <C>
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
</TABLE>
The following table summarizes the changes in estimated proved reserves of
the underlying properties for the periods indicated. The data is presented
assuming the underlying properties were acquired prior to December 31, 1995.
Reserve estimates for underlying properties that Cross Timbers acquired between
1996 and 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 reserves are assumed to equal reserves
at the acquisition date plus production between December 31, 1995, 1996 or 1997
and the acquisition date.
<TABLE>
<CAPTION>
Underlying Properties
----------------------------
Gas
Gas Oil Equivalents
(Mcf) (Bbls) (Mcfe)
------- ------ -----------
(in thousands)
<S> <C> <C> <C>
Balance, December 31,
1995..................... 445,045 4,438 471,673
Revisions, extensions,
discoveries and
additions.............. 48,131 573 51,569
Production.............. (36,708) (450) (39,408)
------- ----- -------
Balance, December 31,
1996..................... 456,468 4,561 483,834
Revisions, extensions,
discoveries and
additions.............. 70,279 191 71,425
Production.............. (38,126) (477) (40,988)
------- ----- -------
Balance, December 31,
1997..................... 488,621 4,275 514,271
Revisions, extensions,
discoveries and
additions.............. 65,271 245 66,741
Production.............. (38,819) (490) (41,759)
------- ----- -------
Balance, December 31,
1998..................... 515,073 4,030 539,253
======= ===== =======
Proved Developed Reserves
Balance, December 31,
1995..................... 383,798 3,629 405,572
Balance, December 31,
1996..................... 401,127 3,962 424,899
Balance, December 31,
1997..................... 417,743 3,574 439,187
Balance, December 31,
1998..................... 435,328 3,368 455,536
</TABLE>
30
<PAGE>
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, 80%
of the underlying properties and the net profits interests as of December 31,
1998. Because the underlying properties and the trust are not taxable at the
underlying property level or trust level, no provision is included for income
taxes.
<TABLE>
<CAPTION>
80% of Net
Underlying Underlying Profits
Properties Properties Interests
---------- ---------- ---------
(in thousands)
<S> <C> <C> <C>
Future cash flows............................... $1,087,660 $870,128 $595,301
Future costs:
Production.................................... 364,930 291,944 55,686
Development................................... 48,212 38,569 --
---------- -------- --------
Future net cash flows........................... 674,518 539,615 539,615
10% discount factor............................. 327,341 261,873 261,873
---------- -------- --------
Standardized measure............................ $ 347,177 $277,742 $277,742
========== ======== ========
</TABLE>
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. Federal and state regulations govern
the price and terms for access to natural gas pipeline transportation. The
Federal Energy Regulatory Commission's regulations for interstate natural gas
transmission in some circumstances may also affect the intrastate
transportation of natural gas.
While natural gas prices are currently unregulated, Congress historically
has been active in the area of natural gas regulation. Cross Timbers cannot
predict whether new legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the various state
legislatures, and what effect, if any, the proposals might have on the
operations of the underlying properties.
Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at market prices. The Federal Energy Regulatory
Commission implemented regulations on January 1, 1995, to establish an indexing
system for transportation rates for oil that could increase the cost of
transporting oil to the purchaser. Cross Timbers is not able to predict what
effect, if any, these regulations might have.
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,
31
<PAGE>
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. Seven percent of the net acres
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.
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
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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 wellhead to third parties at the best available
price. Cross Timbers arranges for some of its natural gas to be processed by
unaffiliated third parties and markets the natural gas liquids. 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 and computer-controlled equipment of Cross Timbers, the trust's
transfer agent and other third parties. These third parties include oil and
natural gas purchasers and significant service providers such as electric
utility companies and natural gas plant, pipeline and gathering system
operators. Because the trust will not use the trustee's computer systems to any
significant degree, the trustee's Year 2000 compliance should not significantly
affect the trust.
Cross Timbers is in the process of reviewing its computer systems and
computer-controlled field equipment and making the necessary modifications for
Year 2000 compliance. Cross Timbers has completed modifications and testing of
its primary accounting and land computer programs. The remaining computer
systems have been inventoried and assessed. Cross Timbers expects to complete
remediation and testing of significant remaining systems by August 1999.
Some of Cross Timbers' critical field equipment, such as natural gas
compressors, are partially controlled or regulated by embedded computer chips.
Based on a preliminary review of all operating areas, Cross Timbers has
identified no significant compliance exceptions. Cross Timbers has inventoried
approximately 30% of field equipment in operated areas and expects to complete
its review of the remaining 70% of field equipment inventories by April 1999.
Cross Timbers plans to complete remediation and testing of identified
exceptions for significant computer-controlled field equipment by August 1999.
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Based on its review, remediation efforts and the results of testing to date,
Cross Timbers does not believe that timely modification of its computer systems
and computer-controlled equipment for Year 2000 compliance represents a
material risk to the trust. Cross Timbers estimates that total costs related to
Year 2000 compliance efforts will be less than $500,000 of which approximately
$50,000 has been incurred and expensed through December 1998. The trust will
not incur any of Cross Timbers' Year 2000 costs.
Cross Timbers has identified significant third parties whose Year 2000
compliance could affect Cross Timbers and is in the process of formally
inquiring about their Year 2000 status. Cross Timbers has received responses to
approximately 30% of its inquiries. Approximately 90% of respondents have
indicated that they will be Year 2000 compliant by January 1, 2000. Despite its
efforts to assure that such third parties are Year 2000 compliant, Cross
Timbers cannot provide assurance that all significant third parties will
achieve compliance in a timely manner. A third party's failure to achieve Year
2000 compliance could have a material adverse effect on Cross Timbers'
operations and cash flow, and therefore have a material adverse impact on
timely trust distributions to trust unitholders. For example a third party
might fail to deliver revenue related to the trust's net profits interest to
Cross Timbers, 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 identifying appropriate contingency plans in the
event of potential problems resulting from failure of Cross Timbers' or
significant third party computer systems on January 1, 2000. Cross Timbers has
not completed any contingency plans to date. Specific contingency plans will be
developed in response to the results of testing scheduled to be complete by
August 1999, as well as the assessed probability and risk of system or
equipment failure. These contingency plans may include installing backup
computer systems or equipment, temporarily replacing systems or equipment with
manual processes, and identifying alternative suppliers, service companies and
purchasers. Cross Timbers expects these plans to be complete by October 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 reducing
royalties for improper charges for production, marketing, gathering, processing
and transportation costs. The plaintiffs also allege that Cross Timbers sold
natural gas through affiliated companies at prices less favorable than those
paid by third parties. The plaintiffs are seeking an accounting and payment of
the monies allegedly owed to them. 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 Cross Timbers
underpaid royalties on natural gas produced from federal leases and lands owned
by Native Americans by at least 20% during the past 10 years as a result of
mismeasuring the volume of natural gas and wrongfully analyzing 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 of between $5,000 and $10,000 for each violation of the U.S.
False Claims Act, and an order for Cross Timbers to cease the allegedly
improper measuring
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practices. According to the U.S. Justice Department, 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" contained in the
conveyances and described below. Under the conveyances, net proceeds are
computed monthly. Cross Timbers pays 80% of the aggregate net proceeds
attributable to a computation period to the trust on or before the last
business day of the month following the computation period. Cross Timbers will
not pay to the trust interest on the net proceeds held by Cross Timbers prior
to payment to the trust. The trustee makes distributions to trust unitholders
monthly. See "Description of the Trust Units--Distributions and Income
Computations."
Net proceeds equal the excess of gross proceeds over production costs and
excess production costs attributable to a prior computation period. For
royalty and overriding royalty interests, production costs are zero.
Gross proceeds means:
. during computation periods through February 2000,
calculated each month, relating to payments to trust unitholders through
April 2000, the greater of:
-- $2.00 per Mcf multiplied by the amount of production of natural gas
from the underlying properties, or
-- the amounts received by Cross Timbers from sales of natural gas
produced from the underlying properties;
plus the amounts received by Cross Timbers from sales of oil produced
from the underlying properties; and
. for computation periods after February 2000,
the amounts received by Cross Timbers from sales of oil and natural gas
produced from the underlying properties;
in each case 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 of production; and
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. 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.
When gross proceeds are calculated based on the realized $2.00 per Mcf
minimum price, the amount of gross proceeds will be reduced by an amount to
reflect deductions for severance taxes computed on a realized sales price of
$2.00 per Mcf, although not actually paid by Cross Timbers.
For computation periods through February 2000, Cross Timbers will pay to the
trust the difference between the gross proceeds payable if natural gas were
sold at $2.00 per Mcf and gross proceeds payable from sales at any lower actual
price. For tax reasons, the conveyances limit the net proceeds payable to the
trust to 100% of gross proceeds actually received from the underlying
properties. As a result, based on 1999 projected distributable income, if
natural gas prices fall below $.75 per Mcf, the trust would receive an
effective price of less than $2.00 per Mcf.
Cross Timbers has entered into NYMEX futures contracts and location
differential swap agreements that will yield an average price of $2.00 per Mcf
through December 1999. These contracts cover substantially all of the projected
production during that period attributable to the 43% of trust units that will
not be owned by Cross Timbers, assuming full exercise of the underwriters'
option. These hedging contracts will not be pledged to the trust, but will
provide Cross Timbers with additional funds with which to pay the difference
between any lower actual price and $2.00 per Mcf. In addition, the conveyances
covering the net profits interests provide that Cross Timbers will produce oil
and natural gas from the underlying properties as though it were not required
to pay any amount under these minimum price provisions.
Gross proceeds does not include consideration for the transfer or sale of
any underlying property by Cross Timbers or any subsequent owner to any new
owner. Gross proceeds also does not include any amount for oil and natural gas
lost in production or marketing or used by the owner of the underlying
properties in drilling, production and plant operations. Gross proceeds
includes payments for future production if they are not subject to repayment in
the event of insufficient subsequent production.
Production costs 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;
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. any overhead charge;
. amounts previously included in gross proceeds but subsequently paid as a
refund, interest or penalty;
. costs and expenses for renewals or extensions of leases; and
. at the option of the owner of an underlying property, accruals for costs
approved under authorizations for expenditure.
As is customary in the oil and natural gas industry, Cross Timbers charges
an overhead fee to operate the underlying properties. The operating activities
include various engineering, accounting and administrative functions. The fee
is based on a monthly charge per active operated well, and it totalled $6.3
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.
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
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the transferred property will be calculated separately and paid by the
transferee. The conveyances have been recorded in the appropriate real property
records to give notice of the net profits interests to Cross Timbers' creditors
and transferees.
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 contained 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. Instead the trust will rely on the opinion of Butler & Binion,
L.L.P. regarding the classification of the trust and certain federal income tax
consequences described below, which will be confirmed at the time of the
closing. Butler & Binion, L.L.P. believes that its opinion is in accordance
with the present position of the IRS regarding grantor trusts. The tax opinion
is not binding on the IRS or the courts, however, and no assurance can be given
that the IRS or the courts will agree with the opinion.
Summary of Legal Opinions
Butler & Binion, L.L.P. is of the opinion that, for federal income tax
purposes:
. the trust will be treated as a grantor trust and not a business entity
taxable as a partnership or a corporation;
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. 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 for his share of qualifying natural gas
production from tight sands attributable to the net profits interests.
Butler & Binion, L.L.P. advises that, unless noted otherwise, legal conclusions
stated in this section constitute its opinion.
Since no ruling is being requested from the IRS with respect to the trust or
trust unitholders, the IRS could challenge these opinions and statements, which
do not bind the IRS or the courts. The IRS could win in court if it did
challenge these matters.
Classification and Taxation of the Trust
In the opinion of Butler & Binion, L.L.P., under current law, the trust will
be taxable as a grantor trust and not as a business entity. As a grantor trust,
the trust will not be subject to tax at the trust level. For tax purposes, the
grantors, who in this case are the trust unitholders, will be considered to own
the trust's income and principal as though no trust were in existence. A
grantor trust simply files an information return, reporting all items of
income, credit or deduction which must be included in the tax returns of the
trust unitholders based on their respective accounting methods and taxable
years without regard to the accounting method and tax year of the trust. If,
contrary to the opinion of Butler & Binion, L.L.P., the trust was determined to
be 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 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 by
the trust. This will normally be the last business day of each calendar month.
Similarly, the trustee intends to pay expenses only on the day it receives a
royalty payment. All expenses paid on a royalty receipt day will be allocated
as expenses of each trust unitholder who receives the distribution of that
royalty income. In most cases, therefore, the income and expenses of the trust
for a period will be reported as belonging to the trust unitholder who received
a distribution for that period. The amount of the distribution for a trust unit
will generally equal the net income allocated to that trust unit, determined
without regard to depletion. This correlation may not exist if, for example,
the trustee were to establish a cash reserve to pay estimated future expenses
or pay an expense with borrowed funds. Moreover, the IRS could attempt to
impute income to trust unitholders when a royalty payment on the net profits
interests accrues. The IRS could also attempt to disallow the deduction of
administrative expenses to persons who were not trust unitholders when the
expenses were incurred. If the IRS were successful, trust income might be taxed
to trust unitholders other than those who received the distribution relating to
that income. Also, an accrual basis trust unitholder might realize royalty
income in a tax year earlier than that reported by the trustee.
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Royalty Income and Depletion
In the opinion of Butler & Binion, L.L.P. the income from the net profits
interests will be royalty income qualifying for an allowance for depletion. The
depletion allowance must be computed separately by each trust unitholder for
each oil or gas property, within the meaning of Section 614 of the Internal
Revenue Code. Butler & Binion, L.L.P. understands that the IRS is presently
taking the position that a net profits interest carved from multiple properties
is a single property for depletion purposes. Accordingly, the trust intends to
take the position that each net profits interest transferred to the trust by a
conveyance 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. Percentage depletion is subject
to a net income limitation of 100% of the taxable income from the property,
computed without regard to depletion deductions and 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 allowance
for the property is calculated by dividing the adjusted tax basis of the
property at the beginning of the year by the estimated total number of Bbls of
oil or Mcf of natural gas recoverable from the property. This amount is then
multiplied by the number of Bbls of oil or Mcf of natural gas produced and sold
from the property during the year. Cost depletion for a property cannot exceed
the adjusted tax basis of the property. Each trust unitholder will compute cost
depletion using his basis in his trust units. Information will be provided to
each trust unitholder reflecting how his basis should be allocated among each
property represented by his trust units. To the extent the depletion tax
deduction exceeds cash distributions per trust unit, that excess can be
deducted from the taxpayer's other sources of taxable income.
Other Income and Expenses
It is anticipated that the only other income of the trust will be interest
income earned on funds held as a reserve or pending distribution. Other
expenses of the trust will include any state and local taxes imposed on the
trust and administrative expenses of the trustee. Although the issue has not
been finally resolved, Butler & Binion, L.L.P. believes that all or
substantially all of those expenses are deductible in computing adjusted gross
income and, therefore, are not the type of miscellaneous itemized deductions
that are allowable only to the extent that they total more than 2% of adjusted
gross income.
Alternative Minimum Tax
All taxpayers are subject to an alternative minimum tax. Alternative minimum
taxable income is the taxpayer's taxable income recomputed with various
adjustments plus items of tax preference. In the case of persons other than
independent producers, tax preferences include the excess of percentage
depletion deductions for an oil or natural gas property over the adjusted tax
basis of the property. Alternative minimum tax is the excess of a taxpayer's
tentative minimum tax for a tax year
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over his regular tax for that year. The tentative minimum tax is determined by
multiplying the excess of alternate minimum taxable income over the applicable
exemption amount by 26% up to $175,000 and 28% over $175,000 and subtracting
the alternate minimum tax foreign tax credit. Reduced maximum alternate minimum
tax rates apply to net capital gains and certain other gains.
Since the effect of the alternate minimum tax 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 alternate minimum tax on him.
Section 29 Tight Sands Natural Gas Tax Credit
A small amount 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. 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, which is 5.8 MMBtu, or approximately $.52 per MMBtu. The credit is
reduced by a formula computation as the price of oil rises above an inflation
adjusted amount. Because the calendar year 1998 computed oil 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 Butler & Binion, L.L.P.,
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 of the taxpayer's regular tax liability for that taxable year, as
reduced by the taxpayer's foreign tax credits and certain nonrefundable
credits, over the taxpayer's tentative minimum tax liability for that year. Any
amount of Section 29 tax credit disallowed for the tax year solely because of
this limitation will increase the taxpayer's minimum tax credit carryover. This
credit may be carried forward indefinitely as a credit against the taxpayer's
regular tax liability, subject, however, to the limitation described in the
first sentence of this paragraph. There is no provision for the carryback or
carryforward of the Section 29 tax credit in any other circumstances. 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
Internal Revenue Code Section 469 for a trust unitholder who acquires and holds
trust units as an investment. Section 29 tax credits generated by an investment
in the trust units, therefore, can be utilized to offset regular tax liability
on income from any source, subject to the limitations discussed in "--Section
29 Tight Sands Natural Gas Tax Credit" above.
Unrelated Business Taxable Income
Certain organizations that are generally exempt from tax under Internal
Revenue Code Section 501 are subject to tax on certain types of business income
defined in Section 512 as unrelated business income. In the opinion of Butler &
Binion, L.L.P., the income of the trust will not be unrelated business taxable
income so long as the trust units are not debt-financed property within
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the meaning of 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 the gain on such sale or the sum of the
prior depletion deductions taken on the trust units, but not in excess of the
initial basis of the trust units. The IRS could take the position, however,
that a portion of the sales proceeds is ordinary income to the extent of any
accrued income at the time of the sale that was allocable to the trust units
sold even though the income had not been distributed to the selling trust
unitholder.
Taxation of Foreign Holders
Unless the election described below is made, a foreign holder, consisting
of a nonresident alien individual, foreign corporation, or foreign estate or
trust, will be subject to federal income withholding tax on his share of gross
royalty income from the net profits interests. The withholding tax will be at
a 30% rate, or lower treaty rate if applicable and proper evidence is supplied
to the withholding agent, 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.
Trust unitholders who are foreign holders may elect under Internal Revenue
Code Section 871 or Section 882 or similar provisions of applicable treaties
to treat income attributable to the net profits interests as effectively
connected with the conduct of a trade or business in the United States. The
foreign holder will then be taxed at regular federal income tax rates on the
net income attributable to the net profits interests, including gain
recognized on the disposition of trust units. Absent a treaty exception, the
net income of a corporate foreign holder which has made such an election will
also be subject to the branch profits tax imposed under Section 884. To claim
the deductions allowable in computing net income, including cost depletion, an
electing foreign holder must file a United States income tax return. To avoid
tax withholding, an electing foreign holder must provide proper certificates
or other evidence to the withholding agent. Once made, the election is
irrevocable unless an applicable treaty allows the election to be made
annually. The election is applicable to all income and gain realized by the
foreign holder on any real property interests located in the United States,
including those interests held through partnerships, fixed investment trusts,
and other pass-through entities.
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Backup Withholding
In general, distributions of trust income will not be subject to backup
withholding unless the trust unitholder is an individual or other noncorporate
taxpayer and he fails to comply with certain reporting procedures.
Tax Shelter Registration
Cross Timbers believes that the requirements for tax shelter registration
under Internal Revenue Code Section 6111 would be met if any trust unitholder's
investment base is substantially reduced by borrowing. To avoid any potential
penalty, the trust will be registered as a tax shelter with the IRS. The
trustee will furnish the tax shelter registration number to each trust
unitholder. Each trust unitholder must disclose this number by attaching Form
8271 to his tax return.
Issuance of a tax shelter registration number does not indicate this
investment or the claimed tax benefits have been reviewed, examined or approved
by the IRS.
Reports
The trustee will furnish to trust unitholders of record quarterly and annual
reports to facilitate their computation of their tax liability. See
"Description of the Trust Units--Periodic Reports."
STATE TAX CONSIDERATIONS
The following is a brief summary of the material state income taxes and
other state tax matters affecting the trust and the trust unitholders. Trust
unitholders are urged to consult their own legal and tax advisors as these
matters relate to their individual circumstances.
Income Tax Considerations
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
trust 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
-- 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.
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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 regulates pension,
profit-sharing and other employee benefit plans to which it applies. ERISA
also contains standards for persons who are fiduciaries of those plans. In
addition, the Internal Revenue Code provides similar requirements and
standards which are applicable to qualified plans, which include these types
of plans and to individual retirement accounts, whether or not subject to
ERISA.
A fiduciary of a qualified plan should carefully consider fiduciary
standards under ERISA regarding the qualified plan's particular circumstances
before authorizing an investment in trust units. A fiduciary should consider
. whether the investment satisfies the prudence requirements of Section
404(a)(1)(B) of ERISA;
. whether the investment satisfies the diversification requirements of
Section 404(a)(1)(C) of ERISA; and
. whether the investment is in accordance with the documents and
instruments governing the qualified plan as required by Section
404(a)(1)(D) of ERISA.
A fiduciary should also consider whether an investment in trust units might
result in direct or indirect nonexempt prohibited transactions under Section
406 of ERISA and Internal Revenue Code Section 4975. In deciding whether an
investment involves a prohibited transaction, a fiduciary must determine
whether there are plan assets in the transaction. On November 13, 1986, the
Department
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of Labor published final regulations concerning whether or not a qualified
plan's assets would be deemed to include an interest in the underlying assets
of an entity for purposes of the reporting, disclosure and fiduciary
responsibility provisions of ERISA and analogous provisions of the Internal
Revenue Code. These regulations provide that the underlying assets of an entity
will not be considered "plan assets" if the equity interests in the entity are
a publicly offered security. Cross Timbers expects that at the time of the sale
of the trust units in this offering, they will be publicly offered securities.
Fiduciaries, however, will need to determine whether the acquisition of trust
units is a nonexempt prohibited transaction under the general requirements of
ERISA Section 406 and Internal Revenue Code Section 4975.
The prohibited transaction rules are complex, and persons involved in
prohibited transactions are subject to penalties. For that reason, potential
qualified plan investors should consult with their counsel to determine the
consequences under ERISA and the Internal Revenue Code of their acquisition and
ownership of trust units.
DESCRIPTION OF THE TRUST INDENTURE
The following information and the information included under "Description of
the Trust Units" summarize the material information contained in the trust
indenture. This summary may not contain all the information that is important
to you. For more detailed provisions concerning the trust, you should read the
trust indenture. A copy of the trust indenture was filed as an exhibit to the
registration statement. See "Available Information."
Creation and Organization of the Trust; Amendments
Cross Timbers 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 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--
. increase the power of the trustee to engage in business or investment
activities;
. alter the rights of the trust unitholders as among themselves; or
. permit the trustee to distribute the net profits interests in kind.
Assets of the Trust
The assets of the trust consist of net profits interests and any cash and
temporary investments being held for the payment of expenses and liabilities
and for distribution to the trust unitholders.
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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, cash
and temporary cash investments, and it may not engage in any investment
activity except investing cash on hand.
At the request of Cross Timbers, the trustee must sell for cash net profits
interests relating to the underlying properties sold by Cross Timbers to an
unaffiliated third party. However, these sales are required only if in any
calendar year the net profits interests sold do not exceed 1% of the discounted
present value of estimated future net revenues for the proved reserves of the
trust's net profits interests, as contained in the most recent reserve report.
The trustee may sell the net profits interests in any of the following
circumstances:
. the sale does not involve a material part of the trust's assets and is
in the best interests of the trust unitholders. A majority of the trust
units represented at a meeting of the trust unitholders where a quorum
is present must approve the sale; or
. the sale constitutes a material part of the trust's assets and is in the
best interests of the trust unitholders. Holders representing 80% of the
outstanding trust units must approve the sale.
Upon 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
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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 the net profits interests become working interests or that the
trust becomes an operating business.
Liabilities of the Trust
Because the trust does not conduct an active business and the trustee has
little power to incur obligations, Cross Timbers expects that the trust will
only incur liabilities for routine administrative expenses. These might include
the trustee's fees and accounting, engineering, legal and other professional
fees.
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 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;
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. 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 regarding each of his trust
units as every other trust unitholder has regarding his units. The trust has
40,000,000 trust units outstanding.
Distributions and Income Computations
Each month, the trustee will determine the amount of funds available for
distribution to the trust unitholders. Available funds are the excess cash
received by the trust from the net profits interests and other sources that
month, over the trust's liabilities for that month. Available funds will be
reduced by any cash the trustee decides to hold as a reserve against future
liabilities. Trust unitholders that own their trust units on the monthly record
date, which is the end of the last business day of the month, will receive a
pro-rata distribution no later than 10 business days after the monthly record
date. The first distribution of $0.089 per trust unit was paid in early April
1999 to Cross Timbers, the sole trust unitholder. The first distribution to
trust unitholders purchasing trust units in this offering will be made around
May 14, 1999 to trust unitholders owning trust units on April 30, 1999.
Unless otherwise advised by counsel or the IRS, the trustee will treat the
income and expenses of the trust for each month as belonging to the trust
unitholders of record on the monthly record date. Trust unitholders will
recognize income and expenses for tax purposes in the month the trust receives
or pays those amounts, rather than in the month the trust distributes them.
Minor variances
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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.
Voting Rights of Trust Unitholders
Trust unitholders have more limited voting rights than those of stockholders
of most public corporations. For example, there is no requirement for annual
meetings of trust unitholders or for annual or other periodic re-election of
the trustee.
The trustee or trust unitholders owning at least 15% of the outstanding
trust units may call meetings of trust unitholders. Meetings must be held in
Fort Worth, Texas. The trustee must send written notice of the time and place
of the meeting and the matters to be acted upon to all of the trust unitholders
at least 20 days and not more than 60 days before the meeting. Trust
unitholders representing a majority of trust units outstanding must be present
or represented to have a quorum. Each trust unitholder is entitled to one vote
for each trust unit owned.
Unless otherwise required by the trust indenture, a matter is approved by
the vote of a majority of the trust units held by the trust unitholders at a
meeting where there is a quorum. This is true,
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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.
Fiduciary Trustee has a fiduciary duty Officers and directors have a
Duties to trust unitholders, but fiduciary duty of loyalty to
Cross Timbers does not. stockholders and a duty to
use due care in management
and administration of a
corporation.
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.
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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 sell trust units, exchange them for oil and natural
gas properties or use them for other corporate purposes.
Prior to this offering there has been no public market for the trust units.
Cross Timbers cannot predict the effect on future market prices, if any, of
market sales of trust units or the availability of trust units for sale if it
disposes of its remaining trust units. Nevertheless, sales of substantial
amounts of trust units in the public market could adversely affect prevailing
market prices.
LEGAL MATTERS
Counsel for Cross Timbers, Kelly, Hart & Hallman, P.C., Fort Worth, Texas,
will give a legal opinion as to the validity of the trust units. Counsel for
the underwriters, Andrews & Kurth L.L.P., Houston, Texas, will give a legal
opinion to the underwriters regarding other matters related to this offering.
Butler & Binion, L.L.P., Houston, Texas, will give the tax opinion described in
the section of this prospectus captioned "Federal Income Tax Consequences."
Morris, Laing, Evans, Brock & Kennedy, Chartered, Wichita, Kansas, will give
the Kansas tax opinion described 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 statements of revenues and direct operating expenses of the Underlying
Properties, the statement of assets and trust corpus of Hugoton Royalty Trust,
the financial statements of Cross Timbers and the statements of revenues and
direct operating expenses of the EEX Acquisition and the Amoco Acquisition
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 relating to those financial statements, and are
included in this prospectus in reliance upon the authority of said firm as
experts in accounting and auditing.
AVAILABLE INFORMATION
The trust and Cross Timbers have filed with the SEC in Washington, D.C. a
registration statement, including all amendments, under the Securities Act of
1933 relating to the trust units. As permitted by the rules and regulations of
the SEC, this prospectus does not contain all of the information contained in
the registration statement and the exhibits and schedules to the registration
statement. In addition, Cross Timbers files annual, quarterly and current
reports, proxy statements and other information with the SEC. You may read and
copy the registration statement and any of
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Cross Timbers' reports, statements or other information at the SEC's public
reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. You may
request copies of these documents, upon payment of a duplicating fee, by
writing to the SEC at the address in the previous sentence. To obtain
information on the operation of the public reference rooms you may call the SEC
at (800) SEC-0330. Cross Timbers' filings are also available to the public on
the SEC Internet Web site at http://www.sec.gov.
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.
52
<PAGE>
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
In this prospectus the following terms have the meanings specified below.
Bbl -- One stock tank barrel, or 42 US gallons liquid volume, of crude oil or
other liquid hydrocarbons.
Bcf -- One billion cubic feet of natural gas.
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.
Net Profits Interest (also called a net overriding royalty interest) -- A
nonoperating interest that creates a share in gross production from an
operating or working interest in oil and gas properties. The share is measured
by net profits from the sale of production.
NYMEX -- New York Mercantile Exchange, where futures and options contracts for
the oil and natural gas industry and some precious metals are traded.
Oil Revenue -- Includes revenue related to the sale of oil and condensate
production.
Overriding Royalty Interest -- A royalty interest created or "carved" out of a
working or operating interest. Its term extends for the same term as the
working interest from which it is carved.
Proved Developed Reserves -- Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
53
<PAGE>
Proved Reserves -- The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering data,
appear with reasonable certainty to be recoverable in the future from known oil
and natural gas reservoirs under existing economic and operating conditions.
The Securities and Exchange Commission definition of proved oil and gas
reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the date
the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalations
based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (B) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (C) crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; and (D) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.
Proved Undeveloped Reserves -- Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required.
Reserve-to-Production Index -- An estimate, expressed in years, of the total
estimated proved reserves attributable to a producing property divided by
production from the property for the 12 months preceding the date as of which
the proved reserves were estimated.
Royalty Interest -- A real property interest entitling the owner to receive a
specified portion of the gross proceeds of the sale of oil and natural gas
production or, if the conveyance creating the interest provides, a specific
portion of oil and natural gas produced, without any deduction for the costs to
explore for, develop or produce the oil and natural gas. A royalty interest
owner has no right to consent to or approve the operation and development of
the property, while the owners of the working interest have the exclusive right
to exploit the mineral on the land.
Standardized Measure of Discounted Future Net Cash Flows -- Also referred to
herein as "standardized measure." It is the present value of estimated future
net revenues computed by discounting estimated future net revenues at a rate of
10% annually.
54
<PAGE>
The Financial Accounting Standards Board requires disclosure of standardized
measure of discounted future net cash flows relating to proved oil and gas
reserve quantities, per paragraph 30 of Statement of Financial Accounting
Standards No. 69, as follows:
A standardized measure of discounted future net cash flows relating to an
enterprise's interests in (a) proved oil and gas reserves and (b) oil and
gas subject to purchase under long-term supply, purchase, or similar
agreements and contracts in which the enterprise participates in the
operation of the properties on which the oil or gas is located or otherwise
serves as the producer of those reserves shall be disclosed as of the end
of the year. The standardized measure of discounted future net cash flows
relating to those two types of interests in reserves may be combined for
reporting purposes. The following information shall be disclosed in the
aggregate and for each geographic area for which reserve quantities are
disclosed:
a. Future cash inflows. These shall be computed by applying year-end prices
of oil and gas relating to the enterprise's proved reserves to the year-
end quantities of those reserves. Future price changes shall be
considered only to the extent provided by contractual arrangements in
existence at year-end.
b. Future development and production costs. These costs shall be computed
by estimating the expenditures to be incurred in developing and
producing the proved oil and gas reserves at the end of the year, based
on year-end costs and assuming continuation of existing economic
conditions. If estimated development expenditures are significant, they
shall be presented separately from estimated production costs.
c. Future income tax expenses. These expenses shall be computed by applying
the appropriate year-end statutory tax rates, with consideration of
future tax rates already legislated, to the future pretax net cash flows
relating to the enterprise's proved oil and gas reserves, less the tax
basis of the properties involved. The future income tax expenses shall
give effect to tax deductions, tax credits and allowances relating to
the enterprise's proved oil and gas reserves.
d. Future net cash flows. These amounts are the result of subtracting
future development and production costs and future income tax expenses
from future cash inflows.
e. Discount. This amount shall be derived from using a discount rate of 10
percent a year to reflect the timing of the future net cash flows
relating to proved oil and gas reserves.
f. Standardized measure of discounted future net cash flows. This amount is
the future net cash flows less the computed discount.
Working Interest (also called an operating interest) -- A real property
interest entitling the owner to receive a specified percentage of the proceeds
of the sale of oil and natural gas production or a percentage of the
production, but requiring the owner of the working interest to bear the cost to
explore for, develop and produce such oil and natural gas. A working interest
owner who owns a portion of the working interest may participate either as
operator or by voting his percentage interest to approve or disapprove the
appointment of an operator and certain activities in connection with the
development and operation of a property.
55
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Underlying Properties
Report of Independent Public Accountants................................ F-2
Statements of Revenues and Direct Operating Expenses for the Years Ended
December 31, 1996, 1997 and 1998....................................... 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-12
Notes to Pro Forma Statement of Distributable Income (Unaudited)........ F-13
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
Cross Timbers Oil Company:
We have audited the accompanying statements of revenues and direct operating
expenses of the Underlying Properties of Cross Timbers Oil Company ("the
Company") for each of the three years in the period ended December 31, 1998.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statement. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the statements referred to above present fairly, in all
material respects, the revenues and direct operating expenses of the Underlying
Properties for each of the three years in the period ended December 31, 1998,
in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
February 18, 1999
F-2
<PAGE>
UNDERLYING PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
For the Years Ended December 31, 1996, 1997 and 1998
<TABLE>
<CAPTION>
1996 1997 1998
------- ------- -------
(in thousands)
<S> <C> <C> <C>
Revenues
Gas sales............................................. $67,530 $84,024 $73,559
Oil sales............................................. 9,544 9,360 6,496
------- ------- -------
Total............................................... 77,074 93,384 80,055
------- ------- -------
Direct Operating Expenses
Production and property taxes and transportation...... 6,697 9,557 9,069
Production expenses................................... 12,650 12,989 12,767
------- ------- -------
Total............................................... 19,347 22,546 21,836
------- ------- -------
Excess of Revenues over Direct Operating Expenses....... $57,727 $70,838 $58,219
======= ======= =======
</TABLE>
See Accompanying Notes to Financial Statements.
F-3
<PAGE>
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS
1. UNDERLYING PROPERTIES
The Underlying Properties are predominantly working interests in producing
properties currently owned by Cross Timbers Oil Company ("Company") in the
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
accompanying 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 accrual 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.
Royalty income of the Trust is determined based on the defined 80% net
profits interest percentage of net proceeds of the Underlying Properties. Net
proceeds for the year ended December 31 is computed based on Company cash
receipts and disbursements for the period from December of the prior year
through November. The computation also includes deductions for development
costs on the properties of $21,497,000 in 1996, $41,078,000 in 1997 and
$30,497,000 in 1998, as well as an overhead charge totaling $4,665,000 in 1996,
$5,278,000 in 1997, and $6,312,000 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
<PAGE>
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS--(Continued)
Sales from the Underlying Properties to the Company's wholly owned
subsidiaries are as follows (in thousands):
<TABLE>
<CAPTION>
1996 1997 1998
------- ------- -------
<S> <C> <C> <C>
TGPC................................................. $13,944 $16,837 $13,248
RGC.................................................. 9,969 10,390 8,344
CTES................................................. 13,228 32,348 30,042
</TABLE>
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 plaintiffs are
seeking an accounting and payment of the monies allegedly owed to them. 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, in management's opinion, 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 the Company underpaid
royalties on natural gas produced from federal leases and lands owned by Native
Americans by at least 20% during the past 10 years as a result of mismeasuring
the volume of natural gas and wrongfully analyzing 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 of between $5,000 and $10,000 for each violation of the U.S. False
Claims Act, and an order for the Company to cease the allegedly improper
measuring practices. According to the U.S. Justice Department, 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 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, in management's opinion, 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
F-5
<PAGE>
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS--(Continued)
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%. 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.
<TABLE>
<CAPTION>
Gas (Mcf) Oil (Bbls)
Proved Reserves --------- ----------
(in thousands)
<S> <C> <C>
Balance, December 31, 1995.............................. 445,045 4,438
Revisions............................................. 21,000 428
Extensions, discoveries and other additions........... 27,131 145
Production............................................ (36,708) (450)
------- -----
Balance, December 31, 1996.............................. 456,468 4,561
Revisions............................................. (14,115) (294)
Extensions, discoveries and other additions........... 84,394 485
Production............................................ (38,126) (477)
------- -----
Balance, December 31, 1997.............................. 488,621 4,275
Revisions............................................. 18,251 (14)
Extensions, discoveries and other additions........... 47,020 259
Production............................................ (38,819) (490)
------- -----
Balance, December 31, 1998.............................. 515,073 4,030
======= =====
</TABLE>
<TABLE>
<S> <C> <C>
Proved Developed Reserves
<CAPTION>
Gas (Mcf) Oil (Bbls)
--------- ----------
(in thousands)
<S> <C> <C>
December 31, 1995....................................... 383,798 3,629
======= =====
December 31, 1996....................................... 401,127 3,962
======= =====
December 31, 1997....................................... 417,743 3,574
======= =====
December 31, 1998....................................... 435,328 3,368
======= =====
</TABLE>
F-6
<PAGE>
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS--(Continued)
<TABLE>
<S> <C> <C> <C>
Standardized Measure of Discounted
Future Net Cash Flows Relating to
Proved Reserves
<CAPTION>
December 31,
----------------------------------
1996 1997 1998
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>
Future cash inflows.................... $1,411,655 $1,056,395 $1,087,660
Future costs:
Production........................... 356,588 326,168 364,930
Development.......................... 30,894 42,460 48,212
---------- ---------- ----------
Future net cash flows.................. 1,024,173 687,767 674,518
10% discount factor.................... 467,536 322,305 327,341
---------- ---------- ----------
Standardized measure of discounted
future net cash flows................. $ 556,637 $ 365,462 $ 347,177
========== ========== ==========
Changes in Standardized Measure of
Discounted Future Net Cash Flows from
Proved Reserves
<CAPTION>
December 31,
----------------------------------
1996 1997 1998
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>
Standardized measure, beginning of
year.................................. $ 270,814 $ 556,637 $ 365,462
---------- ---------- ----------
Revisions:
Prices and costs..................... 246,172 (211,947) (31,151)
Quantity estimates................... 48,347 7,816 11,790
Accretion of discount................ 24,262 50,432 33,468
Future development costs............. (25,724) (49,522) (31,020)
Production rates and other........... (545) (1,076) (827)
---------- ---------- ----------
Net revisions...................... 292,512 (204,297) (17,740)
Extensions, discoveries and other
additions............................. 29,541 42,882 27,177
Production............................. (57,727) (70,838) (58,219)
Development costs...................... 21,497 41,078 30,497
---------- ---------- ----------
Net change........................... 285,823 (191,175) (18,285)
---------- ---------- ----------
Standardized measure, end of year...... $ 556,637 $ 365,462 $ 347,177
========== ========== ==========
</TABLE>
F-7
<PAGE>
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
March 15, 1999
F-8
<PAGE>
HUGOTON ROYALTY TRUST
STATEMENT OF ASSETS AND TRUST CORPUS
December 31, 1998
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
Cash........................................................... $ 1
Net profits 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
========
</TABLE>
See Accompanying Note to Statement of Assets and Trust Corpus.
F-9
<PAGE>
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 Company conveyed
to the Trust 80% defined net profits interests ("Net Profits Interests") from
certain oil and gas-producing properties in Kansas, Oklahoma and Wyoming
("Underlying Properties") in exchange for 40,000,000 units of beneficial
interest in the Trust ("Units"). The Company filed a registration statement
with the Securities and Exchange Commission in December 1998 and plans to offer
approximately 40% of the Units to the public in March or April 1999.
The Net Profits 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.
Net proceeds received by the Company from the Underlying Properties are paid
to the Trust in the month following the Company's receipt. Accordingly, the
Trust did not receive royalty income and was not allocated production related
to the Net Profits Interests for December 1998.
The Trust will terminate upon the first occurrence of: (a) disposition of all
net profits 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.
2. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)
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%. At December 31, 1998, the posted West Texas Intermediate crude oil
price was $9.50 per barrel and the weighted average spot gas price was $2.01
per Mcf. As the Trust is not subject to taxation at the trust level, no
provision is included for federal income taxes.
Reserve quantities and revenues for the Net Profits Interests were estimated
from projections of reserves and revenues attributable to the Underlying
Properties. Since the Trust has a defined net profits interest, the Trust does
not own a specific ownership percentage of the oil and natural gas reserves or
production quantities. Accordingly, reserves and production allocated to the
Trust pertaining to its 80% net profits interest in the working interest
properties have effectively been reduced to reflect recovery of the Trust's 80%
portion of applicable production and development costs, excluding overhead and
trust administrative expenses. Because Trust reserve quantities are determined
using an allocation formula, any fluctuations in actual or assumed prices or
costs will result in revisions to the estimated reserve quantities allocated to
the Net Profits Interests.
The Net Profits Interests' 80% share of production and development costs are
netted in royalty income received by the Net Profits Interests. Accordingly,
these costs are not shown separately as future costs in calculating the
standardized measure. Only production taxes, calculated at the same rate as
incurred on the underlying properties, is included in future production costs
in calculating the standardized measure.
F-10
<PAGE>
HUGOTON ROYALTY TRUST
NOTES TO STATEMENT OF ASSETS AND TRUST CORPUS--(Continued)
The standardized measure of future net cash flows is not intended to
represent the fair value of the Trust. Numerous uncertainties are inherent in
estimating volumes and values of proved reserves and in projecting future
production rates and timing of development expenditures. Such reserve estimates
are subject to change as additional information becomes available. The reserves
actually recovered and the timing of production may be substantially different
from the original estimates. Also, because natural gas prices are influenced by
seasonal demand, use of year-end prices, as required by the Financial
Accounting Standards Board, may not be representative in estimating future
revenues or reserve data.
<TABLE>
<CAPTION>
Gas (Mcf) Oil (Bbls)
--------- ----------
(in thousands)
<S> <C> <C>
Proved Reserves
Balance, December 31, 1998.............................. 282,297 2,193
======= =====
Proved Developed Reserves
Balance, December 31, 1998.............................. 249,215 1,934
======= =====
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Reserves at December 31, 1998
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
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
========
</TABLE>
F-11
<PAGE>
HUGOTON ROYALTY TRUST
PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)
For the Year Ended December 31, 1998
(in thousands, except for per Unit amounts)
<TABLE>
<CAPTION>
Pro Forma
Adjustments (Note
2)
-------------------
Underlying Other Cash
Properties Costs (a) Basis (b) Pro Forma
---------- --------- --------- ---------
<S> <C> <C> <C> <C>
Revenues:
Gas................................. $73,559 $3,565 $77,124
Oil................................. 6,496 587 7,083
------- ------ -------
Total Revenues..................... 80,055 4,152 84,207
------- ------ -------
Direct Operating Expenses:
Production and property taxes and
transportation..................... 9,069 101 9,170
Production.......................... 12,767 264 13,031
------- ------ -------
Total............................. 21,836 365 22,201
------- ------ -------
Excess of revenues over direct
operating expenses................... $58,219 3,787 62,006
======= ======
Development costs..................... 30,497 2,522 33,019
Overhead.............................. 6,312 (114) 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
=======
</TABLE>
See Accompanying Notes to Unaudited Pro Forma Statement of Distributable
Income.
F-12
<PAGE>
HUGOTON ROYALTY TRUST
NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)
1. BASIS OF PRESENTATION
Hugoton Royalty Trust ("Trust") was created in December 1998 by Cross
Timbers Oil Company ("Company"). The Company conveyed net profits interests
("Net Profits Interests") from the Underlying Properties to the Trust in
exchange for 40 million units of beneficial interest in the Trust.
The pro forma statement of distributable income of the Trust for the year
ended December 31, 1998 has been prepared from the historical statement of
revenues and direct operating expenses of the Underlying Properties, adjusted
to the cash basis, and based on the following assumptions:
a. The Trust was formed and the Net Profits Interests were conveyed to
the Trust prior to December 1, 1997.
b. Net proceeds related to the Net Profits Interests are received and
recorded as royalty income by the Trust in the month following their
receipt by the Company from the Underlying Properties. Generally the Trust
will receive and record royalty income two months after the month of
production. This basis for recognizing royalty income differs from
generally accepted accounting principles which requires that revenues be
accrued in the month of production.
c. Royalty income is calculated based on 80% of the Net Proceeds from the
Underlying Properties. Net Proceeds is a defined term in the Net Profits
Interests conveyances to the Trust.
d. Administrative expense is estimated to be $300,000 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 revenues and
direct operating expenses of the Underlying Properties to present Trust pro
forma distributable income for the year ended December 31, 1998:
a. Historical development costs of $30,497,000 and a Company overhead
charge of $6,312,000 were deducted. The overhead charge is based on a
monthly count of active wells operated by the Company and is specified by
the terms of the Net Profits Interests conveyances to the Trust.
b. Adjustment from the accrual basis to the cash basis of accounting. Pro
forma distributable income for the year ended December 31, 1998 is based on
Net Proceeds received by the Company in December 1997 through November
1998.
3. FEDERAL INCOME TAXES
As a grantor trust, the Trust will not be required to pay federal income
taxes. Accordingly, the accompanying pro forma statement of distributable
income does not include a provision for federal income taxes.
4. 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.
F-13
<PAGE>
HUGOTON ROYALTY TRUST
NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)--(Continued)
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
plaintiffs are seeking an accounting and payment of the monies allegedly owed
to them. 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,
in management's opinion, 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 the Company underpaid
royalties on natural gas produced from federal leases and lands owned by Native
Americans by at least 20% during the past 10 years as a result of mismeasuring
the volume of natural gas and wrongfully analyzing 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 of between $5,000 and $10,000 for each violation of the U.S. False
Claims Act, and an order for the Company to cease the allegedly improper
measuring practices. According to the U.S. Justice Department, 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, in management's opinion, 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 interest, the Trust does
not own a specific ownership percentage of the oil and natural gas reserves or
production quantities. Accordingly, reserves and production allocated to the
Trust pertaining to its 80% net profits interest in the working interest
properties have effectively been reduced to reflect recovery of the Trust's 80%
portion of applicable production and development costs, excluding overhead and
trust administrative expenses. Because Trust reserve quantities are determined
using an allocation
F-14
<PAGE>
HUGOTON ROYALTY TRUST
NOTES TO PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)--(Continued)
formula, any fluctuations in actual or assumed prices or costs will result in
revisions to the estimated reserve quantities allocated to the Net Profits
Interests.
The Net Profits Interests' 80% share of production and development costs are
netted in royalty income received by the Net Profits Interests. Accordingly,
these costs are not shown separately as future costs in calculating the
standardized measure. Only production taxes, calculated at the same rate as
incurred on the underlying properties, is included in future production costs
in calculating the standardized measure.
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.
<TABLE>
<CAPTION>
Gas (Mcf) Oil (Bbls)
--------- ----------
(in thousands)
<S> <C> <C>
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
======= =====
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Reserves at December 31, 1998
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
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
<CAPTION>
(in thousands)
<S> <C>
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
========
</TABLE>
F-15
<PAGE>
UNDERWRITING
Cross Timbers and the underwriters named below have entered into an
underwriting agreement with respect to the trust units being offered. Subject
to certain conditions, each underwriter has severally agreed to purchase the
number of trust units indicated in the following table. Goldman, Sachs & Co.,
Lehman Brothers Inc., 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.
<TABLE>
<CAPTION>
Number of
Underwriter Trust Units
----------- -----------
<S> <C>
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
==========
</TABLE>
If the underwriters sell more trust units than the total number shown in the
table above, the underwriters have an option to buy up to an additional
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.
<TABLE>
<CAPTION>
Paid by Cross Timbers
-------------------------
No Exercise Full Exercise
----------- -------------
<S> <C> <C>
Per trust unit....................................... $ $
Total................................................ $ $
</TABLE>
Trust units sold by the underwriters to the public will initially be offered
at the initial public offering price shown on the cover of this prospectus. Any
trust units sold by the underwriters to securities dealers may be sold at a
discount of up to $ per trust unit from the initial public offering price. Any
such securities dealers may resell any trust units purchased from the
underwriters to certain other brokers or dealers at a discount of up to $ per
trust unit from the initial public offering price. If all the trust units are
not sold at the initial offering price, the representatives may change the
offering price and the other selling terms.
Cross Timbers and its executive officers have agreed with the underwriters
not to dispose of or hedge any of their trust units or securities convertible
into or exchangeable for trust units during the period from the date of this
prospectus continuing through the date 180 days after the date of this
prospectus, except with the prior written consent of the representatives. This
agreement does not apply to any existing employee benefit plans.
U-1
<PAGE>
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.
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 400
beneficial holders to establish at least 1,000,000 trust units in the public
float having a minimum total public market value of $4,000,000.
In connection with the offering, the underwriters may purchase and sell
trust units in the open market. These transactions may include short sales,
stabilizing transactions and purchases to cover positions created by short
sales. Short sales involve the sale by the underwriters of a greater number of
trust units than they are required to purchase in the offering. Stabilizing
transactions consist of certain bids or purchases made for the purpose of
preventing or retarding a decline in the market price of the trust units while
the offering is in progress.
The underwriters also may impose a penalty bid. This occurs when a
particular underwriter repays to the underwriters a portion of the underwriting
discount it received because the representatives repurchased trust units sold
by or for the account of such underwriter in stabilizing or short covering
transactions.
These activities by the underwriters may stabilize, maintain or otherwise
affect the market price of the trust units. As a result, the price of the trust
units may be higher than the price that otherwise might exist in the open
market. If these activities are commenced, they may be discontinued by the
underwriters at any time. These transactions may be effected on the New York
Stock Exchange, in the over-the-counter market or otherwise.
The underwriters do not expect sales to discretionary accounts to exceed
five percent of the total number of trust units offered.
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
<PAGE>
INFORMATION ABOUT
CROSS TIMBERS OIL COMPANY
The trust units are not interests in or obligations of
Cross Timbers Oil Company.
CT-1
<PAGE>
CROSS TIMBERS
Cross Timbers and its subsidiaries engage 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 has grown primarily through acquisitions of proved oil
and natural gas reserves, followed by development activities and strategic
acquisitions of additional interests in or near those acquired properties.
Cross Timbers typically acquires properties that it can develop to increase
production and reserves. Its proved reserves are principally located in fields
with relatively long producing lives and well-established production histories
concentrated in:
. western Oklahoma;
. the East Texas area;
. the Permian Basin of West Texas and New Mexico;
. the Hugoton area of Oklahoma and Kansas;
. the San Juan Basin of northwestern New Mexico;
. the Green River Basin of Wyoming; and
. the Middle Ground Shoal Field of Alaska's Cook Inlet.
Cross Timbers is a Delaware corporation. Its principal executive offices are
located at 810 Houston Street, Fort Worth, Texas 76102, and its telephone
number is (817) 870-2800.
BUSINESS AND PROPERTIES
Historical Development of the Business
Cross Timbers was organized in 1990 to combine the operations of
predecessors, which were formed beginning in 1986. Cross Timbers has grown
primarily by acquiring and developing oil and natural gas properties.
Cross Timbers makes large purchases of producing oil and natural gas
properties as well as smaller, follow-on acquisitions of properties in or near
its producing fields. The following table shows the amount expended and
reserves added by Cross Timbers as the result of acquisitions in each of the
years 1994 through 1998:
<TABLE>
<CAPTION>
Reserves
--------------------------------
Year Costs Bbls of Oil Bcf of Natural Gas
---- ------------- ------------- ------------------
(in millions) (in millions)
<S> <C> <C> <C>
1994.......................... $28 3.8 4.3
1995.......................... 131 3.1 170.7
1996.......................... 106 1.6 153.4
1997.......................... 256 3.2(a) 248.0(a)
1998.......................... 340 16.3 311.3
</TABLE>
- --------
(a) 1997 acquisitions also added 13.9 million Bbls of natural gas liquids.
For additional information regarding Cross Timbers' acquisitions, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" beginning on Page CT-17.
Cross Timbers has significant experience with the organization of royalty
trusts. Its senior management organized the Permian Basin Royalty Trust and the
San Juan Basin Royalty Trust in 1980, while they were with a different company.
Cross Timbers formed the Cross Timbers Royalty Trust in 1991. All three of
these trusts are currently in existence, and their trust units are traded on
the New York Stock Exchange.
CT-2
<PAGE>
In December 1998, Cross Timbers formed the Hugoton Royalty Trust, which will
hold 80% net profits interests in properties located in the Hugoton area of
Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the Green River Basin
of Wyoming. These properties represent approximately 30% of Cross Timbers'
existing reserve base.
In 1998, Cross Timbers announced that it may organize up to two additional
royalty trusts, one for properties in the San Juan Basin area and one for the
Permian Basin area. Doing so will allow Cross Timbers to more efficiently
capitalize its mature properties with stable production and long producing
lives. Cross Timbers will use the proceeds from sales of trust units to reduce
its bank debt. It may also exchange trust units for oil and natural gas
properties or use them for other corporate purposes. After formation of the
royalty trusts, Cross Timbers would continue to apply its historical growth
strategy of acquiring and developing oil and natural gas properties that meet
its acquisition criteria.
Business Strategy and Goals
The primary components of Cross Timbers' business strategy are:
. acquiring oil and natural gas properties with long producing lives;
. increasing production and reserves through aggressive management of
operations and through development and exploration activities; and
. retaining management and technical staff that have substantial
experience in its core areas.
Acquiring Long-Lived, Operated Properties. Cross Timbers seeks to acquire
producing properties with long producing lives that:
. produce from multiple horizons and have the potential for increases in
reserves and production;
. are in its core operating areas or in areas with similar geologic and
reservoir characteristics; and
. present opportunities to reduce expenses, per Mcfe produced, through
more efficient operations.
Cross Timbers also seeks to acquire facilities related to gathering,
processing, marketing and transporting oil and natural gas in areas where it
owns reserves. These facilities can:
. enhance profitability;
. reduce gathering, processing, marketing and transportation costs; and
. provide marketing flexibility and access to additional markets.
Cross Timbers' ability to successfully purchase properties is subject to
competition from other purchasers and the availability of cash resources.
Increasing Production and Reserves. Cross Timbers believes that its
principal properties have geologic and reservoir characteristics that make them
well-suited for production increases through development programs. It has an
inventory of approximately 1,075 potential development drilling locations.
Cross Timbers attributes 585 of these potential drilling locations to proved
undeveloped reserves. Approximately 200 of these locations will require
regulatory approvals and legislation in Oklahoma prior to drilling. Cross
Timbers also reviews operations and mechanical data on its operated properties
to determine if it can reduce operating costs or increase production through:
. adding pipeline compression and pumps to improve production flow;
. opening new producing zones in existing wells;
CT-3
<PAGE>
. deepening existing wells to new producing zones;
. performing mechanical and chemical treatments to stimulate production
rates; and
. drilling additional wells.
Cross Timbers also initiates, upgrades or revises existing secondary recovery
operations.
Business Goals. In May 1998, Cross Timbers announced strategic goals for
1999, including increasing cash flow to $4.00 per share, increasing proved
reserves to 36 Mcfe per share and reducing debt to $.40 per Mcfe of proved
reserves. These goals were based on net commodity prices of $18 per Bbl of oil
and $2.20 per Mcf of natural gas. For 1998, operating cash flow per share was
$1.81, while year-end proved reserves per share were 36.7 Mcfe and debt per
Mcfe was $0.56. While Cross Timbers believes that it was on course with
production and costs to achieve its cash flow goal, current lower commodity
prices make its achievement unlikely in 1999. Its primary 1999 goal is debt
reduction of as much as $300 million. If it achieves this goal, Cross Timbers
will reduce its debt to $.40 to $.45 per Mcfe of proved reserves. Cross Timbers
plans to reduce debt with operating cash flow and proceeds from sales of
royalty trust units, producing properties and equity securities.
Cross Timbers also announced plans to make strategic acquisitions totaling
$150 million from May 1998 through the end of 1999. After closing the Alaska
Cook Inlet properties acquisition in September 1998, the Seagull properties
acquisition in November 1998, and other smaller acquisitions in the last half
of 1998, it has achieved approximately two-thirds of this goal. Cross Timbers
does not anticipate any further significant acquisitions until it has
substantially met its debt reduction goal.
Cross Timbers budgeted $60 million for its 1999 development program. It
expects to fund this program primarily by cash flow from operations.
Exploration expenditures are expected to be less than 5% of the 1999
development budget. Cross Timbers will adjust the total capital budget,
including acquisitions, throughout 1999 depending on oil and natural gas prices
to capitalize on opportunities offering the highest rates of return.
Significant Properties
The following table summarizes proved reserves and discounted present value,
before income tax, of proved reserves by Cross Timbers' major operating areas
at December 31, 1998 (in thousands):
<TABLE>
<CAPTION>
Proved Reserves
-------------------------------- Discounted
Natural Present Value before
Gas Liquids Income Tax of Proved
Oil (Bbls) Gas (Mcf) (Bbls) Reserves
---------- --------- ----------- --------------------
<S> <C> <C> <C> <C>
Permian Basin......... 32,295 95,356 -- $116,816 12.9%
Mid-Continent......... 4,495 189,374 -- 163,282 18.0%
East Texas............ 2,127 317,947 -- 234,825 25.8%
San Juan Basin........ 1,199 253,568 17,174 170,868 18.8%
Hugoton............... 232 159,128 -- 89,745 9.9%
Rocky Mountain........ 2,481 183,830 -- 110,390 12.1%
Alaska Cook Inlet..... 11,437 -- -- 12,719 1.4%
Other (a)............. 244 10,021 -- 9,961 1.1%
------ --------- ------ ----------------
Total................. 54,510 1,209,224 17,174 $908,606 100.0%
====== ========= ====== ================
</TABLE>
- --------
(a) Includes 209,000 Bbls and 8,278,000 Mcf and discounted present value before
income tax of $8,109,000 related to Cross Timbers ownership of
approximately 22% of Cross Timbers Royalty Trust units at December 31,
1998.
CT-4
<PAGE>
Permian Basin Area
Prentice Field. The Prentice Field is located in Terry and Yoakum Counties,
Texas. In 1993 and 1994, Cross Timbers acquired its 91.5% working interest in
the 178-well Prentice Northeast Unit in four separate transactions and assumed
operation of the Unit. Cross Timbers also owns an interest in 80 gross (1.7
net) non-operated wells.
Discovered in 1950, the Prentice Field produces from carbonate reservoirs in
the Clear Fork and Glorieta formations at depths ranging from 6,000 to 7,000
feet. The Prentice Field is separated into several waterflood units for
secondary recovery operations. The Prentice Northeast Unit was formed in 1964
with waterflood operations commencing a year later. Development potential
exists through infill drilling and improvement of water injection well
placement. Tertiary recovery potential also exists through carbon dioxide
flooding.
During 1998, Cross Timbers drilled 1 gross (0.91 net) horizontal sidetrack
in the Prentice Northeast Unit. Cross Timbers is currently studying additional
areas in the Prentice Northeast Unit for future development using horizontal
technology.
Ozona Area. Cross Timbers acquired interests in 1996 in the Henderson,
Ozona, and Davidson Ranch fields located in Crockett County, Texas. It has
interests in 125 gross (73.3 net) wells that it operates and 144 gross (30.2
net) wells operated by others.
Oil and natural gas were first discovered in the Ozona area in 1962.
Production is from the Pennsylvanian Canyon sandstones and Strawn carbonates at
depths ranging from 6,500 to 9,000 feet. Development potential for this area
includes infill drilling, drilling to extend the currently estimated field
boundaries, and possible horizontal drilling in the Strawn Formation.
This area is one of Cross Timbers' most active natural gas development
areas. During 1998, Cross Timbers drilled a total of 18 gross (11.2 net)
operated wells and participated in 3 gross (1.1 net) wells operated by others.
Cross Timbers is currently evaluating 50 locations for possible future
development.
University Block 9. The University Block 9 Field is located in Andrews
County, Texas. Cross Timbers owns a 100% working interest in 64 wells that it
operates.
The University Block 9 Field was discovered in 1953. Productive zones are of
Wolfcamp (at 8,400 feet), Pennsylvanian (at 8,700 feet) and Devonian age (at
10,400 feet). Cross Timbers operates the Wolfcamp Unit, Penn Unit and 33 of the
34 active Devonian wells. Development potential includes opening new producing
zones, infill drilling and improved water injection techniques.
This field was Cross Timbers' most active oil development area during 1998.
Cross Timbers completed 8 horizontal and vertical wells during 1998 and at
year-end had 3 wells in process of completion. It also opened four Devonian
wells into the Pennsylvanian horizon. During 1999, Cross Timbers plans to drill
up to 6 wells, depending on oil prices. Cross Timbers has identified 30 to 40
additional locations for future development by either drilling or horizontal
sidetrack.
Mid-Continent Area
Major County Area. Cross Timbers is one of the largest producers in the
Ringwood, Northwest Okeene and Cheyenne Valley fields in Major County,
Oklahoma. It operates 496 gross (427.4 net) wells and has an interest in 251
gross (52.5 net) wells operated by others. In 1998, Cross Timbers carved an 80%
net profits interest from a substantial portion of these properties and
conveyed the interest to Hugoton Royalty Trust.
CT-5
<PAGE>
Oil and natural gas were first discovered in the Major County area in 1945.
The fields in the Major County area are located in the Anadarko Basin and 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.
Cross Timbers develops the Major County area primarily through mechanical
and chemical treatments to stimulate production rates, opening new producing
zones and drilling additional wells. During 1998, Cross Timbers participated in
the drilling of 18 gross (14.0 net) wells in the western portion of the county,
targeted at the Mississippian and Chester formations. Cross Timbers has
budgeted drilling 9 wells in Major County for 1999.
Cross Timbers operates a gathering system and pipeline in the Major County
area. The gathering system collects natural gas from over 400 wells through 300
miles of pipeline. The gathering system has current throughput of approximately
25,500 Mcf per day, 70% of which is produced from wells operated by Cross
Timbers. Estimated capacity of the gathering system is 40,000 Mcf per day.
Natural gas is delivered to a processing plant owned and operated by a third
party, and then transmitted by a 26-mile pipeline operated by Cross Timbers to
connections with other pipelines.
East Texas Area
Cross Timbers acquired most of its producing properties in East Texas and
northwestern Louisiana in April 1998. These properties produce primarily from
the Travis Peak, Cotton Valley and Rodessa formations between 7,000 feet and
12,000 feet in eight major fields. Oil and natural gas were first discovered in
the East Texas area in the 1930's.
Cross Timbers owns an interest in 620 gross (590 net) wells which it
operates and 123 gross (14.9 net) wells operated by others. Cross Timbers also
owns the related gathering facilities. The East Texas properties also include
more than 12,800 net undeveloped acres located primarily in Anderson County,
Texas.
During 1998, Cross Timbers drilled 10 net wells to the Travis Peak
formation. Most of these wells were in various stages of completion at 1998
year-end. It has identified over 170 drill well locations and over 300 workover
and recompletion projects in this area. Cross Timbers has allocated
approximately one-half of its 1999 development budget to the East Texas area,
including operations on 75 existing wells to restore or increase production and
drilling 20 new wells.
Hugoton Area
Natural gas was discovered in 1922 in the Hugoton area, which is the largest
natural gas producing area in North America. It covers parts of Texas, Oklahoma
and Kansas with an estimated five million productive acres. Cross Timbers owns
an interest in 399 gross (373.9 net) wells that it operates and 86 gross (20.4
net) wells operated by others. In 1998, Cross Timbers carved 80% net profits
interests from a substantial portion of these properties and conveyed the
interests to Hugoton Royalty Trust.
Cross Timbers delivers approximately 70% of its Hugoton natural gas
production to its Tyrone natural gas processing plant. In May 1996, Cross
Timbers significantly increased gathering production through the installation
of a field compressor on the south end of the Tyrone gathering system. It also
completed the installation and start-up of a residue compressor and 11.5 miles
of high
CT-6
<PAGE>
pressure residue pipeline during August 1996. The installation of these
facilities allows Cross Timbers to operate the Tyrone Plant more efficiently
and to gain access to three additional interstate pipelines. During 1998, Cross
Timbers completed the acquisition of approximately 70 miles of low pressure
gathering lines, adding 3,500 Mcf per day to the existing system.
While much of the Kansas portion of the Hugoton area has been infill drilled
on 320-acre spacing, Cross Timbers believes that there remain up to 35
additional potential infill drilling locations. The Oklahoma portion is drilled
on 640-acre spacing. Cross Timbers believes that approximately 200 potential
infill drilling locations exist, subject to regulatory approval and possibly
new legislation being enacted in Oklahoma.
During 1998, Cross Timbers drilled 15 gross (12.0 net) wells to the Chester,
Council Grove and Chase formations. It plans to drill 13 wells during 1999.
Rocky Mountain Area
San Juan Basin. The San Juan Basin of northwestern New Mexico and
southwestern Colorado contains the largest reserves of natural gas in the Rocky
Mountains. Within North America, it is second in size only to the Hugoton area.
Cross Timbers acquired most of its interests in the San Juan Basin in December
1997 from Amoco Corporation. Cross Timbers owns an interest in 644 gross (514.4
net) wells that it operates and 1,384 gross (186.1 net) wells operated by
others. Of these wells, 66 gross (56.2 net) operated wells and 15 gross (2.8
net) non-operated wells produce from two formations.
During 1998, Cross Timbers participated in the drilling of 48 wells,
completed operations on 15 wells to restore or increase production and
installed 78 wellhead compressors. It has identified over 300 drill well
locations and over 100 workover and recompletion projects. During 1999, it
plans to drill 41 wells (23 operated), open new producing zones on 30 wells and
install 40 wellhead compressors.
Green River Basin. The Green River Basin is located in southwestern Wyoming.
Cross Timbers has interests in 174 gross (166.9 net) wells that it operates and
70 gross (9.4 net) wells operated by others in the Fontenelle, Nitchie Gulch
and Pine Canyon fields. In 1998, Cross Timbers carved an 80% net profits
interest from a substantial portion of these properties and conveyed the
interest to Hugoton Royalty Trust.
Natural gas production was discovered in the early 1970's in the Fontenelle
area, whose producing reservoirs are the Cretaceous Frontier and Dakota
sandstones at depths ranging from 7,500 to 10,000 feet. Development potential
for the fields in this area include deepening and opening new producing zones
in existing wells, drilling new wells and adding compression to lower line
pressures.
Cross Timbers drilled 20 net wells in the Fontenelle area in 1998 and plans
to drill approximately 5 wells during 1999.
In 1997, Cross Timbers installed additional field compression to lower
overall field operating pressures and improve overall field performance. It
also completed an interconnect to another pipeline in the southeastern part of
the Fontenelle area that added an additional market for the natural gas.
CT-7
<PAGE>
Alaska Cook Inlet Area
In September 1998, Cross Timbers acquired a 100% working interest in two
State of Alaska leases and the offshore installations located in the Middle
Ground Shoal Field of the Cook Inlet. The properties include two operated
production platforms set in 70 feet of water about seven miles offshore and a
50% interest in operated production pipelines and onshore processing
facilities.
Oil was first discovered in the Cook Inlet in 1966. Production from the 29
operated wells is primarily from multiple zones within the Miocene-Oligocene-
aged Tyonek formation between 7,300 feet and 10,000 feet subsea.
Cross Timbers does not anticipate significant development operations in
1999. It is conducting engineering and geologic studies and plans to implement
development in 2000, depending on oil prices.
Reserves
Cross Timbers' estimated proved reserves at December 31, 1998 were 54.5
million Bbls of oil, 1.2 Bcf of natural gas and 17.2 million Bbls of natural
gas liquids, based on December 31, 1998 prices of $9.50 per Bbl for oil, $2.01
per Mcf for natural gas and $3.99 per Bbl for natural gas liquids.
Approximately 80% of December 31, 1998 proved reserves, computed on a Mcfe
basis, were proved developed reserves. Based on December 31, 1997 prices of
$15.50 per Bbl for oil, $2.20 per Mcf and $11.07 per Bbl for natural gas
liquids, estimated proved reserves at December 31, 1998 would be 65.9 million
Bbls of oil, 1.2 Bcf of natural gas and 17.7 million Bbls of natural gas
liquids. Cross Timbers increased proved reserves during 1998 primarily through
acquisitions of predominantly gas-producing properties and through development
activities.
The following table shows estimated quantities of proved reserves and cash
flows as of December 31, 1996, 1997 and 1998:
<TABLE>
<CAPTION>
December 31
--------------------------------
1996 1997 1998
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>
Proved developed:
Oil (Bbls).............................. 31,883 33,835 42,876
Gas (Mcf)............................... 466,412 677,710 968,495
Natural gas liquids (Bbls).............. -- 11,494 14,000
Proved undeveloped:
Oil (Bbls).............................. 10,557 14,019 11,634
Gas (Mcf)............................... 74,126 138,065 240,729
Natural gas liquids (Bbls).............. -- 2,316 3,174
Total proved:
Oil (Bbls).............................. 42,440 47,854 54,510
Gas (Mcf)............................... 540,538 815,775 1,209,224
Natural gas liquids (Bbls).............. -- 13,810 17,174
Estimated future net cash flows:
Before income tax....................... $1,737,024 $1,484,542 $1,677,426
After income tax........................ $1,286,037 $1,193,167 $1,446,177
Present value of estimated future net cash
flows, discounted at 10%:
Before income tax....................... $ 946,150 $ 782,322 $ 908,606
After income tax........................ $ 706,481 $ 642,109 $ 808,403
</TABLE>
Miller and Lents prepared the estimates of Cross Timbers' proved reserves
and the future net cash flow and present value of cash flow attributable to
proved reserves at December 31, 1996, 1997 and 1998. As prescribed by the SEC,
proved reserves were estimated using oil and natural gas
CT-8
<PAGE>
prices and production and development costs as of December 31 of each year,
without escalation. See Note 14 to Consolidated Financial Statements beginning
on page CTF-1 for additional information regarding estimated proved reserves.
There are numerous uncertainties inherent in estimating quantities of proved
reserves, including many factors beyond the control of Cross Timbers. Reserve
engineering is a subjective process of estimating subsurface accumulations of
oil and natural gas that cannot be measured in an exact manner. The accuracy of
any reserve estimate is a function of the quality of available data and the
interpretation of that data. As a result, estimates by different engineers
often vary, sometimes significantly. In addition, a number of factors may
justify revisions of the estimates. These include physical factors, such as the
results of drilling, testing and production after the date of an estimate, and
economic factors, such as changes in product prices. Accordingly, oil and
natural gas quantities ultimately recovered will vary from reserve estimates.
During 1998, Cross Timbers filed estimates of oil and natural gas reserves
as of December 31, 1997 with the U.S. Department of Energy on Form EIA-23.
These estimates are consistent with the reserve data reported in Note 14 to
Consolidated Financial Statements for the year ended December 31, 1997, with
the exception that Form EIA-23 includes only reserves from properties operated
by Cross Timbers.
Production and Exploration
Cross Timbers' properties have relatively long reserve lives and highly
predictable well production profiles. Based on December 31, 1998 proved
reserves and 1998 production, the average reserve-to-production index of Cross
Timbers' proved reserves is 12.6 years. In general, Cross Timbers' properties
have extensive production histories and production enhancement opportunities.
Cross Timbers' properties are geographically diversified, but the major
producing fields are concentrated within core areas. This concentration allows
Cross Timbers to attain substantial economies of scale in production and to
apply cost-effective reservoir management techniques gained from prior
operations. As of December 31, 1998, Cross Timbers owned interests in 8,901
gross (3,281 net) wells and operated wells representing approximately 87% of
the present value of cash flows before income taxes (discounted at 10%) from
estimated proved reserves. Operating properties allows Cross Timbers to control
expenses, capital allocation and the timing of development activities in its
fields.
During 1998, Cross Timbers' daily production averaged 12,598 Bbls of oil and
229,717 Mcf of natural gas. Fourth quarter 1998 daily production averaged
14,991 Bbls of oil and 265,702 Mcf of natural gas.
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 it owns. 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.
Producing Wells
The following table summarizes Cross Timbers' producing wells as of December
31, 1998, all of which are located in the United States:
<TABLE>
<CAPTION>
Non-
Operated Operated
Wells Wells Total
------------- ----------- -------------
Gross Net Gross Net Gross Net
----- ------- ----- ----- ----- -------
<S> <C> <C> <C> <C> <C> <C>
Oil.................................. 642 589.7 3,595 203.2 4,237 792.9
Gas.................................. 2,480 2,155.4 2,184 333.1 4,664 2,488.5
----- ------- ----- ----- ----- -------
Total................................ 3,122 2,745.1 5,779 536.3 8,901 3,281.4
===== ======= ===== ===== ===== =======
</TABLE>
Two gross (1.5 net) oil wells and 86 gross (60 net) natural gas wells produce
from two formations.
CT-9
<PAGE>
Drilling Activity
The following table summarizes the number of wells drilled by Cross Timbers
during the years indicated. As of December 31, 1998, Cross Timbers was in the
process of drilling 52 gross (33.8 net) wells.
<TABLE>
<CAPTION>
Year Ended December 31
---------------------------------
1996 1997 1998
---------- ----------- ----------
Gross Net Gross Net Gross Net
----- ---- ----- ----- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Development wells:
Completed as--
Oil wells.............................. 92 45.5 82 53.4 53 14.1
Gas wells.............................. 70 38.1 119 85.9 139 63.4
Non-productive........................... 4 2.7 5 3.2 1 --
--- ---- --- ----- --- ----
Total.................................... 166 86.3 206 142.5 193 77.5
--- ---- --- ----- --- ----
Exploratory wells:
Completed as--
Gas wells.............................. -- -- 2 0.6 3 3.0
Non-productive........................... -- -- 1 0.1 2 1.0
--- ---- --- ----- --- ----
Total.................................... -- -- 3 0.7 5 4.0
--- ---- --- ----- --- ----
Total...................................... 166 86.3 209 143.2 198 81.5
=== ==== === ===== === ====
</TABLE>
The total number of wells includes wells drilled on non-operated interests
of 85 gross (10.4 net) wells in 1996, 57 gross (6.9 net) wells in 1997 and 118
gross (14.6 net) wells in 1998. Total wells excludes 21 gross (0.4 net) carbon
dioxide wells drilled on non-operated interests in 1996.
Acreage
The following table summarizes developed and undeveloped leasehold acreage
in which Cross Timbers owns a working interest as of December 31, 1998.
"Developed acres" are acres spaced or assignable to productive wells. This
table excludes acreage in which Cross Timbers' interest is limited to royalty,
overriding royalty and other similar interests.
<TABLE>
<CAPTION>
Developed Undeveloped
----------------- -------------
Gross Net Gross Net
--------- ------- ------ ------
<S> <C> <C> <C> <C>
Oklahoma..................................... 355,303 289,225 15,821 7,143
Texas........................................ 268,264 172,859 36,489 25,041
New Mexico................................... 232,205 172,049 5,094 4,030
Kansas....................................... 80,225 67,951 -0- -0-
Wyoming...................................... 56,583 34,933 2,811 1,906
Other........................................ 41,699 28,737 31,053 23,876
--------- ------- ------ ------
Total........................................ 1,034,279 765,754 91,268 61,996
========= ======= ====== ======
</TABLE>
Certain developed leasehold acreage in Oklahoma and Texas is subject to a
75% net profits interest conveyed to the Cross Timbers Royalty Trust. Certain
developed acreage in Oklahoma, Kansas and Wyoming is subject to an 80% net
profits interest conveyed to the Hugoton Royalty Trust.
CT-10
<PAGE>
Oil and Gas Sales Prices and Production Costs
The following table shows the average sales prices per Bbl of oil
(including condensate), per Mcf of natural gas and per Bbl of natural gas
liquids produced and the production costs and taxes, transportation and other
costs per Mcfe:
<TABLE>
<CAPTION>
Year Ended December
31
--------------------
1996 1997 1998
------ ------ ------
<S> <C> <C> <C>
Sales prices:
Oil (per Bbl)........................................ $21.38 $18.90 $12.21
Gas (per Mcf)........................................ $ 1.97 $ 2.20 $ 2.07
Natural gas liquids (per Bbl)........................ $ -- $ 9.66 $ 7.62
Production costs (per Mcfe)............................ $ 0.67 $ 0.59 $ 0.53
Taxes, transportation and other (per Mcfe)............. $ 0.20 $ 0.22 $ 0.25
</TABLE>
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 wellhead to third parties at the best
available price. 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.
Delivery Commitments
Cross Timbers has contracted to sell to a single purchaser approximately
11,650 Mcf of natural gas per day through May 2000 and 21,650 Mcf of natural
gas per day from June 2000 through July 2005. Cross Timbers generally makes
deliveries under this contract in Oklahoma.
Cross Timbers has committed to sell all natural gas production from certain
properties in the East Texas Basin to EEX Corporation at market prices through
the earlier of December 31, 2001, or until a total of approximately 34.3 Bcf
(27.8 Bcf net to its interest) of natural gas have been delivered. Based on
current production, this sales commitment is approximately 24,700 Mcf (20,000
Mcf net) per day.
Under the terms of its amended purchase and sale agreement with Shell Oil
Company for the Alaska Cook Inlet acquisition, Cross Timbers has committed to
sell to Shell, beginning March 1, 1999, the following minimum daily quantities
of natural gas: 42,000 Mcf in 1999, 40,000 Mcf in 2000, 37,500 Mcf in 2001,
36,500 Mcf in 2002 and 35,000 Mcf in 2003. Cross Timbers must deliver 20,000
Mcf per day of committed sales volumes in the San Juan Basin and the remaining
volumes in the East Texas Basin.
Cross Timbers' production and reserves are adequate to meet the above sales
commitments.
Competition
Cross Timbers competes with other oil and gas companies in:
. acquisition of producing properties and oil and natural gas leases;
. marketing oil and natural gas; and
. obtaining goods, services and labor.
CT-11
<PAGE>
Many competitors have substantially larger financial and other resources than
Cross Timbers. Cross Timbers' ability to make property acquisitions are
affected by availability of funds, availability of information about the
property to be acquired and Cross Timbers' standards for minimum projected
return on investment. Other pipelines and gas gathering systems compete with
Cross Timbers for natural gas delivery. Alternative fuel sources, including
heating oil and other fossil fuels, also provide strong competition to Cross
Timbers. Because of the long-lived nature of Cross Timbers' oil and natural gas
reserves and management's expertise in exploiting these reserves, management
believes that Cross Timbers competes effectively in its markets.
Many factors beyond Cross Timbers' control affect its ability to market oil
and natural gas. These factors include:
. the extent of domestic production and imports of oil and natural gas;
. the proximity of the natural gas production to pipelines;
. the available capacity in those pipelines;
. the demand for oil and natural gas;
. the effects of weather; and
. the effects of state and federal regulation.
Cross Timbers cannot assure that it will always be able to market all of its
production or obtain favorable prices. However, it does not currently believe
that the loss of any of its oil or natural gas purchasers would have a material
adverse effect on its operations.
Regulatory Matters
There have been, and continue to be, numerous federal and state laws and
regulations governing the oil and natural gas industry. These often change in
response to the current political or economic environment. Regulatory
compliance is often difficult and costly, and noncompliance may carry
substantial penalties. The text below discusses some specific regulations that
may affect Cross Timbers. It cannot predict the impact of these or future
legislative or regulatory initiatives.
Federal Regulation of Natural Gas
The Federal Energy Regulatory Commission regulates the interstate
transportation and sale for resale of natural gas. Cross Timbers' gathering
systems and 26-mile pipeline have been declared exempt from the Federal Energy
Regulatory Commission's jurisdiction. Cross Timbers cannot predict the impact
of government regulation on any natural gas facilities.
In 1992, the Federal Energy Regulatory Commission issued Orders Nos. 636 and
636-A that require operators of pipelines to unbundle transportation services
from sales services. This allows customers to pay for only the services they
require, regardless of whether the customer purchases natural gas from the
pipeline operator or from other suppliers. The United States Court of Appeals
upheld the unbundling provisions and other components of the Federal Energy
Regulatory Commission's orders but remanded several issues to that commission
for further explanation. On February 27, 1997, the Federal Energy Regulatory
Commission issued Order No. 636-C, addressing the court's concern. Petitions
for rehearing on Order No. 636-C were denied on May 28, 1998. That order
remains subject to judicial review and may change as a result of that review.
The Federal Energy Regulatory Commission's regulations should generally
facilitate Cross Timbers' transportation of natural gas produced from its
properties and direct access to end-user markets. Cross Timbers, however,
cannot predict the impact of these regulations on marketing its production or
on its natural gas transportation business. Cross Timbers does not believe that
it will be affected any differently than other natural gas producers and
marketers with which it competes.
CT-12
<PAGE>
Federal Regulation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at market prices. The net price received from the sale
of these products is affected by market transportation costs. A significant
part of Cross Timbers' oil production is transported by pipeline. The Energy
Policy Act of 1992 required the Federal Energy Regulatory Commission to adopt a
simplified ratemaking methodology for interstate oil pipelines. In 1993 and
1994, the Federal Energy Regulatory Commission issued Order Nos. 561 and 561-A,
adopting rules that establish new rate methods for oil pipelines. Under those
rules, interstate oil pipelines can change rates based on an inflation index,
though other rate mechanisms may be used in specific circumstances. The United
States Court of Appeals upheld the Federal Energy Regulatory Commission's
orders in 1996. Cross Timbers' cost of transporting oil has not been affected
to any significant extent by these rules.
State Regulation
Various state and local regulations affect oil and natural gas operations.
These regulations include:
. requirements for drilling permits;
. the method of developing new fields;
. spacing and operations of wells; and
. waste prevention.
Production rates may be regulated, and the maximum daily production
allowable from oil and natural gas wells may be established on a market demand
or conservation basis. These regulations may limit production by well and the
number of wells or locations that can be drilled.
Cross Timbers may make agreements relating to the construction or operation
of natural gas pipeline systems. In cases where natural gas is produced,
transported and consumed wholly within one state, the state's administrative
authority that regulates pipelines may have regulatory authority over pipeline
operations. This regulation could cover:
. rates that can be charged for natural gas;
. the transportation of natural gas; and
. the construction and operation of pipelines.
Some states have recently adopted, and other states are considering,
regulations that apply to gathering systems. New regulations have not had a
material effect on its gathering systems, but Cross Timbers cannot predict
whether any further rules will be adopted or, if adopted, the effect of these
rules on its gathering systems.
Federal, State or Indian Leases
Cross Timbers' operations on federal, state or Indian oil and natural gas
leases are subject to numerous restrictions, including nondiscrimination
statutes. Cross Timbers must conduct these operations according to specified
on-site security regulations and other permits and authorizations issued by the
Bureau of Land Management, Minerals Management Service and other agencies.
Environmental Regulations
Various federal, state and local laws regulating the discharge of materials
into the environment, or otherwise relating to the protection of the
environment, directly impact oil and natural gas exploration, development and
production operations. These laws may impact Cross Timbers' operations and
costs. Management believes that Cross Timbers is in substantial compliance with
applicable environmental laws and regulations. To date, it has not expended any
material amounts to
CT-13
<PAGE>
comply with environmental regulations. Management does not currently anticipate
that Cross Timbers' consolidated financial position or results of operations
will be materially adversely affected by future compliance.
Personnel
Cross Timbers employed 521 persons as of December 31, 1998. None of its
employees are represented by a union. Cross Timbers considers its relations
with its employees to be good.
Litigation
On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross
Timbers Oil Company, was filed against Cross Timbers 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 by
reducing royalty payments for improper charges for production, marketing,
gathering, processing and transportation costs. The plaintiffs also allege that
Cross Timbers sold natural gas through affiliated companies at prices less
favorable than those paid by third parties. The plaintiffs are seeking an
accounting and payment of the monies allegedly owed to them. Management
believes Cross Timbers has strong defenses against this claim and intends to
vigorously defend the action. Management's estimate of the potential liability
from this claim has been accrued in Cross Timbers' financial statements.
On October 17, 1997, an action, styled United States of America ex rel.
Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District
Court for the Western District of Oklahoma against Cross Timbers and certain of
its subsidiaries. The plaintiff alleges that Cross Timbers underpaid royalties
on natural gas produced from federal leases and lands owned by Native Americans
by at least 20% during the past 10 years as a result of mismeasuring the volume
of natural gas and incorrectly analyzing 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, along with interest, civil penalties
of between $5,000 and $10,000 for each violation of the U.S. False Claims Act,
and an order for Cross Timbers to cease the allegedly improper measuring
practices. According to the U.S. Justice Department, the lawsuit is one of more
than 75 suits filed nationwide by the same plaintiff alleging similar claims
against over 300 producers and pipeline companies. Cross Timbers has not been
served with this complaint and was not aware of it until the U.S. Justice
Department contacted Cross Timbers in August 1998. Cross Timbers filed a
response with the U.S. Justice Department and is awaiting its decision whether
to intervene in the case. Cross Timbers believes that the allegations of this
lawsuit are without merit and intends to vigorously defend the action.
Cross Timbers and certain of its subsidiaries are involved in various other
lawsuits and certain governmental proceedings arising in the ordinary course of
business. Management does not believe that the ultimate resolution of these
claims, including the lawsuits described above, will have a material effect on
Cross Timbers' financial position, liquidity or operations.
CT-14
<PAGE>
SELECTED FINANCIAL DATA
The following table shows selected historical financial information for the
five years ended December 31, 1998 and pro forma financial information for the
year ended December 31, 1998. Pro forma financial information is as if 1998
acquisitions of producing properties and the sale of 15,000,000 units of the
Hugoton Royalty Trust were consummated immediately prior to period presented.
Significant producing property acquisitions in each of the years presented
affect the comparability of year-to-year financial and operating data. All
weighted average shares and per share data have been adjusted for the three-
for-two stock splits effected in March 1997 and February 1998. This information
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the historical and pro forma
Consolidated Financial Statements.
<TABLE>
<CAPTION>
1998
1994 1995 1996 1997 1998 Pro Forma
--------- ---------- ---------- ---------- ----------- --------------
(in thousands except production, per share and per unit data)
<S> <C> <C> <C> <C> <C> <C>
Consolidated Statement
of Operations Data
Revenues:
Oil and condensate..... $ 53,324 $ 60,349 $ 75,013 $ 75,223 $ 56,164 $ 67,861
Gas and natural gas
liquids............... 38,389 40,543 73,402 110,104 182,587 190,587
Gas gathering,
processing and
marketing............. 4,274 7,091 12,032 9,851 9,438 9,438
Other.................. 288 3,362 888 3,094 1,297 1,297
--------- ---------- ---------- ---------- ----------- -----------
Total Revenues......... $ 96,275 $ 111,345 $ 161,335 $ 198,272 $ 249,486 $ 269,183
========= ========== ========== ========== =========== ===========
Earnings (loss)
available to common
stock.................. $ 3,048 $ (10,538)(a) $ 19,790 $ 23,905 $ (71,498)(b) $ (65,492)(b)
========= ========== ========== ========== =========== ===========
Per common share:
Basic.................. $ 0.09 $ (0.28)(a) $ 0.50 $ 0.60 $ (1.65)(b) $ (1.39)(b)
========= ========== ========== ========== =========== ===========
Diluted................ $ 0.08 $ (0.28)(a) $ 0.48 $ 0.59 $ (1.65)(b) $ (1.39)(b)
========= ========== ========== ========== =========== ===========
Weighted average common
shares outstanding..... 35,829 38,072 39,913 39,773 43,396 46,994
========= ========== ========== ========== =========== ===========
Dividends declared per
common share........... $ 0.13 $ 0.13 $ 0.13 $ 0.15 $ 0.16 $ 0.16
========= ========== ========== ========== =========== ===========
Consolidated Statement
of Cash Flows Data
Cash provided (used) by:
Operating activities... $ 42,293 $ 32,938 $ 59,694 $ 98,006 $ (45,842)
Investing activities... $ (62,745) $ (160,416) $ (124,871) $ (311,322) $ (384,598)
Financing activities... $ 26,232 $ 121,852 $ 66,902 $ 213,195 $ 438,957
Consolidated Balance
Sheet Data at
December 31
Property and equipment,
net.................... $ 244,555 $ 364,474 $ 450,561 $ 723,836 $ 1,051,011 $ 958,361
Total assets............ $ 292,451 $ 402,675 $ 523,070 $ 788,455 $ 1,207,594 $ 1,114,944
Long-term debt.......... $ 142,750 $ 238,475 $ 314,757 $ 539,000 $ 921,000 $ 789,125
Stockholders' equity.... $ 113,333 $ 130,700 $ 142,668 $ 170,243 $ 177,451 $ 216,676
Operating Data
Average daily
production:
Oil (Bbls)............. 9,497 9,677 9,584 10,905 12,598 15,284
Gas (Mcf).............. 58,182 78,408 101,845 135,855 229,717 237,707
Natural gas liquids
(Bbls)................ -- -- -- 220 3,347 3,347
Mcfe................... 115,164 136,470 159,349 202,609 325,390 349,496
Average sales price:
Oil (per Bbl).......... $ 15.38 $ 17.09 $ 21.38 $ 18.90 $ 12.21 $ 12.16
Gas (per Mcf).......... $ 1.81 $ 1.42 $ 1.97 $ 2.20 $ 2.07 $ 2.09
Natural gas liquids
(per Bbl)............. -- -- -- $ 9.66 $ 7.62 $ 7.62
Production costs (per
Mcfe).................. $ 0.77 $ 0.71 $ 0.67 $ 0.59 $ 0.53 $ 0.54
Taxes, transportation
and other (per Mcfe)... $ 0.21 $ 0.17 $ 0.20 $ 0.22 $ 0.25 $ 0.24
Proved reserves:
Oil (Bbls)............. 33,581 39,988 42,440 47,854 54,510 53,301
Gas (Mcf).............. 177,061 358,070 540,538 815,775 1,209,224 1,054,702
Natural gas liquids
(Bbls)................ -- -- -- 13,810 17,174 17,174
Mcfe................... 378,547 597,998 795,178 1,185,759 1,639,331 1,477,552
Other Data
Operating cash flow
(c).................... $ 37,816 $ 40,439 $ 68,263 $ 89,979 $ 78,480
Ratio of earnings to
fixed charges (d)...... 1.5 (0.2)(e) 2.6 2.2 (0.7)(f) (0.7)(f)
</TABLE>
CT-15
<PAGE>
- --------
(a) Includes effect of a $20.3 million pre-tax, non-cash impairment charge
recorded upon adoption of Statement of Financial Accounting Standards No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of.
(b) Includes effect of a $93.7 million pre-tax net loss on investment in equity
securities and a $2 million pre-tax, non-cash impairment charge.
(c) Defined as cash provided by operating activities before changes in current
assets and liabilities. Because of exclusion of changes in current assets
and liabilities, this cash flow statistic is different from cash provided
(used) by operating activities, as is disclosed under generally accepted
accounting principles.
(d) For purposes of calculating this ratio, earnings include income (loss) from
continuing operations before income tax and fixed charges. Fixed charges
include interest expense, the portion of rentals (calculated as one-third)
considered to be representative of the interest factor and preferred stock
dividends.
(e) Includes effect of the charge in (a) above. Excluding the effect of this
charge, the ratio of earnings to fixed charges is 1.3.
(f) Includes effect of the items in (b) above. Excluding the effect of these
items, the ratio of earnings to fixed charges is 0.8.
CT-16
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion and analysis should be read in conjunction with
Selected Financial Data and Cross Timbers' consolidated financial statements.
The following events affect the comparability of results of operations and
financial condition for the years ended December 31, 1996, 1997 and 1998, and
may impact future operations and financial condition. Throughout this
discussion, the term "Mcfe" refers to thousands of cubic feet of gas equivalent
quantities produced for the indicated period, with oil quantities converted to
Mcf on an energy equivalent ratio of one barrel to six Mcf.
Three-for-Two Stock Splits. Cross Timbers effected a three-for-two stock
split on March 19, 1997 and on February 25, 1998. All common stock shares,
treasury stock shares and per share amounts have been retroactively restated to
reflect both stock splits.
1996 Acquisitions. During 1996, Cross Timbers acquired primarily gas-
producing properties for a total cost of $106 million funded primarily by bank
debt. These acquisitions include:
-- The Enserch Acquisition. This acquisition closed in July 1996 at a cost
of $39.4 million and primarily consisted of operated gas-producing
properties in the Green River Basin of southwestern Wyoming. In November
1996, Cross Timbers acquired additional interests in the Fontenelle
Unit, the most significant property included in the Enserch Acquisition,
at a cost of $12.5 million.
-- Gas-producing properties in the Ozona area of the Permian Basin of West
Texas. Cross Timbers acquired these mostly operated interests for $28.1
million.
-- 16% of the publicly traded outstanding units in Cross Timbers Royalty
Trust. Cross Timbers purchased these units at a total cost of $12.8
million from July through December 1996.
1997 Acquisitions. During 1997, Cross Timbers acquired predominantly gas-
producing properties for a total cost of $256 million, funded primarily by bank
borrowings and cash flow from operations. The acquisitions include:
-- The Amoco Acquisition. Cross Timbers purchased these properties in the
San Juan Basin of New Mexico in December 1997 for an estimated adjusted
purchase price of $195 million. This purchase price includes $5.7
million for five-year warrants to purchase 937,500 shares of Cross
Timbers' common stock at $15.31 per share.
-- The Burlington Resources Acquisition. Cross Timbers purchased these
properties in Oklahoma, Kansas and Texas for an estimated adjusted
purchase price of $39 million in May 1997.
-- 6% of the publicly traded outstanding units in Cross Timbers Royalty
Trust, at a cost of $5.4 million.
1998 Acquisitions. During 1998, Cross Timbers acquired oil- and gas-
producing properties for a total cost of $340 million, including:
-- The East Texas Basin Acquisition. Cross Timbers acquired these primarily
gas-producing properties for an estimated purchase price of $245
million, later reduced to $215 million by a $30 million production
payment sold to EEX Corporation. This acquisition closed on April 24,
1998 and was funded by bank debt, partially repaid from proceeds of the
1998 Common Stock Offering.
-- The Alaska Cook Inlet Acquisition. In September 1998, Cross Timbers
acquired these oil-producing properties in exchange for 1,921,850 shares
of Cross Timbers' common stock
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along with certain price guarantees and a non-interest bearing note
payable of $6 million, resulting in an estimated purchase price of $44.4
million.
-- The Seagull Acquisition. This acquisition includes primarily gas-
producing properties in northwest Oklahoma and the San Juan Basin of New
Mexico. Cross Timbers acquired these properties in November 1998 for an
estimated purchase price of $29.2 million, funded by bank borrowings.
1996, 1997 and 1998 Development and Exploration Programs. Oil development
was concentrated in the Prentice Northeast Unit of West Texas during 1996 and
1997, as well as the University Block 9 Field during 1997 and 1998. Gas
development focused on Major County, Oklahoma during 1996, the Ozona Area in
1997 and 1998, the Fontenelle Unit during all three years and the Hugoton Area
during 1998. Exploration activity during 1998 was primarily geological and
geophysical analysis, including seismic studies, of undeveloped properties at
a total cost of $8 million. This work was concentrated in the Silurian Reef of
Illinois, and Texas County and the Nemeha Ridge Area of Oklahoma. Exploratory
expenditures were $2.1 million in 1997 and insignificant in 1996.
1999 Development and Exploration Program. Cross Timbers has budgeted $60
million for its 1999 development and exploration program, which is expected to
be funded primarily by cash flow from operations. Cross Timbers anticipates
exploration will be less than 5% of the 1999 budget. The total capital budget,
including acquisitions, will be adjusted throughout 1999 to capitalize on
opportunities offering the highest rates of return.
1996 Preferred Stock Exchange. In September 1996, stockholders exchanged
2,979,249 shares of common stock for 1,138,729 shares of Series A convertible
preferred stock pursuant to Cross Timbers' exchange offer.
1996 and 1997 Conversion of Subordinated Notes. During November and
December 1996, noteholders converted $27.7 million principal of the 5 1/4%
convertible subordinated notes into 2,696,521 shares of common stock. In
January 1997, noteholders converted the remaining principal of $29.7 million
into 2,892,363 shares of common stock.
1997 Senior Subordinated Note Sales. Cross Timbers sold $125 million of 9
1/4% senior subordinated notes in April 1997 and $175 million of 8 3/4% senior
subordinated notes in October 1997. Net proceeds of $121.1 million and $169.9
million were used to reduce bank debt.
1998 Common Stock Offering. In April 1998, Cross Timbers sold 7,203,450
shares of common stock. Net proceeds of $133.1 million were used to partially
repay bank debt used to fund the East Texas Basin Acquisition.
1998 Issuance of Common Shares. In September 1998, Cross Timbers issued
from treasury stock 1,921,850 common shares to subsidiaries of Shell Oil
Company for the Alaska Cook Inlet Acquisition.
Treasury Stock Purchases. Since May 1996, the Board of Directors has
authorized the purchase of a total of 10.5 million shares of Cross Timbers'
common stock as part of its strategic acquisition plans. Cross Timbers
purchased on the open market 2.9 million shares at a cost of $30.7 million in
1996, 2.4 million shares at a cost of $28 million in 1997 and 4.3 million
shares at a cost of $65.6 million in 1998.
CT-18
<PAGE>
Investment in Equity Securities. Cross Timbers acquired common stock of
publicly traded independent oil and gas producers at a total cost of $16.1
million in 1996, $6.5 million in 1997 and $167.7 million in 1998. For
accounting purposes, Cross Timbers considered equity securities purchased in
1998 to be trading securities, whereas it considered equity securities
purchased prior to 1998 to be available-for-sale securities. Accordingly, Cross
Timbers recognized unrealized investment gains and losses in its 1998 statement
of operations, as opposed to recording as a component of stockholders' equity
in prior years. During 1997, Cross Timbers recognized a gain of $1.7 million on
its investment in equity securities including a gain on sale of securities of
$2.4 million and interest expense of $700,000 related to the investment. During
1998, Cross Timbers recognized a $93.7 million loss on investment in equity
securities, including a loss on sale of securities of $14.8 million, an
unrealized loss of $72.6 million and interest expense of $6.3 million related
to the investment.
Property Sales. Cross Timbers sold producing properties resulting in net
gains of $500,000 in 1996, $1.8 million in 1997 and $800,000 in 1998.
Stock Incentive Compensation. Stock incentive compensation results from
stock appreciation right ("SAR") and performance share awards, and subsequent
changes in Cross Timbers' stock price. During 1996, stock incentive
compensation totaled $6.2 million, which included SAR compensation of $3.7
million (cash payments of $7.1 million, partially offset by prior accruals) and
non-cash performance share compensation of $2.5 million. In 1997, stock
incentive compensation totaled $3.7 million, which included non-cash
performance share compensation of $3.3 million and SAR compensation of
$400,000. During 1998, stock incentive compensation totaled $1.3 million, which
included non-cash performance share compensation of $1.6 million, partially
offset by a reduction in SAR compensation of $300,000. Exercises and
forfeitures under the 1991 Stock Incentive Plan reduced outstanding stock
incentive units (including SARs) from 836,000 at the beginning of 1996 to
18,000 at year-end 1998.
Product Prices. In addition to supply and demand, oil and gas prices are
affected by substantial seasonal, political and other fluctuations Cross
Timbers generally cannot control or predict.
Crude oil prices are generally determined by global supply and demand. After
sinking to a five-year low at the end of 1993, oil prices reached their highest
levels since the 1990 Persian Gulf War during fourth quarter 1996 and January
1997. Crude oil prices ranged from $17 to $20 during most of 1997, then
declined to a $16 average in December. Crude oil prices continued to decline
throughout 1998, dropping to a West Texas Intermediate price of $8.00 per
barrel in December 1998, the lowest level since 1978. This decline is the
result of low demand, as well as the failure of OPEC, at its November 1998
meeting, to further reduce production quotas. Low demand has been caused by
warmer than normal winter temperatures and a slower than expected recovery in
Asian economies. Based on 1998 production, Cross Timbers estimates that a $1.00
per barrel increase or decrease in the average oil sales price would result in
approximately a $4.4 million change in 1999 annual operating cash flow.
Natural gas prices are influenced by national and regional supply and
demand, which is often dependent upon weather conditions. Specific gas prices
are also based on the location of production, pipeline capacity, gathering
charges and the energy content of the gas. Generally because of colder weather,
storage concerns and U.S. economic growth, prices remained relatively high
during most of 1996 and 1997, reaching their highest levels since 1985. Gas
prices declined, however, in December 1997 and, except for a rebound during the
summer, have remained lower throughout 1998. Lower gas prices have been
primarily because the winters of 1997-1998 and 1998-1999 in the central and
eastern U.S. were abnormally mild. Cross Timbers has entered into commodity
price hedging instruments to reduce its exposure to gas price fluctuations. As
a result of these commodity hedging
CT-19
<PAGE>
instruments, Cross Timbers' average gas price increased from $1.97 to $2.07 in
1998 and decreased from $2.24 to $2.20 in 1997. Based on 1998 production, Cross
Timbers estimates that a $0.10 per Mcf increase or decrease in the average gas
sales price would result in approximately a $7.7 million change in 1999 annual
operating cash flow.
Impairment Provision. During 1998, the Company recorded an impairment
provision on producing properties of $2 million before income tax. This
impairment provision was determined based on an assessment of recoverability of
net property costs from estimated future net cash flows from those properties.
Estimated future net cash flows are based on management's best estimate of
projected oil and gas reserves and prices. If oil and gas prices remain at
lower levels or decline further, the Company may be required to record
impairment provisions in the future, which may be material.
Results of Operations
1998 Compared to 1997
For the year 1998, loss available to common stock was $71.5 million compared
with earnings of $23.9 million for 1997. The 1998 loss includes a $93.7 million
loss ($61.8 million after tax) on investment in equity securities and a $2
million ($1.3 million after tax) impairment write-down of producing properties.
The remaining decline in earnings is primarily the result of lower product
prices and increased interest related to the 1998 acquisitions and treasury
stock purchases.
Revenues for 1998 were $249.5 million, or 26% above 1997 revenues of $198.3
million. Even though oil production increased by 16%, oil revenue decreased
$19.1 million or 25% because of a 35% decrease in oil prices from an average of
$18.90 in 1997 to $12.21 in 1998 (see "Product Prices" above). Increased
production was primarily because of the 1998 acquisitions.
Gas revenue increased $72.5 million or 66% because of a 69% increase in
production partially offset by a 6% price decrease (see "Product Prices"
above). Increased gas production was attributable to the 1997 and 1998
acquisitions and development programs. Gas revenues for 1998 also included $9.3
million from San Juan Basin natural gas liquids production attributable to the
December 1997 Amoco Acquisition.
Gas gathering, processing and marketing revenues decreased $400,000
primarily because of decreased wellhead volumes and lower gas and natural gas
liquids prices, partially offset by increased margin. Other revenues were $1.8
million lower primarily because of decreased net gains on sale of properties
and decreased lawsuit settlement receipts.
Expenses for 1998 totaled $209.2 million as compared with total 1997
expenses of $134.8 million. Most expenses increased in 1998 primarily because
of the 1997 and 1998 acquisitions and exploration and development programs.
Production expense increased $19.6 million or 45%. Per Mcfe, production
expense decreased from $0.59 to $0.53. This decrease is primarily because of
the lower operating costs of gas-producing properties acquired in 1997 and
1998, the timing of workovers and operating efficiencies initiated after
acquiring operated properties. Exploration expenses for 1998 totaled $8 million
and were predominantly geological and geophysical costs, including seismic
analysis, related to the 1998 exploration program. Exploration costs in 1997
totaled $2.1 million.
Taxes on production and property, transportation and other deductions
increased 77% or $12.7 million because of increased oil and gas revenues, as
well as increased property taxes related to the 1997 and 1998 acquisitions.
Taxes, transportation and other per Mcfe increased 14% from $0.22 to $0.25
because of increased transportation, compression and other charges related to
acquisitions.
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<PAGE>
Depreciation, depletion and amortization ("DD&A") increased $35.8 million,
or 75%, primarily because of the 1997 and 1998 acquisitions and development
programs. On an Mcfe basis, DD&A increased from $0.65 in 1997 to $0.70 in 1998
primarily because of the higher cost per Mcfe of the 1998 acquisitions.
General and administrative expense decreased $2.3 million, or 15%, because
of a $2.4 million decrease in stock incentive compensation, partially offset by
increased expenses from company growth. Excluding stock incentive compensation,
general and administrative expense per Mcfe decreased to $0.10 in 1998 from
$0.16 in 1997. This reduction resulted from production growth outpacing company
personnel requirements and other administrative expenses.
Interest expense increased $26.1 million or 100% primarily because of a
comparable increase in weighted average borrowings to partially fund the 1997
and 1998 acquisitions and treasury stock purchases, combined with a 1% increase
in the weighted average interest rate and amortization of loan fees. Interest
related to investment in equity securities has been classified as part of the
loss on investment in equity securities. Interest expense per Mcfe increased
from $0.35 in 1997 to $0.44 in 1998 primarily as the result of an increase in
the weighted average borrowings to fund treasury stock purchases.
1997 Compared to 1996
Earnings available to common stock for 1997 were $23.9 million as compared
with $19.8 million for 1996. Improved earnings were primarily the result of
higher gas prices and increased gas production from the 1996 and 1997
acquisitions and development programs. Results included the effects of stock
incentive compensation of $3.7 million in 1997 and $6.2 million in 1996. Also
included in 1997 results were a $1.7 million gain on investment in equity
securities, a gain of $1.8 million on sale of properties and lawsuit settlement
proceeds of $1.3 million. A $500,000 gain on sale of properties was included in
1996 results. Dividends on preferred stock issued in September 1996 reduced
1997 earnings by $1.8 million and 1996 earnings by $500,000.
Revenues for 1997 were $198.3 million, or 23% above 1996 revenues of $161.4
million. Oil revenue remained constant as a 13% increase in oil production was
offset by a 12% decrease in oil prices from an average of $21.38 in 1996 to
$18.90 in 1997 (see "Product Prices" above). Increased production was primarily
because of the 1997 acquisitions and development programs.
Gas revenue increased $36.7 million or 50% because of a 33% increase in
production combined with a 12% price increase (see "Product Prices" above).
Increased gas production was attributable to the 1996 and 1997 acquisitions and
development programs. Gas revenues for 1997 also included $800,000 from San
Juan Basin natural gas liquids production attributable to the December 1997
Amoco Acquisition.
Gas gathering, processing and marketing revenues decreased $2.2 million
primarily because of a decrease in margin and gas volumes. Other revenues
increased $2.2 million primarily because of increased net gains on sale of
properties and lawsuit settlement proceeds received in 1997.
Expenses for 1997 totaled $134.8 million as compared with total 1996
expenses of $113.3 million. All expenses other than general and administrative
expense increased in 1997 primarily because of the 1996 and 1997 acquisitions
and exploration and development programs.
Production expense increased $4.2 million or 11%. Production expense per
Mcfe decreased from $0.67 to $0.59. This decrease is primarily because of the
lower operating costs of gas-producing properties acquired in 1996 and 1997,
the timing of workovers and operating efficiencies initiated after acquiring
operated properties. Exploration expenses for 1997 totaled $2.1 million, and
CT-21
<PAGE>
were predominantly geological and geophysical costs related to the 1997
exploration program. Exploration costs in 1996 and prior were included in
production expense since not significant.
Taxes on production and property, transportation and other deductions
increased 37% or $4.5 million because of increased oil and gas revenues, as
well as increased property taxes related to the 1996 and 1997 acquisitions.
Taxes, transportation and other per Mcfe increased 10% from $0.20 to $0.22
because of increased gas prices and higher property tax rates.
DD&A increased $9.9 million, or 26%, primarily because of the 1996 and 1997
acquisitions and development programs. On an Mcfe basis, DD&A remained
relatively flat at $0.65 for 1996 and 1997.
General and administrative expense decreased $600,000, or 4%, because of a
$2.5 million decrease in stock incentive compensation, partially offset by
increased expenses from company growth. Excluding stock incentive compensation,
general and administrative expense per Mcfe was $0.16 for 1997 as compared with
$0.17 for 1996.
Gas gathering and processing expense increased $1.6 million or 23%. This
increase was primarily because of rental expense related to the Tyrone plant
and gathering system lease that began in March 1996 and the Major County,
Oklahoma gathering system lease that began in November 1996. This increase
offsets related decreases in DD&A and interest.
Interest expense increased $9.9 million or 61% because of a 36% increase in
weighted average borrowings to partially fund the 1996 and 1997 acquisitions
and purchases of treasury stock, combined with a 20% increase in the weighted
average interest rate primarily attributable to the senior subordinated notes
sold in April and October 1997. Interest expense per Mcfe increased from $0.28
in 1996 to $0.35 in 1997, primarily because of an increase in the weighted
average interest rate, as well as the result of increased bank debt to finance
treasury stock purchases.
Liquidity and Capital Resources
Cross Timbers' primary sources of liquidity are cash flow from operating
activities, producing property sales, including sales of royalty trust units,
public offerings of equity and debt, and bank debt. Other than for operations,
Cross Timbers' cash requirements are generally for the acquisition, exploration
and development of oil and gas properties, and debt and dividend payments.
Cross Timbers believes that its sources of liquidity are adequate to fund its
1999 cash requirements.
Cash provided by operating activities was $59.7 million in 1996 and $98
million in 1997, compared with cash used by operations of $45.8 million in
1998. The fluctuation from 1997 to 1998 was primarily because of decreased
product prices and purchases of equity securities, net of sales. Before changes
in working capital, cash flow from operations was $68.3 million in 1996, $90
million in 1997 and $78.5 million in 1998.
The 1996 and 1997 acquisitions were primarily financed by long-term debt.
The 1998 acquisitions were funded by a combination of bank borrowings, proceeds
from a public offering of common stock and the issuance of common stock.
Exploration and development expenditures and dividend payments have generally
been funded by cash flow from operations.
Financial Condition
Total assets increased 53% from $788 million at December 31, 1997 to $1.2
billion at December 31, 1998, primarily because of the 1998 acquisitions. As of
December 31, 1998, total capitalization of Cross Timbers was $1.1 billion, of
which 84% was long-term debt. This compares with capitalization of $709 million
at December 31, 1997, of which 76% was long-term debt. The increase in the
debt-to-capitalization ratio from year-end 1997 to 1998 is because of increased
CT-22
<PAGE>
borrowings under Cross Timbers' loan agreement to fund the 1998 acquisitions,
purchases of equity securities and other capital expenditures (see "Financing"
below).
Working Capital
Cross Timbers generally uses available cash to reduce bank debt and,
therefore, does not maintain large cash and cash equivalent balances. Short-
term liquidity needs are satisfied by bank commitments under the loan agreement
(see "Financing" below). Because of this, and since Cross Timbers' principal
source of operating cash flows (i.e., proved reserves to be produced in the
following year) cannot be reported as working capital, Cross Timbers often has
low or negative working capital. Working capital of $38 million at December 31,
1998 is primarily attributable to the investment in equity securities and the
related deferred tax benefit.
Financing
On November 16, 1998, Cross Timbers entered into a new Revolving Credit
Agreement with commercial banks. As of December 31, 1998, Cross Timbers had a
borrowing base and commitment of $615 million with no unused borrowing capacity
under the loan agreement. The interest rate on borrowings at December 31, 1998
was 6.9%. Cross Timbers periodically renegotiates the loan agreement to
increase the borrowing commitment and extend the revolving facility; however,
Cross Timbers cannot assure that it can continue to do so in the future. Cross
Timbers' goal in 1999 is to reduce debt by as much as $300 million, resulting
in debt of 40 to 45 cents per Mcfe of proved reserves.
The borrowing base is redetermined annually based on the value and expected
cash flow of Cross Timbers' proved oil and gas reserves. If borrowings exceed
the redetermined borrowing base, the banks may require that the excess be
repaid within a year. Otherwise, borrowings under the loan agreement do not
mature until June 30, 2003, but may be prepaid at any time without penalty. The
borrowing base is scheduled to be redetermined in June 1999. Based on year-end
proved reserves, Cross Timbers does not expect a reduction in the borrowing
base upon its redetermination.
Other financing activities in 1996, 1997 and 1998 included the 1996
preferred stock exchange, 1996 and 1997 conversion of subordinated notes, 1997
senior subordinated note sales, 1998 common stock offering and 1998 issuance of
common shares. These transactions are described in detail above.
Capital Expenditures
In May 1998, Cross Timbers announced plans to make strategic acquisitions
totaling $150 million from May 1998 through the end of 1999. After closing the
Alaska Cook Inlet Acquisition in September, the Seagull Acquisition in November
and other smaller acquisitions in the last half of 1998, Cross Timbers achieved
approximately two-thirds of this goal. Cross Timbers does not expect to make
further significant acquisitions until substantially meeting its debt reduction
goal. Cross Timbers plans to fund any future acquisitions through a combination
of cash flow from operations and proceeds from bank debt, public equity or debt
transactions.
In 1998, exploration and development cash expenditures totaled $77.4 million
compared with the budget of $90 million. In 1997, exploration and development
cash expenditures totaled $90.5 million, compared with the budget of $70
million. Cross Timbers has budgeted $60 million for the 1999 development
program. As it has done historically, Cross Timbers expects to fund the 1999
development program with cash flow from operations. Since there are no material
long-term commitments associated with this budget, Cross Timbers has the
flexibility to adjust its actual development expenditures in response to
changes in product prices, industry conditions, and the effects of Cross
Timbers' acquisition and development programs.
CT-23
<PAGE>
A minor portion of Cross Timbers' existing properties are operated by third
parties which control the timing and amount of expenditures required to exploit
Cross Timbers' interests in such properties. Therefore, Cross Timbers cannot
assure the timing or amount of these expenditures.
To date, Cross Timbers has not spent significant amounts to comply with
environmental or safety regulations, and it currently does not expect to do so
during 1999. However, developments such as new regulations, enforcement
policies or claims for damages could result in significant future costs.
Dividends
The Board of Directors declared quarterly dividends of $0.033 per common
share since Cross Timbers' inception through 1996, $0.037 per common share in
1997 and $0.04 per common share in 1998. In February 1999, the Board reduced
the quarterly dividend to $0.01 per common share because of Cross Timbers'
current focus on debt reduction. Cross Timbers' ability to pay dividends is
dependent upon available cash flow, as well as other factors. In addition, the
loan agreement restricts the amount of common stock dividends to 25% of
operating cash flow for the last four quarters.
Cumulative dividends on Series A convertible preferred stock are paid
quarterly, when declared by the Board of Directors, based on an annual rate of
$1.5625 per share, or $1.8 million annually.
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. Continuity
of Cross Timbers' operations in January 2000 will not only depend upon Year
2000 compliance of Cross Timbers' computer systems and computer-controlled
equipment, but also compliance of computer systems and computer-controlled
equipment of third parties. These third parties include oil and natural gas
purchasers and significant service providers such as electric utility companies
and natural gas plant, pipeline and gathering system operators.
Cross Timbers is in the process of reviewing its computer systems and
computer-controlled field equipment and making the necessary modifications for
Year 2000 compliance. Cross Timbers has completed modifications and testing of
its primary accounting and land computer programs. The remaining computer
systems have been inventoried and assessed. Cross Timbers expects to complete
remediation and testing of significant remaining systems by August 1999.
Some of Cross Timbers' critical field equipment, such as natural gas
compressors, are partially controlled or regulated by embedded computer chips.
Based on a preliminary review of all operating areas, Cross Timbers has
identified no significant compliance exceptions. Cross Timbers has inventoried
approximately 30% of field equipment in operated areas and expects to complete
its review of the remaining 70% of field equipment inventories by April 1999.
Cross Timbers plans to complete remediation and testing of identified
exceptions for significant computer-controlled field equipment by August 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
and computer-controlled equipment for Year 2000 compliance represents a
material risk to Cross Timbers. Cross Timbers estimates that total costs
related to Year 2000 compliance efforts will be less than $500,000 of which
approximately $50,000 has been incurred and expensed through December 1998.
Cross Timbers has identified significant third parties whose Year 2000
compliance could affect Cross Timbers and is in the process of formally
inquiring about their Year 2000 status. Cross Timbers has received responses to
approximately 30% of its inquiries. Approximately 90% of
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<PAGE>
respondents have indicated that they will be Year 2000 compliant by January 1,
2000. Despite its efforts to assure that such third parties are Year 2000
compliant, Cross Timbers cannot provide assurance that all significant third
parties will achieve compliance in a timely manner. A third party's failure to
achieve Year 2000 compliance could have a material adverse effect on Cross
Timbers' operations and cash flow. The potential effect of Year 2000 non-
compliance by third parties is currently unknown.
Cross Timbers is currently identifying appropriate contingency plans in the
event of potential problems resulting from failure of Cross Timbers' or
significant third party computer systems on January 1, 2000. Cross Timbers has
not completed any contingency plans to date. Specific contingency plans will be
developed in response to the results of testing scheduled to be complete by
August 1999, as well as the assessed probability and risk of system or
equipment failure. These contingency plans may include installing backup
computer systems or equipment, temporarily replacing systems or equipment with
manual processes, and identifying alternative suppliers, service companies and
purchasers. Cross Timbers expects these plans to be complete by October 1999.
New Accounting Standards
Cross Timbers adopted the following pronouncements in 1998:
-- SFAS No. 130, "Reporting Comprehensive Income" requires that all items
that are to be recognized under accounting standards as components of
comprehensive income be reported in a financial statement that is
displayed with the same prominence as other financial statements, and
-- SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information" requires reporting of financial and descriptive information
about a company's reportable operating segments. Cross Timbers has
identified only one operating segment, which is the exploration and
production of oil and gas.
Cross Timbers will be required to comply with the provisions of SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities" which must
be adopted for fiscal years beginning after June 15, 1999. SFAS No. 133
requires that derivatives be reported on the balance sheet at fair value and,
if the derivative is not designated as a hedging instrument, changes in fair
value must be recognized in earnings in the period of change. If the derivative
is designated as a hedge and to the extent such hedge is determined to be
effective, changes in fair value are either offset by the change in fair value
of the hedged asset or liability (if applicable) or reported as a component of
other comprehensive income in the period of change, and subsequently recognized
in earnings when the offsetting hedged transaction occurs. The definition of
derivatives has also been expanded to include contracts that require physical
delivery of oil and gas if the contract allows for net cash settlement. Cross
Timbers primarily uses derivatives to hedge product price and interest rate
risks. These derivatives are recorded at cost, and gains and losses on such
derivatives are reported when the hedged transaction occurs. Accordingly,
adoption of SFAS No. 133 will have an impact on the reported financial position
of Cross Timbers, and although such impact has not been determined, it is
currently not believed to be material. Adoption of SFAS No. 133 should have no
significant impact on reported earnings, but could materially affect
comprehensive income.
Production Imbalances
Cross Timbers has gas production imbalance positions that are the result of
partial interest owners selling more or less than their proportionate share of
gas on jointly owned wells. Imbalances are generally settled by
disproportionate gas sales over the remaining life of the well or by cash
payment by the overproduced party to the underproduced party. Cross Timbers
uses the entitlement method of accounting for natural gas sales. At December
31, 1998, Cross Timbers' consolidated balance sheet includes a net receivable
of $4.9 million for a net underproduced balancing position of 885,000 Mcf of
natural gas and 7,909,000 Mcf of carbon dioxide. Production imbalances do not
have, and are not expected to have, a significant impact on Cross Timbers'
liquidity or operations.
CT-25
<PAGE>
Forward-Looking Statements
Certain information included in this Prospectus and other materials filed by
Cross Timbers with the SEC contain forward-looking statements relating to Cross
Timbers' operations and the oil and gas industry. Such forward-looking
statements are based on management's current projections and estimates and are
identified by words such as "expects," "intends," "plans," "projects,"
"anticipates," "believes," "estimates" and similar words. These statements are
not guarantees of future performance and involve certain risks, uncertainties
and assumptions that are difficult to predict. Therefore, actual results may
differ materially from what is expressed or forecasted in such forward-looking
statements.
Among the factors that could cause actual results to differ materially are:
-- crude oil and natural gas price fluctuations;
-- Cross Timbers' ability to acquire oil and gas properties that meet its
objectives and to identify prospects for drilling;
-- potential delays or failure to achieve expected production from existing
and future exploration and development projects;
-- potential disruption of operations because of failure to achieve timely
Year 2000 compliance by Cross Timbers or others with whom it has
material relationships; and
-- potential liability resulting from pending or future litigation.
In addition, these forward-looking statements may be affected by general
domestic and international economic and political conditions.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Cross Timbers only uses derivative financial instruments for hedging
purposes. These instruments principally include interest rate swap agreements
and commodity futures, swaps, and option agreements. These financial and
commodity-based derivative contracts are used to limit the risks of interest
rate fluctuations and natural gas and crude oil price changes. Gains and losses
on these derivatives are entirely offset by losses and gains on the respective
hedged exposures.
The Board of Directors has adopted a policy governing the use of derivative
instruments, which requires that all derivatives used by Cross Timbers relate
to an underlying, offsetting position, anticipated transaction or firm
commitment. The policy prohibits the use of speculative, highly complex or
leveraged derivatives. The policy also requires review and approval by the
Executive Vice President of all risk management programs using derivatives and
all derivative transactions. These programs are also periodically reviewed by
the Board of Directors.
Hypothetical changes in interest rates and prices chosen for the estimated
sensitivity effects are considered to be reasonably possible near-term changes
generally based on consideration of past fluctuations for each risk category.
It is not possible to accurately predict future changes in interest rates,
product prices and investment market values. Accordingly, these hypothetical
changes may not necessarily be an indicator of probable future fluctuations.
Interest Rate Risk
Cross Timbers is exposed to interest rate risk on short-term and long-term
debt carrying variable interest rates. Cross Timbers' variable rate debt was
approximately $620 million at December 31, 1998. Cross Timbers attempts to
balance the benefit of lower cost variable rate debt that has inherent
increased risk with more expensive fixed rate debt that has less market risk.
This is
CT-26
<PAGE>
accomplished through a mix of bank debt with short-term variable rates and
fixed rate subordinated debt, as well as the use of interest rate swaps. During
1998, Cross Timbers entered into interest rate swap agreements that effectively
convert interest rates from variable to fixed on $150 million principal through
September 2005. Cross Timbers had no outstanding interest swap agreements
during 1997.
The following table shows the carrying amount and fair value of long-term
debt and interest rate swaps, and the hypothetical change in fair value that
would result from a 100-basis point change in interest rates:
<TABLE>
<CAPTION>
Hypothetical
Carrying Fair Change in
Amount Value Fair Value
--------- --------- ------------
(in thousands)
<S> <C> <C> <C>
December 31, 1997
Long-term debt.......................... $(539,000) $(538,288) $(20,656)
December 31, 1998
Long-term debt.......................... (921,000) (894,750) (17,000)
Interest rate swaps..................... -- (2,722) (8,655)
</TABLE>
In February and March 1999, Cross Timbers terminated its interest rate swaps
on notional balances totaling $100 million, resulting in proceeds received and
a gain of $1.1 million. This gain will be amortized against interest expense
through September 2005. In February 1999, Cross Timbers sold a call option that
allows the counterparty to terminate the interest rate swap in September 2001
on the remaining $50 million notional balance, resulting in proceeds received
of $800,000. This amount will be deferred until the option is exercised or
expires.
Commodity Price Risk
Cross Timbers hedges a portion of the market risks associated with its crude
oil and natural gas sales. During 1998, Cross Timbers primarily entered into
gas futures contracts and gas basis swap agreements to reduce exposure to price
volatility in the physical markets. As of December 31, 1998, outstanding
futures contracts had a fair value of a gain of $3.5 million and outstanding
basis swap agreements had a fair value of a loss of $0.7 million. These futures
contracts and basis swap agreements are not recorded on Cross Timbers' balance
sheet. Cross Timbers did not have any significant commodity hedging activity in
1997.
For these commodity derivatives that are permitted to be settled in cash or
another financial instrument, sensitivity effects are as follows. At year-end
1998, the aggregate effect of a hypothetical 10% change in natural gas prices
and basis would result in a $3 million change in the fair value of these
financial instruments. This sensitivity does not include the effects of gas
contracts that cannot be settled in cash or another financial instrument. See
Note 6 to Consolidated Financial Statements.
Investment in Equity Securities
Cross Timbers is subject to price risk on its unhedged portfolio of publicly
traded investments in equity securities of energy companies. These securities
were classified as trading securities as of year-end 1998. The fair value of
these securities at December 31, 1998 was $44.4 million. At year-end 1998, a
25% appreciation or depreciation in equity price would increase or decrease
portfolio fair value and pre-tax earnings by approximately $11 million. As of
March 1, 1999, Cross Timbers had incurred a 1999 pre-tax loss on its investment
in equity securities of $8 million, of which $17.5 million was a realized loss,
partially offset by a $9.5 million decrease in unrealized loss.
CT-27
<PAGE>
MANAGEMENT
Directors and Executive Officers
Cross Timbers' Board of Directors consists of six members, divided into
three classes. The members of each class serve three-year terms which expire at
the third following annual meeting of shareholders. Executive officers are
elected annually and serve at the discretion of the Board of Directors. The
following table provides information regarding the directors and executive
officers of Cross Timbers:
<TABLE>
<CAPTION>
Term as
Director
Name Age Position Expires
---- --- -------- --------
<C> <C> <S> <C>
J. Luther King, Jr. ........ 58 Director 2000
Jack P. Randall ............ 49 Director 2002
Scott G. Sherman ........... 65 Director 2001
Bob R. Simpson ............. 50 Chairman of the Board, Chief 2001
Executive Officer and Director
Steffen E. Palko ........... 48 Vice Chairman, President and 2000
Director
J. Richard Seeds ........... 53 Executive Vice President and 1999
Director
Louis G. Baldwin ........... 49 Senior Vice President
and Chief Financial Officer
Senior Vice President--Asset
Keith A. Hutton ............ 40 Development
Senior Vice President and
Bennie G. Kniffen .......... 48 Controller
Senior Vice President--
Larry B. McDonald .......... 52 Operations
Senior Vice President--
Timothy L. Petrus .......... 44 Acquisitions
Senior Vice President of
Kenneth F. Staab ........... 42 Engineering
Senior Vice President--
Thomas L. Vaughn ........... 52 Operations
Vaughn O. Vennerberg II .... 44 Senior Vice President--Land
</TABLE>
Background of Directors and Executive Officers
J. Luther King, Jr. has been a director of Cross Timbers since 1991. Since
1979, Mr. King has served as President, Principal and Portfolio Manager/Analyst
of Luther King Capital Management Corporation, an investment management firm of
which Mr. King is the majority shareholder. Previously, he was Vice President
and Director of Lionel D. Edie & Company, an investment management firm.
Jack P. Randall has been a director of Cross Timbers since August 1997. He
is a co-founder of Randall & Dewey, Inc., an oil and gas consulting firm, and
has served as its president since 1989. From 1975 to 1989, he was employed with
Amoco Production Company where he served as Manager of Acquisitions and
Divestitures for seven years.
Scott G. Sherman has been a director of Cross Timbers since 1990. He has
been the sole owner of Sherman Enterprises, a personal investment firm, for the
past 12 years. Previously, Mr. Sherman owned and operated Eaglemotive
Industries, an automotive parts manufacturing company, for 18 years.
CT-28
<PAGE>
Bob R. Simpson has been a director of Cross Timbers since 1990. A co-founder
of Cross Timbers with Mr. Palko, Mr. Simpson has served as Chairman since July
1, 1996 and as Chief Executive Officer or similar positions with Cross Timbers
and its predecessors since 1986. He served as Vice President of Finance and
Corporate Development of Southland Royalty Company from 1979 to 1986 and as Tax
Manager of Southland Royalty Company from 1976 to 1979.
Steffen E. Palko has been a director of Cross Timbers since 1990. A co-
founder of Cross Timbers with Mr. Simpson, Mr. Palko has served as Vice
Chairman and President or similar positions with Cross Timbers and its
predecessors since 1986. He served as Vice President--Reservoir Engineering of
Southland Royalty Company from 1984 to 1986 and as Manager of Reservoir
Engineering of Southland Royalty Company from 1982 to 1984.
J. Richard Seeds has been a director of Cross Timbers since July 1996. Since
May 1997, Mr. Seeds has served as Executive Vice President. From August 1993 to
May 1997, he was Career Guidance Counselor with the Springtown Independent
School District. Mr. Seeds was an independent personal investment manager and a
consultant to the San Juan Basin Royalty Trust, the Permian Basin Royalty Trust
and the Cross Timbers Royalty Trust from 1986 to 1993. He served as Vice
President of Finance and Controller of Southland Royalty Company from 1979 to
1986 and as Controller of Southland Royalty Company from 1977 to 1979.
Louis G. Baldwin has served as Senior Vice President and Chief Finance
Officer or similar positions with Cross Timbers and its predecessors since
1986. He served as Assistant Treasurer of Southland Royalty Company from 1979
to 1986 and as Financial Analyst of Southland Royalty Company from 1976 to
1979.
Keith A. Hutton served as Senior Vice President--Asset Development or
similar positions with Cross Timbers and its predecessors since 1987. From 1982
to 1987, he served as Reservoir Engineer with Sun Exploration & Production
Company.
Bennie G. Kniffen has served as Senior Vice President and Controller or
similar positions with Cross Timbers and its predecessors since 1986. From 1976
to 1986, he served as Director of Auditing or similar positions with Southland
Royalty Company.
Larry B. McDonald has served as Senior Vice President--Operations or similar
positions with Cross Timbers and its predecessors since 1990. From 1986 to
1990, he owned and operated McDonald Energy, Inc.
Timothy L. Petrus served as Senior Vice President--Acquisitions or similar
positions with Cross Timbers and its predecessors since 1988. From 1980 to
1988, he served as a Vice President with Texas American Bank and as Senior
Project Engineer with Exxon from 1976 to 1980.
Kenneth F. Staab served as Senior Vice President of Engineering or similar
positions with Cross Timbers and its predecessors since 1986. From 1982 to
1986, he was a Reservoir Engineer with Southland Royalty Company.
Thomas L. Vaughn has served as Senior Vice President--Operations or similar
positions with Cross Timbers and its predecessors since 1988. From 1986 to
1988, he owned and operated Vista Operating Company.
Vaughn O. Vennerberg II has served as Senior Vice President--Land or similar
positions with Cross Timbers and its predecessors since 1987. From 1986 to
1987, he served as Land Manager with Hutton Gas Operating Company.
CT-29
<PAGE>
Directors' Compensation
Directors who are also employees of Cross Timbers receive no additional
compensation for service on the Board of Directors. Directors who are not
employees of Cross Timbers receive compensation in the form of common stock and
options to purchase common stock. During 1998, each non-employee director
received 3,375 shares of common stock and options to purchase an additional
2,250 shares of common stock under Cross Timbers' 1998 Stock Incentive Plan.
Executive Compensation
The table below provides compensation information for the Chief Executive
Officer of Cross Timbers and the four other most highly compensated executive
officers for the years ended December 31, 1998, 1997 and 1996.
Summary Compensation Table
<TABLE>
<CAPTION>
Annual Long-Term
Compensation Compensation
--------------- Other ------------------------
Annual Restricted Securities All Other
Compen- Stock Underlying Compen-
Name and Principal Salary Bonus sation Award(s) Options/ sation ($)
Position Year ($) ($) ($)(a) ($) SARs (#) (b)
- ------------------ ---- ------- ------- ------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Bob R. Simpson.......... 1998 481,250 525,000 -- 720,000(c) 225,000 17,107
Chairman of the Board
and 1997 404,167 350,000 -- 1,595,250(d) 225,000 18,187
Chief Executive Officer 1996 309,299 300,000 -- 477,500(e) -- 17,785
Steffen E. Palko........ 1998 361,667 310,000 -- 360,000(c) 129,000 19,080
Vice Chairman 1997 317,083 225,000 -- 797,625(d) 129,000 14,793
and President 1996 302,215 200,000 -- 358,125(e) -- 17,586
J. Richard Seeds (f).... 1998 235,833 165,000 -- 216,000(c) 145,000 10,000
Executive Vice 1997 106,667 100,000 -- -- 75,000 9,500
President 1996 -- -- -- -- -- --
Keith A. Hutton......... 1998 177,083 105,000 -- -- 80,000 10,000
Senior Vice President-- 1997 134,495 103,000 -- -- 63,000 9,500
Asset Development 1996 106,496 66,000 -- 95,500(e) 27,619 9,500
Vaughn O. Vennerberg
II..................... 1998 161,667 100,000 -- -- 67,500 10,000
Senior Vice 1997 127,215 103,000 -- -- 52,500 9,500
President--Land 1996 104,112 66,000 -- 95,500(e) 14,175 9,500
</TABLE>
- --------
(a) Amounts do not include perquisites and other personal benefits, securities
or property, because the total annual amount of such compensation did not
exceed the lesser of $50,000 or 10% of the total of annual salary and bonus
reported for the named executive.
(b) Includes Cross Timbers' 401(k) Plan contributions for each officer of
$10,000 during 1998, $9,500 during 1997, and $9,500 during 1996. The
remaining amounts for Messrs. Simpson and Palko represent life insurance
premiums paid by Cross Timbers.
(c) Represents the value of performance shares of common stock granted under
the 1997 Stock Incentive Plan on May 19, 1998 in the amount of 40,000
shares to Mr. Simpson, 20,000 shares to Mr. Palko and 12,000 shares to Mr.
Seeds. The shares are valued at $18.00, the closing price of the common
stock on May 19, 1998. As of March 1, 1999, these performance shares have
not vested. Based on the December 31, 1998 common stock closing price of
$7.50, Mr. Simpson's restricted stock holdings of 40,000 shares had a year-
end value of $300,000, Mr. Palko's restricted stock holdings of 20,000
shares had a year-end value of $150,000, and Mr. Seeds' restricted stock
holdings of 12,000 shares had a year-end value of $90,000. Quarterly common
stock dividends are paid to holders of performance shares.
CT-30
<PAGE>
(d) Represents the value of performance shares of common stock granted under
the 1997 Stock Incentive Plan on May 20, 1997 and October 1, 1997 in the
amount of 54,000 shares to Mr. Simpson and 27,000 shares to Mr. Palko on
each date. The performance shares granted on May 20, 1997 vested when the
stock price closed at or above $16.67 on October 1, 1997; at that time, the
additional 54,000 and 27,000 performance shares were granted that vested
when the stock price closed at or above $20 on March 26, 1998. The shares
are valued in the above table at $12.58 and $16.96, the closing prices of
the common stock on the May 20, 1997 and October 1, 1997 grant dates.
(e) Represents the value of performance shares of common stock granted under
the 1994 Stock Incentive Plan in 1996 in the amount of 45,000 shares to Mr.
Simpson, 33,750 shares to Mr. Palko, 9,000 shares to Mr. Hutton, and 9,000
shares to Mr. Vennerberg. Performance shares vested when the common stock
price closed at or above $13.33 on January 13, 1997. The shares are valued
in the above table at $10.61 per share, the closing price of the common
stock on the November 20, 1996 grant date.
(f) Mr. Seeds became an employee of Cross Timbers in May 1997.
The following table shows certain information concerning grants of stock
options and stock appreciation rights ("SARs") during 1998 for officers named
in the Summary Compensation Table.
Option/SAR Grants in 1998
Individual Grants
<TABLE>
<CAPTION>
Potential Realized
Value
Percentage at Assumed
Number of of Total Annual Rates of
Securities Options/ Stock Price
Underlying SARs Appreciation
Options/ Granted to Exercise For Option Term (a)
SARs Employees Price Expiration -------------------
Name Granted in 1998 ($/Share) Date 5% ($) 10% ($)
- ---- ---------- ---------- --------- ---------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Bob R. Simpson.......... 225,000 16.2% 18.06 5/19/08 2,555,400 6,477,200
Steffen E. Palko........ 129,000 9.3% 18.06 5/19/08 1,465,100 3,713,600
J. Richard Seeds........ 60,000 4.3% 15.54 2/17/08 586,200 1,486,200
85,000 6.1% 18.06 5/19/08 965,400 2,447,000
Keith A. Hutton......... 65,000 4.7% 18.06 5/19/08 738,200 1,871,200
15,000 1.1% 15.54 2/17/08 146,600 371,600
Vaughn O. Vennerberg II
....................... 52,500 3.8% 18.06 5/19/08 596,300 1,511,300
15,000 1.1% 15.54 2/17/08 146,600 371,600
</TABLE>
- --------
(a) Based on the fair market value at the date of grant and the stated annual
appreciation rate, compounded annually, for the option term of ten years.
The assumed annual appreciation rates of 5% and 10% were established by the
SEC and therefore are not intended to forecast possible future
appreciation, if any, of the common stock. However, the total potential
realized value shown for the above named executives represents less than
1.5% of the total appreciation all stockholders would realize.
CT-31
<PAGE>
The following table shows information regarding stock options and SARs
exercised during 1998 by the officers named in the Summary Compensation Table
and 1998 year-end values.
Aggregated Option/SAR Exercises in 1998 and 12/31/98 Option/SAR Values
<TABLE>
<CAPTION>
Number of Shares Value of
Underlying Unexercised Unexercised In-the-Money
Options/SARs Options/SARs
Shares at 12/31/98 (#) at 12/31/98 (a)
Acquired on Value ------------------------- -------------------------
Name Exercise (#) Realized ($) Exercisable Unexercisable Exercisable Unexercisable
- ---- ------------ ------------ ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Bob R. Simpson.......... 225,000 1,791,000 -- 225,000 -- --
Steffen E. Palko........ 129,000 1,026,600 -- 129,000 -- --
J. Richard Seeds........ 75,000 597,000 32,250 115,000 -- --
Keith A. Hutton......... 63,000 501,480 39,900 72,500 -- --
Vaughn O. Vennerberg
II..................... 52,500 417,900 22,485 60,000 -- --
</TABLE>
- --------
(a) The exercise price of the unexercised options exceeds the 12/31/98 common
stock closing price of $7.50.
Employment and Change in Control Agreements
In February 1995, Messrs. Simpson and Palko entered into new employment
agreements effective March 31, 1995 and ending on December 31, 1995. The
agreements automatically continue from year to year until terminated by either
party on thirty days written notice before each December 31. Under the terms of
the employment agreements, Messrs. Simpson and Palko each receive an annual
base salary of at least $300,000. In December 1997, the Compensation Committee
increased Mr. Simpson's annual base salary to $450,000 and increased Mr.
Palko's annual base salary to $340,000. In December 1998, the Compensation
Committee increased Mr. Simpson's annual base salary to $525,000 and increased
Mr. Palko's annual base salary to $390,000. Under each employment agreement the
employee may participate in any incentive compensation program established by
Cross Timbers for its executive officers as approved by the Compensation
Committee. The employee also receives $2,000,000 of life insurance,
participates in Cross Timbers' group medical and disability insurance plans and
receives a $900 per month automobile allowance plus $400 per month for fuel,
oil, maintenance and insurance costs. The agreements are subject to early
termination upon the death or disability of the employee, or for cause. If an
agreement is terminated because of death or disability, the compensation
payments continue for the term of the agreement, reduced by the amount of
disability insurance paid to the employee. If an agreement is terminated for
cause, Cross Timbers is not required to make additional payments.
Under the employment agreements, Messrs. Simpson and Palko may terminate
their employment for "good reason" which includes:
. the failure of the board of directors to reelect the employee to his
office;
. a significant change in the employee's duties;
. a reduction of or failure to provide typical increases in the employee's
salary following a change in control of Cross Timbers;
. a relocation of the employee to an office outside the Fort Worth/Dallas
metropolitan area;
. a breach of the agreement by Cross Timbers; or
. a failure to maintain the employee's level of participation in the
compensation and benefit plans of Cross Timbers.
CT-32
<PAGE>
The employee is entitled to termination benefits if he terminates his
employment for good reason after a "change in control" or if Cross Timbers
terminates his employment in anticipation of or following a change in control.
The employee will receive a lump-sum payment of three times his most recent
annual compensation and will become fully vested in Cross Timber's stock
incentive plans. Annual compensation includes annual management incentive
compensation and planned level of annual perquisites, but generally excludes
benefits received under stock incentive plans. The lump-sum payment and the
value of full vesting in stock incentive plans will be reduced to the maximum
amount that does not constitute an excess parachute payment under the Internal
Revenue Code, unless the employee elects to receive the full amount. If the
termination for good reason occurs other than because of a change in control,
the employee is entitled to severance pay in the amount that would have been
paid him under the employment agreement had it not been terminated.
A "change in control" of Cross Timbers occurs if:
. any person or group becomes the direct or indirect beneficial owner of
more than 50% of Cross Timbers' outstanding voting equity securities;
. a change in the majority of the Board of Directors occurs within a 12-
month period, unless approved by the vote of two-thirds of the directors
still in office who were directors at the beginning of the 12-month
period; or
. Cross Timbers or its shareholders adopt a plan or agreement to dispose
of all or substantially all of the assets or outstanding common stock.
In June 1997, the Board of Directors approved severance protection plans for
all employees of Cross Timbers. Under the terms of the plans, an employee will
receive a severance payment if a change of control in Cross Timbers occurs and
either the employee is terminated within two years of the change of control or
the employee terminates his employment after a specified period. The specified
period for the President and the Chief Executive Officer is three months and
for Executive Vice Presidents or Senior Vice Presidents is six months. The
severance plans do not apply to any employee that is terminated:
. for cause;
. for permanent disability;
. upon death; or
. by an employee's own decision for other than good reason.
Benefits under the severance plans entitle employees to receive a payment of
a multiple of their annual salary and bonus, 18 months of medical, vision, and
dental benefits and full vesting of all stock options and performance shares
granted under any existing stock incentive plan. The multiple for the Chief
Executive Officer and President is three and for Executive Vice President and
Senior Vice Presidents is two and one-half. If employees become subject to the
20% excess parachute payment excise tax, then Cross Timbers will pay the
employee an additional amount to "gross up" the severance payment.
Messrs. Simpson and Palko also have severance benefits under their
employment agreements. They may elect, within ten days of their termination of
employment, to receive the severance benefits provided under the severance
plans instead of, but not in addition to, the severance benefits under their
employment agreements.
Related Party Transactions
Credit Support and Loans to Officers
In August 1998, Cross Timbers' Board of Directors authorized the use of
Cross Timbers' investment securities held in Cross Timbers' brokerage accounts
to provide credit support for the
CT-33
<PAGE>
margin accounts of the following executive officers: Messrs. Simpson, Palko,
Seeds, Vennerberg and Baldwin. Cross Timbers' Board of Directors made this
assistance available to:
. avoid the executive officers having to sell their shares of Cross
Timbers' common stock at depressed prices;
. prevent downward pressure on the market price of the common stock as a
result of sales by the executive officers; and
. allow the executive officers to retain their shares and more closely
align their interests with those of Cross Timbers' shareholders.
As a result of the continued decline of the market price of Cross Timbers'
common stock, in December 1998 the Board of Directors authorized Cross Timbers
to lend funds directly to the executive officers to reduce their brokerage
account margin debt. These loans are full recourse and due in five years. The
notes bear interest at Cross Timbers' borrowing rates under its bank revolving
credit agreement, which was 6.5% at March 1, 1999.
The following table shows, for each executive officer, the largest principal
amount outstanding during 1998 and the amount outstanding as of March 1, 1999
of each executive officer's margin debt receiving credit support and each
promissory note.
<TABLE>
<CAPTION>
Margin Debt Promissory Notes
------------------------- -------------------------
Largest Amount Largest Amount
Executive Amount Outstanding Amount Outstanding
Officers Outstanding March 1, 1999 Outstanding March 1, 1999
- --------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
Bob R. Simpson............. $13,734,800 $7,278,255 $5,913,000 $5,913,000
Steffen E. Palko........... 5,450,819 2,203,512 -- --
J. Richard Seeds........... 412,943 297,117 121,310 121,310
Vaughn O. Vennerberg II.... 440,026 440,026 -- --
Louis G. Baldwin........... 911,957 797,353 206,753 206,753
</TABLE>
Other Relationships
Randall & Dewey, Inc. performed consulting services in 1998 relating to
Cross Timbers' acquisition of producing properties in Alaska's Cook Inlet.
After Cross Timbers recovers its acquisitions costs, including interest, and
subsequent property development and operating costs, Randall & Dewey, Inc.,
will receive, at its election, either a 20% working interest or a 1% overriding
royalty interest conveyed from Cross Timbers' 100% working interest in the
properties. Randall & Dewey, Inc. also represented EEX Corporation in its sale
to Cross Timbers of certain East Texas properties. For its services, EEX paid
Randall & Dewey, Inc. a fee of $1,096,311. Mr. Randall, a director of Cross
Timbers, is the president and 50% owner of Randall & Dewey, Inc.
During 1998, Cross Timbers incurred fees of $146,094 and expenses of $15,047
with the law firm of Friedman, Young & Suder. A principal of Friedman, Young &
Suder is the son-in-law of Mr. Sherman, a director of Cross Timbers.
CT-34
<PAGE>
SECURITY OWNERSHIP OF MANAGEMENT AND CERTAIN BENEFICIAL OWNERS
The following table shows as of February 1, 1999, the beneficial ownership
of common stock by directors, executive officers, and persons who were known to
Cross Timbers to beneficially own more than five percent of the outstanding
common stock.
<TABLE>
<CAPTION>
Common Stock
Beneficially Owned (a)
-------------------------
Number of
Name Shares Percent
- ---- -------------- ----------
<S> <C> <C>
Directors and Executive Officers (b):
Bob R. Simpson (c)................................. 1,422,789 3.2%
Steffen E. Palko (c)............................... 926,428 2.1
J. Richard Seeds (c)(d)............................ 107,745 *
J. Luther King, Jr. (e)............................ 214,327 *
Jack P. Randall.................................... 25,625 *
Scott G. Sherman (d)(f)............................ 105,263 *
Keith A. Hutton (c)................................ 144,365 *
Vaughn O. Vennerberg II (c)........................ 110,540 *
Directors and executive officers as a group (14
persons) (c)...................................... 3,705,006 8.2
Certain Beneficial Owners:
Baron Capital Group, Inc. (g)...................... 5,835,625 13.0
767 Fifth Avenue, 24th Floor
New York, NY 10153
Demeter Holdings Corporation (h)................... 5,234,113 11.6
c/o Charlesbank Capital Partners, LLC
600 Atlantic Ave, 26th Floor
Boston, MA 02210
GSB Investment Management, Inc. (i)................ 2,513,001 5.6
301 Commerce St, Suite 2001
Fort Worth, TX 76102
</TABLE>
- --------
* Less than 1%
(a) Unless otherwise indicated, all shares listed are directly held with sole
voting and investment power.
(b) Includes options, issued under Cross Timbers' Stock Incentive Plans that
are exercisable within 60 days of February 1, 1999, to acquire common
stock, as follows: Mr. Seeds, 32,250; Mr. King, 4,500; Mr. Randall, 2,250;
Mr. Sherman, 18,000; Mr. Hutton, 39,900; Mr. Vennerberg, 22,485; all
directors and executive officers as a group, 195,135.
(c) Includes common stock that may be deemed to be beneficially owned under the
Cross Timbers' 401(k) Plan as of December 31, 1998.
(d) Includes shares of common stock that may be acquired upon conversion of
Cross Timbers' Series A Convertible Preferred Stock as follows: Mr. Seeds,
3,473; Mr. Sherman (owned by the Scott Sherman Family Limited Partnership),
69,263; all directors and executive officers as a group, 72,736.
(e) Includes 126,202 shares owned by LKCM Investment Partnership. Mr. King is
the general partner and portfolio manager of LKCM Investment Partnership.
Mr. King is president of Luther King Capital Management Corporation, which
is the investment advisor of LKCM Investment Partnership. Luther King
Capital Management Corporation and an affiliated company are also limited
partners of LKCM Investment Partnership. Mr. King has the power to direct
the voting and disposition of these shares.
CT-35
<PAGE>
(f) Includes 80,513 common shares owned by the Scott Sherman Family Limited
Partnership. See also (d) above.
(g) As reported on Schedule 13G at December 31, 1997 and updated through
December 31, 1998 by Baron Capital Group, Inc. which has sole power to vote
and dispose of 149,250 shares and shared power to vote and dispose of
5,452,275 shares.
(h) As reported on Schedule 13G by Demeter Holdings Corporation through its
wholly owned subsidiary, White River Corporation, at December 31, 1998.
Demeter Holdings Corporation, a wholly owned subsidiary of the endowment
fund of Harvard University, has the sole power to vote and dispose of
5,234,113 shares, subject to an investment management agreement between
Charlesbank Capital Partners, LLC and Harvard University.
(i) As reported on Schedule 13G by GSB Investment Management, Inc. which has
sole power to vote on 1,102,658 shares and the sole power to dispose of
2,423,763 shares at December 31, 1998.
CT-36
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Cross Timbers Oil Company
Report of Independent Public Accountants................................ CTF-2
Consolidated Balance Sheets at December 31, 1997 and 1998............... CTF-3
Consolidated Statements of Operations for the years ended December 31,
1996, 1997 and 1998.................................................... CTF-4
Consolidated Statements of Comprehensive Income for the years ended
December 31, 1996, 1997 and 1998....................................... CTF-5
Consolidated Statements of Cash Flows for the years ended December 31,
1996, 1997 and 1998.................................................... CTF-6
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1996, 1997 and 1998....................................... CTF-7
Notes to Consolidated Financial Statements.............................. CTF-8
Cross Timbers Oil Company--Pro Forma
Pro Forma Consolidated Financial Statements (Unaudited)................. CTF-36
Pro Forma Consolidated Balance Sheet at December 31, 1998............... CTF-37
Pro Forma Consolidated Statement of Operations for the year ended
December 31, 1998...................................................... CTF-38
Notes to Pro Forma Consolidated Financial Statements.................... CTF-39
EEX Acquisition
Report of Independent Public Accountants................................ CTF-42
Statements of Revenues and Direct Operating Expenses for the years ended
December 31, 1995, 1996 and 1997 and the period January 1 through April
24, 1998............................................................... CTF-43
Notes to Statements of Revenues and Direct Operating Expenses........... CTF-44
Amoco Acquisition
Report of Independent Public Accountants................................ CTF-46
Statements of Revenues and Direct Operating Expenses for the year ended
December 31, 1996 and the period January 1 through December 1, 1997.... CTF-47
Notes to Statements of Revenues and Direct Operating Expenses........... CTF-48
</TABLE>
CTF-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Cross Timbers Oil Company
We have audited the accompanying consolidated balance sheets of Cross
Timbers Oil Company and its subsidiaries as of December 31, 1997 and 1998, and
the related consolidated statements of operations, comprehensive income, cash
flows and stockholders' equity 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 statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of the Company
as of December 31, 1997 and 1998, and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 1998,
in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 12, 1999
CTF-2
<PAGE>
CROSS TIMBERS OIL COMPANY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31
---------------------
1997 1998
--------- ----------
(in thousands)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents............................. $ 3,816 $ 12,333
Accounts receivable, net (Note 8)..................... 43,996 50,607
Investment in equity securities (Note 2).............. -- 44,386
Deferred income tax benefit (Note 5).................. 445 24,816
Other current assets.................................. 3,905 5,436
--------- ----------
Total Current Assets................................ 52,162 137,578
--------- ----------
Property and Equipment, at cost -- successful efforts
method (Notes 1 and 4):
Producing properties.................................. 931,259 1,335,844
Undeveloped properties................................ 6,406 6,845
Gas gathering and other............................... 23,703 27,829
--------- ----------
Total Property and Equipment........................ 961,368 1,370,518
Accumulated depreciation, depletion and amortization.. (237,532) (319,507)
--------- ----------
Net Property and Equipment.......................... 723,836 1,051,011
--------- ----------
Other Assets............................................ 12,457 13,210
--------- ----------
Loans to Officers (Note 3).............................. -- 5,795
--------- ----------
TOTAL ASSETS............................................ $ 788,455 $1,207,594
========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities.............. $ 52,266 $ 93,583
Payable to Royalty Trust.............................. 2,073 968
Short-term debt (Note 4).............................. -- 4,962
Accrued stock incentive compensation (Note 11)........ 554 75
--------- ----------
Total Current Liabilities........................... 54,893 99,588
--------- ----------
Long-term Debt (Note 4)................................. 539,000 921,000
--------- ----------
Deferred Income Taxes Payable (Note 5).................. 21,320 6,892
--------- ----------
Other Long-term Liabilities (Note 6).................... 2,999 2,663
--------- ----------
Commitments and Contingencies (Note 6)
Stockholders' Equity (Note 7):
Series A convertible preferred stock ($.01 par value,
25,000,000 shares authorized, 1,138,729 issued, at
liquidation value of $25)............................ 28,468 28,468
Common stock ($.01 par value, 100,000,000 shares
authorized, 46,310,710 and 54,048,227 shares
issued).............................................. 463 541
Additional paid-in capital............................ 210,954 338,503
Treasury stock (6,860,779 and 9,320,971 shares)....... (76,656) (118,555)
Retained earnings (deficit)........................... 7,014 (71,506)
--------- ----------
Total Stockholders' Equity.......................... 170,243 177,451
--------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.............. $ 788,455 $1,207,594
========= ==========
</TABLE>
See accompanying notes to consolidated financial statements.
CTF-3
<PAGE>
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
Year Ended December 31
-----------------------------
1996 1997 1998
-------- -------- ---------
(in thousands, except
per share data)
<S> <C> <C> <C>
REVENUES
Oil and condensate........................... $ 75,013 $ 75,223 $ 56,164
Gas and natural gas liquids.................. 73,402 110,104 182,587
Gas gathering, processing and marketing...... 12,032 9,851 9,438
Other........................................ 888 3,094 1,297
-------- -------- ---------
Total Revenues............................. 161,335 198,272 249,486
-------- -------- ---------
EXPENSES
Production................................... 39,365 43,580 63,148
Exploration.................................. -- 2,088 8,034
Taxes, transportation and other.............. 11,944 16,405 29,105
Depreciation, depletion and amortization..... 37,858 47,721 83,560
Impairment (Note 1).......................... -- -- 2,040
General and administrative (Note 11)......... 16,420 15,818 13,479
Gas gathering and processing................. 6,905 8,517 8,360
Trust development costs...................... 854 665 1,498
-------- -------- ---------
Total Expenses............................. 113,346 134,794 209,224
-------- -------- ---------
OPERATING INCOME............................... 47,989 63,478 40,262
-------- -------- ---------
OTHER INCOME (EXPENSE)
Gain (loss) on investment in equity securities
(Note 2)...................................... (893) 1,735 (93,719)
Interest expense, net.......................... (16,123) (26,012) (52,113)
-------- -------- ---------
Total Other Income (Expense)............... (17,016) (24,277) (145,832)
-------- -------- ---------
INCOME (LOSS) BEFORE TAX....................... 30,973 39,201 (105,570)
Income Tax Expense (Benefit) (Note 5).......... 10,669 13,517 (35,851)
-------- -------- ---------
NET INCOME (LOSS).............................. 20,304 25,684 (69,719)
Preferred stock dividends...................... 514 1,779 1,779
-------- -------- ---------
EARNINGS (LOSS) AVAILABLE TO COMMON STOCK...... $ 19,790 $ 23,905 $ (71,498)
======== ======== =========
EARNINGS (LOSS) PER COMMON SHARE (Notes 1 and
9)
Basic........................................ $ 0.50 $ 0.60 $ (1.65)
======== ======== =========
Diluted...................................... $ 0.48 $ 0.59 $ (1.65)
======== ======== =========
Weighted Average Common Shares Outstanding..... 39,913 39,773 43,396
======== ======== =========
</TABLE>
See accompanying notes to consolidated financial statements.
CTF-4
<PAGE>
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
Year Ended December 31
--------------------------
1996 1997 1998
------- ------- --------
(in thousands)
<S> <C> <C> <C>
NET INCOME (LOSS)................................. $20,304 $25,684 $(69,719)
------- ------- --------
OTHER COMPREHENSIVE INCOME
Unrealized gains on available-for-sale securities
(Note 2):
Unrealized holding gains........................ 1,022 1,434 --
Less: realized gains included in net income..... (56) (2,400) --
------- ------- --------
Other Comprehensive Income (Loss) Before Tax...... 966 (966) --
Income tax benefit (expense) related to
other comprehensive income....................... (328) 328 --
------- ------- --------
Other Comprehensive Income (Loss)................. 638 (638) --
------- ------- --------
COMPREHENSIVE INCOME (LOSS)....................... $20,942 $25,046 $(69,719)
======= ======= ========
</TABLE>
See accompanying notes to consolidated financial statements.
CTF-5
<PAGE>
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Note 10)
<TABLE>
<CAPTION>
Year Ended December 31
-----------------------------
1996 1997 1998
-------- -------- ---------
(in thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income (loss).............................. $ 20,304 $ 25,684 $ (69,719)
Adjustments to reconcile net income (loss) to
net cash provided (used) by operating
activities:
Depreciation, depletion and amortization..... 37,858 47,721 83,560
Impairment................................... -- -- 2,040
Exploration.................................. -- 2,088 8,034
Stock incentive compensation................. (853) 3,386 1,141
Deferred income tax.......................... 10,213 13,393 (35,744)
(Gain) loss from sale of properties and
equity securities........................... (576) (4,157) 86,628
Other non-cash items......................... 1,317 1,864 2,540
Changes in current assets and liabilities
(a)......................................... (8,569) 8,027 (124,322)
-------- -------- ---------
Cash Provided (Used) by Operating Activities... 59,694 98,006 (45,842)
-------- -------- ---------
INVESTING ACTIVITIES
Proceeds from sale of long-term investment in
equity securities............................. 402 24,626 --
Long-term investment in equity securities...... (16,093) (6,479) --
Proceeds from sale of property and equipment... 37,388 17,972 2,494
Property acquisitions.......................... (109,535) (238,294) (296,390)
Exploration and development costs.............. (32,291) (90,470) (77,390)
Gas plant, gathering and other additions....... (4,742) (18,677) (7,517)
Loans to officers.............................. -- -- (5,795)
-------- -------- ---------
Cash Used by Investing Activities.............. (124,871) (311,322) (384,598)
-------- -------- ---------
FINANCING ACTIVITIES
Proceeds from long-term debt................... 188,000 688,400 877,900
Payments on long-term debt..................... (81,200) (437,430) (496,938)
Common stock offering.......................... -- -- 133,113
Dividends...................................... (5,339) (7,571) (8,460)
Stock option exercises and other............... 364 750 (269)
Purchases of treasury stock.................... (34,923) (30,954) (66,389)
-------- -------- ---------
Cash Provided by Financing Activities.......... 66,902 213,195 438,957
-------- -------- ---------
INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS................................... 1,725 (121) 8,517
Cash and Cash Equivalents, January 1........... 2,212 3,937 3,816
-------- -------- ---------
Cash and Cash Equivalents, December 31......... $ 3,937 $ 3,816 $ 12,333
======== ======== =========
(a) Changes in Current Assets and Liabilities
Accounts receivable.......................... $(16,999) $ 246 $ (7,022)
Investment in equity securities (purchases
net of sales)............................... -- -- (131,809)
Other current assets......................... (1,683) (970) (1,513)
Accounts payable, accrued liabilities and
payable to Royalty Trust.................... 10,113 8,751 16,022
-------- -------- ---------
Decrease (Increase) in Current Assets and
Liabilities................................... $ (8,569) $ 8,027 $(124,322)
======== ======== =========
</TABLE>
See accompanying notes to consolidated financial statements.
CTF-6
<PAGE>
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Note 7)
<TABLE>
<CAPTION>
Shares Stockholders' Equity
-------------------------- ------------------------------------------------
Common Stock
---------------- Additional Retained
Preferred In Preferred Common Paid-in Treasury Earnings
Stock Issued Treasury Stock Stock Capital Stock (Deficit)
--------- ------ -------- --------- ------ ---------- --------- ---------
(in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balances, December 31,
1995................... -- 41,434 69 $ -- $414 $156,440 $ (528) $(25,626)
Issuance/vesting of
performance shares.... -- 168 106 -- 2 2,673 (1,038) --
Stock option
exercises............. -- 996 768 -- 10 7,189 (7,931) --
Treasury stock
purchases............. -- -- 2,925 -- -- -- (30,722) --
Exchange of Series A
convertible preferred
stock for common
stock................. 1,139 (2,979) -- 28,468 (30) (28,978) -- --
Conversion of
subordinated
convertible notes to
common stock.......... -- 2,696 -- -- 27 27,112 -- --
Common stock dividends
($0.13 per share)..... -- -- -- -- -- -- -- (5,242)
Preferred stock
dividends ($0.45 per
share)................ -- -- -- -- -- -- -- (514)
Net income............. -- -- -- -- -- -- -- 20,304
----- ------ ------ ------- ---- -------- --------- --------
Balances, December 31,
1996................... 1,139 42,315 3,868 28,468 423 164,436 (40,219) (11,078)
Issuance/vesting of
performance shares.... -- 180 76 -- 2 3,431 (1,098) --
Stock option
exercises............. -- 924 566 -- 9 8,183 (7,326) --
Treasury stock
purchases............. -- -- 2,351 -- -- -- (28,013) --
Conversion of
subordinated
convertible notes to
common stock.......... -- 2,892 -- -- 29 29,179 -- --
Issuance of warrants... -- -- -- -- -- 5,725 -- --
Common stock dividends
($0.15 per share)..... -- -- -- -- -- -- -- (5,813)
Preferred stock
dividends ($1.56 per
share)................ -- -- -- -- -- -- -- (1,779)
Net income............. -- -- -- -- -- -- -- 25,684
----- ------ ------ ------- ---- -------- --------- --------
Balances, December 31,
1997................... 1,139 46,311 6,861 28,468 463 210,954 (76,656) 7,014
Sale of common stock... -- 7,203 -- -- 72 133,041 -- --
Issuance/vesting of
performance shares.... -- 82 27 -- 1 1,804 (536) --
Stock option
exercises............. -- 452 25 -- 5 2,986 (483) --
Treasury stock
purchases............. -- -- 4,330 -- -- -- (65,575) --
Treasury stock issued.. -- -- (1,922) -- -- (10,282) 24,695 --
Common stock dividends
($0.16 per share)..... -- -- -- -- -- -- -- (7,022)
Preferred stock
dividends ($1.56 per
share)................ -- -- -- -- -- -- -- (1,779)
Net loss............... -- -- -- -- -- -- -- (69,719)
----- ------ ------ ------- ---- -------- --------- --------
Balances, December 31,
1998................... 1,139 54,048 9,321 $28,468 $541 $338,503 $(118,555) $(71,506)
===== ====== ====== ======= ==== ======== ========= ========
</TABLE>
See accompanying notes to consolidated financial statements.
CTF-7
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Cross Timbers Oil Company, a Delaware corporation, was organized in October
1990 to ultimately acquire the business and properties of predecessor entities
that were created from 1986 through 1989. Cross Timbers Oil Company completed
its initial public offering of common stock in May 1993.
The accompanying consolidated financial statements include the financial
statements of Cross Timbers Oil Company and its wholly owned subsidiaries ("the
Company"). All significant intercompany balances and transactions have been
eliminated in the consolidation. In preparing the accompanying financial
statements, management has made certain estimates and assumptions that affect
reported amounts in the financial statements and disclosures of contingencies.
Actual results may differ from those estimates. Certain amounts presented in
prior period financial statements have been reclassified for consistency with
current period presentation.
All common stock shares and per share amounts in the accompanying financial
statements have been adjusted for the three-for-two stock splits effected on
March 19, 1997 and February 25, 1998 (Note 7).
The Company is an independent oil and gas company with production and
exploration concentrated in Texas, Oklahoma, Kansas, New Mexico, Wyoming and
Alaska. The Company also gathers, processes and markets gas, transports and
markets oil and conducts other activities directly related to the oil and gas
producing industry.
Property and Equipment
The Company follows the successful efforts method of accounting,
capitalizing costs of successful exploratory wells and expensing costs of
unsuccessful exploratory wells. Exploratory geological and geophysical costs
are expensed as incurred. All developmental costs are capitalized. The Company
generally pursues acquisition and development of proved reserves, although the
Company increased its exploration activities in 1997 and 1998. Most of the
property costs reflected in the accompanying consolidated balance sheets are
from acquisitions of producing properties from other oil and gas companies.
Producing properties balances include costs of $26,570,000 at December 31, 1997
and $15,859,000 at December 31, 1998, related to wells in progress of drilling.
Depreciation, depletion and amortization of producing properties is computed
on the unit-of-production method based on estimated proved oil and gas
reserves. Other property and equipment is generally depreciated using the
straight-line method over estimated useful lives which range from 3 to 40
years. Repairs and maintenance are expensed, while renewals and betterments are
generally capitalized. The estimated undiscounted cost, net of salvage value,
of dismantling and removing major oil and gas production facilities, including
necessary site restoration, are accrued using the unit-of-production method.
Effective October 1, 1995, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of. When impairment
review is necessary, the carrying value of property, plant and equipment
intended to be retained is compared to management's future estimated pretax
cash flow. If impairment is necessary, the asset carrying value is adjusted to
fair value. Cash flow pricing estimates are based on existing reserve and
production information and pricing assumptions that management believes are
reasonable. Generally, for producing properties, the review considers proved
reserves, though probable reserves and other conditions are considered if
warranted.
CTF-8
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Impairment of individually significant undeveloped properties is assessed on a
property-by-property basis and impairment of other undeveloped properties is
assessed and amortized on an aggregate basis. The Company recorded an
impairment provision on producing properties of $2,040,000 before income tax in
1998.
Cross Timbers Royalty Trust
The Company makes monthly net profits payments to Cross Timbers Royalty
Trust based on revenues and costs related to properties from which net profits
interests were carved. Net profits payments to the Cross Timbers Royalty Trust
are generally based on revenues received and costs disbursed by the Company in
the prior month. For financial reporting purposes, the Company reduces oil and
gas revenues and taxes on production for amounts allocated to the Cross Timbers
Royalty Trust. The Cross Timbers Royalty Trust's portion of development costs
are expensed as trust development costs in the accompanying consolidated
statements of operations. The Company owned approximately 22% of the Cross
Timbers Royalty Trust publicly traded units at December 31, 1997 and 1998.
Cross Timbers Royalty Trust units are traded on the New York Stock Exchange
under the symbol "CRT."
Hugoton Royalty Trust
In December 1998, the Company formed the Hugoton Royalty Trust by conveying
an 80% net profits interest in properties that are principally located in the
Hugoton area of Kansas and Oklahoma, the Anadarko Basin of Oklahoma and the
Green River Basin of Wyoming. These properties represent approximately 30% of
the Company's existing reserve base. The Company filed a registration statement
with the Securities and Exchange Commission ("Commission") in December 1998 and
plans to offer approximately 40% of the trust units to the public in March or
April 1999. The trust units will be listed on the New York Stock Exchange under
the symbol "HGT."
Cash and Cash Equivalents
Cash equivalents are considered to be all highly liquid investments having
an original maturity of three months or less.
Investment in Equity Securities
In accordance with Statement of Financial Accounting Standards No. 115,
Accounting for Certain Investments in Debt and Equity Securities, equity
securities acquired during 1998 have been recorded as trading securities since
such securities were acquired principally for resale in the near future.
Accordingly, such investment at December 31, 1998 has been recorded as a
current asset at market value, unrealized holding gains and losses have been
recognized in the consolidated statement of operations, and cash flows from
purchases and sales of equity securities have been included in cash provided
(used) by operating activities in the consolidated statement of cash flows.
Gains (losses) on trading securities and interest related to the cost of these
investments have been classified as other income (expense). Such gains (losses)
were previously classified as other revenue and interest related to such
investments was previously classified as interest expense.
Prior to 1998, the Company's investments in equity securities were recorded
as available-for-sale securities. As a result, such investments were recorded
as long-term assets at market value, unrealized holding gains and losses were
recorded as a separate component of stockholders' equity and cash flows from
purchases and sales of equity securities were included in cash provided (used)
by investing activities. See Note 2.
CTF-9
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Other Assets
Other assets primarily include deferred debt costs that are amortized over
the term of the related debt (Note 4). Other assets are presented net of
accumulated amortization of $2,860,000 at December 31, 1997 and $4,697,000 at
December 31, 1998.
Derivatives
The Company uses derivatives on a limited basis to hedge interest rate and
product price risks, as opposed to their use for trading purposes. Amounts
receivable or payable under interest swap agreements are recorded as
adjustments to interest expense. Gains and losses on commodity futures
contracts and other price risk management instruments are recognized in oil and
gas revenues when the hedged transaction occurs. Cash flows related to
derivative transactions are included in operating activities. See Note 8.
Production Imbalances
The Company uses the entitlement method of accounting for gas sales, based
on the Company's net revenue interest in production. Accordingly, revenue is
deferred when gas deliveries exceed the Company's net revenue interest, while
revenue is accrued for under-deliveries. Production imbalances are generally
recorded at the estimated sales price in effect at the time of production. At
December 31, 1997, the Company recorded a net receivable of $5,054,000 for a
net underproduced balancing position of 1,114,000 Mcf of natural gas and
8,049,000 Mcf of carbon dioxide. At December 31, 1998, the Company recorded a
net receivable of $4,904,000 for a net underproduced balancing position of
885,000 Mcf of natural gas and 7,909,000 Mcf of carbon dioxide.
Gas Gathering, Processing and Marketing Revenues
Gas produced by the Company and third parties is marketed by the Company to
brokers, local distribution companies and end-users. Gas gathering and
marketing revenues are recognized in the month of delivery based on customer
nominations. Gas processing and marketing revenues are recorded net of cost of
gas sold of $56.4 million for 1996, $57.1 million for 1997 and $56.3 million
for 1998. These amounts are net of intercompany eliminations.
Other Revenues
Other revenues include gains and losses from sale of property and equipment.
The Company realized gains on sale of property and equipment of $520,000 in
1996, $1,757,000 in 1997 and $795,000 in 1998.
Exploration Expense
Exploration costs were $2.1 million in 1997. During 1998, the Company
incurred $8 million of exploration costs, primarily composed of geological and
geophysical costs related to the 1998 exploration program.
Interest Expense
Interest expense includes amortization of deferred debt costs and is
presented net of interest income of $152,000 in 1996, $71,000 in 1997 and
$91,000 in 1998, and net of capitalized interest of $1,185,000 in 1997 and
$1,070,000 in 1998. No interest was capitalized in 1996.
CTF-10
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Stock-Based Compensation
In accordance with Accounting Principles Board Opinion No. 25, Accounting
for Stock Issued to Employees, no compensation is recorded for stock options or
other stock-based awards that are granted to employees with an exercise price
equal to or above the common stock price on the grant date. Compensation
related to performance share grants is recognized from the grant date until the
performance conditions are satisfied, based on the market price of the
Company's common stock. The pro forma effect of recording stock-based
compensation at the estimated fair value of awards on the grant date, as
prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, is
disclosed in Note 11.
Earnings per Common Share
Effective December 31, 1997, the Company adopted SFAS No. 128, Earnings Per
Share, which changed the method of computing and disclosing earnings per share
for all periods. Under SFAS No. 128, the Company must report basic earnings per
share, which excludes the effect of potentially dilutive securities, and
diluted earnings per share, which includes the effect of all potentially
dilutive securities unless their impact is antidilutive. The Company previously
only reported earnings per share excluding potentially dilutive securities
because their effect was antidilutive or less than 3% dilutive, as prescribed
by the accounting pronouncement superseded by SFAS No. 128. See Note 9.
Earnings (loss) per common share for all periods presented is based on
weighted average common shares outstanding as adjusted for the three-for-two
stock splits on March 19, 1997 and February 25, 1998 (Note 7).
Segment Reporting
In accordance with SFAS No. 131, Disclosures about Segments of an Enterprise
and Related Information, the Company has identified only one operating segment,
which is the exploration and production of oil and gas. All the Company's
assets are located in the United States and all its revenues are attributable
to United States customers.
In 1996, gas sales to two purchasers were approximately 15% and 14% of total
revenues. In 1997, gas sales to one purchaser were approximately 14% of total
revenues. There were no sales to a single purchaser that exceeded 10% of total
revenues in 1998.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, which is required
to be adopted for fiscal years beginning after June 15, 1999. SFAS No. 133
requires that derivatives be reported on the balance sheet at fair value and,
if the derivative is not designated as a hedging instrument, changes in fair
value must be recognized in earnings in the period of change. If the derivative
is designated as a hedge and to the extent such hedge is determined to be
effective, changes in fair value are either a) offset by the change in fair
value of the hedged asset or liability (if applicable) or b) reported as a
component of other comprehensive income in the period of change, and
subsequently recognized in earnings when the offsetting hedged transaction
occurs. The definition of derivatives has also been expanded to include
contracts that require physical delivery of oil and gas if the contract allows
for net cash settlement. The Company primarily uses derivatives to hedge
product price and interest rate risks. Such derivatives are reported at cost,
if any, and gains and losses on such derivatives are
CTF-11
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
reported when the hedged transaction occurs. Accordingly, the Company's
adoption of SFAS No. 133 will have an impact of the reported financial
position of the Company, and although such impact has not been determined, it
is currently not believed to be material. Adoption of SFAS No. 133 should have
no significant impact on reported earnings, but could materially affect
comprehensive income.
2. Investment in Equity Securities
The Company periodically invests in publicly traded equity securities of
select energy companies which it believes to be undervalued. Since classified
as trading securities, this investment at December 31, 1998 is recorded as a
current asset at market value. Realized gains and losses are computed based on
a first-in, first-out determination of cost of securities sold. After sale of
its current investment, the Company does not plan to make future investments
in equity securities of other energy companies.
The following are components of gain (loss) on investment in equity
securities (in thousands):
<TABLE>
<CAPTION>
1996 1997 1998
----- ------ --------
<S> <C> <C> <C>
Realized gains (losses) on sale of securities:
Gains........................................... $ 56 $2,400 $ 887
Losses.......................................... -- -- (15,706)
----- ------ --------
Net gains (losses).............................. 56 2,400 (14,819)
Unrealized gains (losses) (a)..................... -- -- (72,605)
Interest expense related to investment in equity
securities....................................... (949) (665) (6,295)
----- ------ --------
Gains (losses) on investment in equity
securities....................................... $(893) $1,735 $(93,719)
===== ====== ========
</TABLE>
- --------
(a) Because investments in equity securities were recorded as available-for-
sale securities prior to 1998, unrealized gains and losses for 1996 and
1997 are reported as a component of stockholders' equity, as shown in the
Consolidated Statements of Comprehensive Income.
As of March 1, 1999 the Company had incurred a 1999 pre-tax loss on its
investment in equity securities of $8 million, of which $17.5 million was a
realized loss, partially offset by a $9.5 million decrease in unrealized loss.
3. Related Party Transactions
Loans to Officers
Pursuant to margin support agreements with each of six officers, the
Company agreed to use the value of its investments in equity securities (Note
2) to provide margin support for the officers' broker accounts in which they
held Company common stock. In August 1998, the Board of Directors authorized
these agreements so that the officers would not be forced to sell Company
common stock, particularly at depressed prices, potentially creating further
downward pressure on the stock price. These agreements provide that each
officer cannot purchase additional securities in his broker account, or engage
in any transaction that would increase the margin requirements for his
account, including withdrawal of any funds or securities. The Company also has
agreed to pay each officer's margin debt to the extent unpaid by the officer.
In connection with these agreements, in December 1998 the Company loaned four
officers a total of $5,795,000 to reduce their margin debt. In January and
February 1999, an additional $430,000 was loaned. These loans are full
recourse and due in five
CTF-12
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
years, with interest equal to the Company's bank debt rates (Note 4). Total
officer margin debt on their broker accounts at March 1, 1999 was $11.2
million.
Other Transactions
A director-related company performed consulting services in 1998 in
connection with the Cook Inlet Acquisition (Note 12). After the Company
recovers its acquisition costs, including interest and subsequent property
development and operating costs, the director-related company will receive, at
its election, either a 20% working interest or a 1% overriding interest
conveyed from the Company's 100% working interest in these properties. In 1997,
the Company paid fees of $1.6 million to this director-related company in
connection with property sales and the Amoco Acquisition. These consulting fees
are effectively capitalized as a portion of property cost.
4. Debt
The Company's outstanding debt consists of the following (in thousands):
<TABLE>
<CAPTION>
December 31
------------------
1997 1998
-------- --------
<S> <C> <C>
Short-term Debt:
Short-term borrowings, 7.4% at December 31, 1998.......... $ 10,000 $ 4,962
Reclassified to long-term debt............................ (10,000) --
-------- --------
Total short-term debt................................... $ -- $ 4,962
======== ========
Long-term Debt:
Senior debt-
Bank debt under revolving credit agreements due June 30,
2003, 6.9% at December 31, 1998.......................... $229,000 $615,000
Subordinated debt- .........................................
9 1/4% senior subordinated notes due April 1, 2007........ 125,000 125,000
8 3/4% senior subordinated notes due November 1, 2009..... 175,000 175,000
Other long-term debt........................................ -- 6,000
-------- --------
Sub-total long-term debt.................................... 529,000 921,000
Reclassified from short-term debt........................... 10,000 --
-------- --------
Total long-term debt.................................... $539,000 $921,000
======== ========
</TABLE>
Senior Debt
On November 16, 1998, the Company entered into a new Revolving Credit
Agreement with commercial banks ("loan agreement"). As of December 31, 1998,
the loan agreement had a borrowing base and commitment of $615 million with no
unused borrowing capacity. The borrowing base is redetermined annually based on
the value and expected cash flow of the Company's proved oil and gas reserves.
If borrowings exceed the redetermined borrowing base, the banks may require
that the excess be repaid within a year. Otherwise, borrowings under the loan
agreement do not mature until June 30, 2003, but may be prepaid at any time
without penalty. The Company periodically renegotiates the loan agreement to
increase the borrowing commitment and extend the revolving facility. The
borrowing base is scheduled to be redetermined in June 1999. Based on year-end
proved reserves, the Company does not expect a reduction in the borrowing base
upon its redetermination.
CTF-13
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Reclassification of short-term to long-term debt at December 31, 1997
represents unused capacity under the loan agreement based on outstanding debt
balances at that date.
Restrictions set forth in the loan agreement include limitations on the
incurrence of additional indebtedness, the creation of certain liens, and the
redemption or prepayment of subordinated indebtedness. The loan agreement also
limits dividends to 25% of cash flow from operations for the latest four
consecutive quarterly periods. The Company is also required to maintain a
current ratio of not less than one (where unused borrowing commitments are
included as a current asset).
The loan agreement provides the option of borrowing at floating interest
rates based on the prime rate or at fixed rates for periods of up to six months
based on certificate of deposit rates or London Interbank Offered Rates
("LIBOR"). Borrowings under the loan agreement at December 31, 1998 were based
on LIBOR rates with a maturity of one to six months and accrued at the
applicable LIBOR rate plus 1 3/8%. Interest is paid at maturity, or quarterly
if the term is for a period of 90 days or more. The Company also incurs a
commitment fee of 3/8% on unused borrowing commitments. The weighted average
interest rate on senior debt was 6.7% during 1996 and 6.9% during 1997 and
1998. See Note 8 regarding interest rate swap agreements.
Subordinated Debt
The Company sold $125 million of 9 1/4% senior subordinated notes ("9 1/4%
Notes") on April 2, 1997, and $175 million of 8 3/4% senior subordinated notes
("8 3/4% Notes") on October 28, 1997 (the 9 1/4% Notes and the 8 3/4% Notes
collectively referred to as "the Notes"). The Notes are general unsecured
indebtedness that is subordinate to bank borrowings under the loan agreement.
Net proceeds of $121.1 million from the 9 1/4% Notes and $169.9 million from
the 8 3/4% Notes were used to reduce bank borrowings under the loan agreement.
The 9 1/4% Notes mature on April 1, 2007 and interest is payable each April 1
and October 1, while the 8 3/4% Notes mature on November 1, 2009 with interest
payable each May 1 and November 1.
The Company has the option to redeem the 9 1/4% Notes on April 1, 2002 and
the 8 3/4% Notes on November 1, 2002 at a price of approximately 105%, and
thereafter at prices declining ratably at each anniversary to 100% in 2005. In
addition, on or prior to April 1, 2000 for the 9 1/4% Notes and November 1,
2000 for the 8 3/4% Notes, the Company may redeem up to one-third of the Notes
with the net proceeds from one or more public equity offerings at a price of
approximately 109% plus accrued interest, subject to certain requirements. Upon
a change in control of the Company, the holders of the Notes have the right to
require the Company to purchase all or a portion of their Notes at 101% plus
accrued interest.
The Notes were issued under indentures that place certain restrictions on
the Company, including limitations on additional indebtedness, liens, dividend
payments, treasury stock purchases, disposition of proceeds from asset sales,
transfers of assets and transactions with subsidiaries and affiliates.
To reduce the interest rate on a portion of its subordinated debt, the
Company has entered an agreement with a bank that has purchased on the market
Notes with a face value of $21.6 million. The Company pays the bank a variable
interest rate based on three-month LIBOR rates, and receives semiannually from
the bank the fixed interest rate on the Notes. The term of the agreement for
approximately half the Notes is through April 2002, and for the remaining half
is through November 2002. Any change in market value of the Notes from the date
purchased by the bank is payable to or receivable from the bank. The Company
funded market value depreciation of $169,000
CTF-14
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
in January 1999. The Company has the option of repurchasing the Notes from the
bank at any time at market value.
Other Debt
As part of the Cook Inlet Acquisition, the Company executed a $6 million
non-interest bearing promissory note payable to Shell. Payments of $3 million,
$2 million and $1 million are due when the average NYMEX crude oil price for 60
consecutive calendar days equals or exceeds $18.50, $19.50 and $20.50,
respectively.
See also Note 7 "--Registration Statement."
5. Income Tax
The effective income tax rate for the Company was different than the
statutory federal income tax rate for the following reasons (in thousands):
<TABLE>
<CAPTION>
1996 1997 1998
------- ------- --------
<S> <C> <C> <C>
Income tax expense (benefit) at the federal
statutory rate of 34%.......................... $10,531 $13,329 $(35,893)
State and local taxes and other................. 138 188 42
------- ------- --------
Income tax expense (benefit).................... $10,669 $13,517 $(35,851)
======= ======= ========
</TABLE>
Components of income tax expense (benefit) are as follows (in thousands):
<TABLE>
<CAPTION>
1996 1997 1998
------- ------- --------
<S> <C> <C> <C>
Current income tax.............................. $ 456 $ 124 $ (107)
Deferred income tax expense (benefit)........... 13,152 22,509 (2,626)
Net operating loss carryforward................. (2,939) (9,116) (33,118)
------- ------- --------
Income tax expense (benefit).................... $10,669 $13,517 $(35,851)
======= ======= ========
</TABLE>
CTF-15
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Deferred tax assets and liabilities are the result of temporary differences
between the financial statement carrying values and tax bases of assets and
liabilities. The Company's net deferred tax liabilities are recorded as a
current asset of $445,000 and a long-term liability of $21,320,000 at December
31, 1997, and a current asset of $24,816,000 and a long-term liability of
$6,892,000 at December 31, 1998. Significant components of net deferred tax
assets and liabilities are (in thousands):
<TABLE>
<CAPTION>
December 31
-----------------
1997 1998
-------- -------
<S> <C> <C>
Deferred tax assets:
Net operating loss carryforwards....................... $ 20,926 $54,044
Trust development expenses............................. 3,959 4,454
Accrued stock appreciation right and performance share
compensation.......................................... 739 576
Unrealized loss on trading securities.................. -- 24,686
Other.................................................. 1,593 2,626
-------- -------
Total deferred tax assets............................ 27,217 86,386
-------- -------
Deferred tax liabilities:
Intangible development costs........................... 37,856 48,913
Tax depletion and depreciation in excess of financial
statement amounts..................................... 8,008 16,894
Other.................................................. 2,228 2,655
-------- -------
Total deferred tax liabilities....................... 48,092 68,462
-------- -------
Net deferred tax assets (liabilities).................... $(20,875) $17,924
======== =======
</TABLE>
As of December 31, 1998, the Company has estimated tax loss carryforwards of
approximately $160 million, of which $10 million are related to capital losses.
The capital loss tax carryforwards expire in 2003 while the remaining $150
million are scheduled to expire in 2008 through 2013. The Company believes it
will be able to realize its deferred tax asset, as it plans to utilize its tax
loss carryforwards through gains generated from the sale of Hugoton Royalty
Trust units and non-strategic asset sales which are to begin in 1999.
6. Commitments and Contingencies
Leases
The Company leases offices, vehicles and certain other equipment in its
primary locations under non-cancelable operating leases. As of December 31,
1998, minimum future lease payments for all non-cancelable lease agreements
(including the sale and operating leaseback agreements described below) were as
follows (in thousands):
<TABLE>
<S> <C>
1999................................................................. $ 7,528
2000................................................................. 7,177
2001................................................................. 6,968
2002................................................................. 6,886
2003................................................................. 6,858
Remaining............................................................ 6,548
-------
$41,965
=======
</TABLE>
CTF-16
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Amounts incurred by the Company under operating leases (including renewable
monthly leases) were $5,489,000 in 1996, $9,132,000 in 1997 and $11,180,000 in
1998.
In March 1996, the Company sold its Tyrone gas processing plant and related
gathering system for $28 million and entered an agreement to lease the facility
from the buyers for an initial term of eight years at annual rentals of $4
million, and with fixed renewal options for an additional 13 years. The Company
does not have the right or option to purchase, nor does the lessor have the
obligation to sell the facility at any time. However, if the lessor decides to
sell the facility at the end of the initial term or any renewal period, the
lessor must first offer to sell it to the Company at its fair market value.
Additionally, the Company has a right of first refusal of any third party
offers to buy the facility after the initial term. This transaction has been
recorded as a sale and operating leaseback, with no gain or loss on the sale.
Proceeds of the sale were used to reduce bank debt.
In November 1996, the Company sold its gathering system in Major County,
Oklahoma for $8 million and entered an agreement to lease the facility from the
buyers for an initial term of eight years, with fixed renewal options for an
additional 10 years. Rentals are adjusted monthly based on the 30-day LIBOR
rate (Note 4) and may be irrevocably fixed by the Company with 20 days advance
notice. As of December 31, 1998, annual rentals were $1.7 million. The Company
does not have the right or option to purchase, nor does the lessor have the
obligation to sell the facility at any time. However, if the lessor decides to
sell the facility at the end of the initial term or any renewal period, the
lessor must first offer to sell it to the Company at its fair market value.
Additionally, the Company has a right of first refusal of any third party
offers to buy the facility after the initial term. This transaction has been
recorded as a sale and operating leaseback, with a deferred gain of $3.4
million on the sale. The deferred gain is amortized over the lease term based
on pro rata rentals and is recorded in other long-term liabilities in the
accompanying balance sheet. Proceeds of the sale were used to reduce bank debt.
Employment Agreements
Two executive officers have entered into year-to-year employment agreements
with the Company. The agreements are automatically renewed each year-end unless
terminated by either party upon thirty days notice prior to each December 31.
Under these agreements, each of the officers receives a minimum annual salary
of $300,000 and is entitled to participate in any incentive compensation
programs administered by the Board of Directors. The agreements also provide
that, in the event the officer terminates his employment for good reason, as
defined in the agreement, the officer will receive severance pay equal to the
amount that would have been paid under the agreement had it not been
terminated. If such termination follows a change in control of the Company, the
officer is entitled to a lump-sum payment of three times his most recent annual
compensation.
Gas Sales Contracts
The Company has entered into 1999 futures contracts to sell 175,000 Mcf per
day in April at $1.98 per Mcf, 160,000 Mcf per day in May and June at $1.96 per
Mcf, 40,000 Mcf per day in July at $2.00 per Mcf, 50,000 Mcf per day in August
and September at $2.04 per Mcf and 30,000 Mcf per day in October through
December at an average of $2.13 per Mcf. Prices to be realized for hedged
production may be less than these hedged prices because of location, quality
and other adjustments.
The Company has entered into basis swap agreements that effectively fix the
San Juan Basin basis at $0.25 per Mcf for 30,000 Mcf per day for April and May
1999 and 20,000 Mcf per day from
CTF-17
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
June through December 1999, and $0.28 per Mcf for 10,000 Mcf per day from
January through December 2000. The Company has basis swap agreements that
effectively fix the Wyoming basis at $0.27 per Mcf for 15,000 Mcf per day for
April 1999 and 10,000 Mcf per day from May through December 1999. The Company
also has basis swap agreements that effectively fix Oklahoma basis at $0.13 per
Mcf for 10,000 Mcf per day for April 1999 through December 1999.
The Company's termination of futures contracts related to first quarter 1999
gas production, net of the effects of basis swap agreements, resulted in a net
gain of $6.4 million. This gain will be recognized as additional gas revenue of
approximately $0.25 per Mcf in the first quarter of 1999.
The Company has committed a minimum gas sales price of $2.00 per Mcf for gas
sales related to April 1999 through March 2000 distributions of the Hugoton
Royalty Trust. The Company plans to sell approximately 40% of Hugoton Royalty
Trust units to the public in March or April 1999. The underlying volumes for
units to be sold to the public are approximately 36,000 Mcf per day.
Under the terms of its amended purchase and sale agreement with Shell for
the Cook Inlet Acquisition (Note 12), the Company has committed to sell to
Shell 20,000 Mcf of gas per day from March 1, 1999 through 2003 in the San Juan
Basin with an estimated basis differential of $0.24 per Mcf. The Company has
also agreed to sell Shell in East Texas daily gas volumes of 22,000 Mcf in
1999, 20,000 Mcf in 2000, 17,500 Mcf in 2001, 16,500 Mcf in 2002 and 15,000 Mcf
in 2003 at the index price less a weighted average transportation fee of $0.24
per Mcf.
The Company has committed to sell all gas production from certain properties
in the East Texas Basin Acquisition to EEX Corporation at market prices through
the earlier of December 31, 2001, or until a total of approximately 34.3
billion cubic feet (27.8 billion cubic feet net to the Company's interest) of
gas has been delivered. Based on current production, this sales commitment is
approximately 24,700 Mcf (20,000 Mcf net to the Company's interest) per day.
From August 1995 through July 1998 the Company received an additional $0.30
to $0.35 per Mcf on 10,000 Mcf of gas per day. In exchange therefor, the
Company has agreed to sell 11,650 Mcf per day from August 1998 through May 2000
at the index price and 21,650 Mcf per day from June 2000 through July 2005 at a
contract price of approximately 10% of the month's average NYMEX futures
contract for West Texas Intermediate crude oil, adjusted for point of physical
delivery.
Section 29 Tax Credits
The Company has entered contracts to monetize Section 29 tax credits
generated by production from qualified properties, most of which were acquired
in December 1997. As a result, the Company received approximately $2.9 million
in 1998 and anticipates receiving approximately $2.8 million annually from 1999
through 2002 which will be recorded as gas revenue.
Litigation
On April 3, 1998, a class action lawsuit, styled Booth, et al. v. Cross
Timbers Oil Company, was filed against the Company in the District Court of
Dewey County, Oklahoma. The action was filed on behalf of all persons who, at
any time since June 1991, have been paid royalties on gas produced from any gas
well within the State of Oklahoma under which the Company has assumed the
obligation to pay royalties. The plaintiffs allege that the Company has reduced
royalty payments by post-production deductions and has entered into contracts
with subsidiaries that were not arms-length transactions, which actions reduced
the royalties paid to the plaintiffs and those similarly situated, and that
such actions are a breach of the leases under which the royalties are paid. The
CTF-18
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
plaintiffs are seeking an accounting and payment of the monies allegedly owed
to them. The Company filed motions to dismiss the action due to lack of proper
venue, which motions were denied. The decision denying the motions is being
appealed. A hearing on the class certification issue has not been scheduled.
Management believes it has strong defenses against this claim and intends to
vigorously defend the action. Management's estimate of the potential liability
from this claim has been accrued in the Company's financial statements.
On October 17, 1997, an action, styled United States of America ex rel.
Grynberg v. Cross Timbers Oil Company, et al., was filed in the U. S. District
Court for the Western District of Oklahoma against the Company and certain of
its subsidiaries by Jack J. Grynberg on behalf of the United States under the
qui tam provisions of the False Claims Act. The Company was not made aware of
the claim until the U.S. Justice Department contacted the Company in August
1998. The plaintiff alleges that the Company underpaid royalties on gas
produced from federal leases and lands owned by Native Americans by at least
20% during the past 10 years as a result of mismeasuring the volume of gas and
incorrectly analyzing its heating content. According to the U.S. Justice
Department, the plaintiff has made similar allegations in actions filed against
over 300 other companies. The plaintiff seeks to recover the amount of
royalties not paid, together with treble damages, a civil penalty of $5,000 to
$10,000 for each violation and attorney fees and expenses. The Company has not
been served with this complaint that is under review by the U.S. Justice
Department. The Company has filed a response with the U.S. Justice Department
and is awaiting its decision whether to intervene in the case. The Company
believes that the allegations of this lawsuit are without merit and intends to
vigorously defend the action.
The Company is involved in various other lawsuits and certain governmental
proceedings arising in the ordinary course of business. Company management and
legal counsel do not believe that the ultimate resolution of these claims,
including the lawsuits described above, will have a material effect on the
Company's financial position, liquidity or operations.
Other
To date, the Company's expenditures to comply with environmental or safety
regulations have not been significant and are not expected to be significant in
the future. However, developments such as new regulations, enforcement policies
or claims for damages could result in significant future costs.
See also Notes 3 and 12.
7. Equity
Three-for-Two Stock Split
The Company effected a three-for-two common stock split on March 19, 1997
and February 25, 1998. All common stock shares, treasury stock shares and per
share amounts have been retroactively restated to reflect this stock split.
Common Stock
On April 27, 1998, the Company completed a public offering of 7,500,000
shares of common stock, of which 7,203,450 shares were sold by the Company and
296,550 shares were sold by a
CTF-19
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
stockholder. The Company's net proceeds from the offering of $133.1 million
were used to partially repay bank debt used to fund the East Texas Basin
Acquisition that closed on April 24, 1998 (Note 12). The offering was made
pursuant to the shelf registration statement filed with the Commission in
February 1998. See "--Registration Statement" below.
On September 30, 1998, the Company issued from treasury 1,921,850 shares to
Shell Western E&P, Inc., Shell Deepwater Development Holdings, Inc., and Shell
Offshore Inc. ("Shell") for the Cook Inlet Acquisition (Note 12). As of
December 31, 1998, these shares are valued at $7.50 per share, or a total of
$14.4 million. The Company effectively guaranteed Shell a $20 per share value,
resulting in an accrued liability of $12.50 per share, or a total of $24
million, that is included in accounts payable and accrued liabilities in the
accompanying consolidated balance sheet at December 31, 1998.
Performance Shares
The Company issued performance shares totaling 167,625 shares in 1996,
180,000 shares in 1997 and 82,125 shares in 1998 (Note 11).
Treasury Stock
The Company's treasury share acquisitions totaled 3,341,515 shares in 1996
at an average cost of $10.45 per share, 2,571,396 shares in 1997 at an average
cost of $12.06 per share and 4,373,138 shares in 1998 at an average cost of
$15.19 per share. Additionally, the Company received 457,994 shares in 1996,
421,212 shares in 1997 and 8,904 shares in 1998 that are held in treasury, as
payment for the option price upon exercise of stock options.
Shareholder Rights Plan
On August 25, 1998, the Board of Directors adopted a shareholder rights plan
that is designed to assure that all shareholders receive fair and equal
treatment in the event of any proposed takeover of the Company. Under this
plan, a dividend of one preferred share purchase right ("Right") was declared
for each outstanding share of common stock, par value $.01 per share, payable
on September 15, 1998 to shareholders of record on that date. Each Right
entitles shareholders to buy one one-thousandth of a share of newly created
Series A Junior Participating Preferred Stock at an exercise price of $80,
subject to adjustment in the event a person acquires, or makes a tender or
exchange offer for, 15% or more of the outstanding common stock. In such event,
each Right entitles the holder (other than the person acquiring 15% or more of
the outstanding common stock) to purchase shares of common stock with a market
value of twice the Right's exercise price. At any time prior to such event, the
Board of Directors may redeem the Rights at one cent per Right. The Rights can
be transferred only with common stock and expire in ten years.
Registration Statement
In February 1998, the Company filed a shelf registration statement with the
Commission to potentially offer securities which may include debt securities,
preferred stock, common stock or warrants to purchase debt securities,
preferred stock or common stock. The shelf registration statement was amended
on April 8, 1998 to increase the maximum total price of securities to be
offered to $400 million at prices and on terms to be determined at the time of
sale. Net proceeds from the sale of such securities will be used for general
corporate purposes, including reduction of bank debt. After the April 1998
common stock offering, $253.8 million remains available under the shelf
registration statement for future sales of securities.
CTF-20
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Common Stock Warrants
As partial consideration for producing properties acquired in December 1997
(Note 12), the Company issued warrants to purchase 937,500 shares of common
stock at a price of $15.31 per share for a period of five years. These warrants
were valued at $5,725,000 and recorded as additional paid-in capital.
Common Stock Dividends
Since the Company's inception, the Board of Directors has declared quarterly
dividends of $0.033 per common share through 1996, $0.037 per common share in
1997 and $0.04 per common share in 1998. In February 1999, the quarterly
dividend was reduced to $0.01 per common share in response to the low commodity
price environment and the Company's 1999 goal to reduce debt by $300 million.
See Note 4 regarding restrictions on dividends.
Series A Convertible Preferred Stock
In September 1996, pursuant to the Company's exchange offer, a total of
2,979,249 shares of common stock were exchanged for 1,138,729 shares of Series
A convertible preferred stock ("Preferred Stock"). The Company incurred costs
of $540,000 related to this exchange offer. All exchanged shares of common
stock have been canceled and are authorized but unissued. Preferred Stock is
recorded in the accompanying consolidated balance sheet at its liquidation
preference of $25 per share.
Cumulative dividends on Preferred Stock are payable quarterly in arrears,
when declared by the Board of Directors, based on an annual rate of $1.5625 per
share. The Preferred Stock has no stated maturity and no sinking fund, and is
redeemable, in whole or in part, by the Company after October 15, 1999.
Redemption is allowed only under certain circumstances on or before October 15,
2000 at $26.09 per share, and thereafter unconditionally at prices declining
ratably annually to $25.00 per share after October 15, 2006, plus dividends
accrued and unpaid to the redemption date.
The Preferred Stock is convertible at the option of the holder at any time,
unless previously redeemed, into shares of common stock at a rate of 2.16
shares of common stock for each share of Preferred Stock, subject to adjustment
in certain events. Preferred Stock holders are allowed one vote for each common
share into which their Preferred Stock may be converted.
Convertible Debt
During November and December 1996, $27.7 million principal of the Company's
5 1/4% convertible subordinated notes (Note 4) was converted by noteholders
into 2,696,521 shares of common stock. In January 1997, principal of $29.7
million of the notes was converted by noteholders into 2,892,363 shares of
common stock.
8. Financial Instruments
The Company uses financial and commodity-based derivative contracts to
manage exposures to interest rate and commodity price fluctuations. The Company
does not hold or issue derivative financial instruments for speculative or
trading purposes.
CTF-21
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Commodity Price Hedging Instruments
The Company periodically enters into futures contracts, energy swaps,
collars, basis swaps and option agreements to hedge its exposure to price
fluctuations on crude oil and natural gas sales. The Company did not have
significant commodity hedging activity during 1996 or 1997. During 1998, the
Company recognized net gains of $7.7 million primarily related to futures
contracts and basis swap transactions. This gain is recorded as a component of
natural gas sales. See Note 6.
Interest Rate Swap Agreements
In September 1998, to reduce variable interest rate exposure on debt, the
Company entered into a series of interest rate swap agreements, effectively
fixing its interest rate at an average of 6.9% on a total notional balance of
$150 million until September 2005. Settlements of net amounts due are made
quarterly, based on LIBOR rates (Note 4), which is the same interest rate basis
as the Company's senior debt borrowings.
In February and March 1999, the Company terminated its interest rate swaps
on notional balances totaling $100 million, resulting in proceeds received and
a gain of $1.1 million. This gain will be amortized against interest expense
through September 2005. In February 1999, the Company sold a call option that
allows the counterparty to terminate the interest rate swap in September 2001
on the remaining $50 million notional balance, resulting in proceeds received
of $800,000. This amount will be deferred until the option is exercised or
expires.
Fair Value
Because of their short-term maturity, the fair value of cash and cash
equivalents, accounts receivable and accounts payable approximates their
carrying values at December 31, 1997 and 1998. The following are estimated fair
values and carrying values of the Company's other financial instruments at each
of these dates (in thousands):
<TABLE>
<CAPTION>
Asset (Liability)
------------------------------------------
December 31, 1997 December 31, 1998
-------------------- --------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Investment in equity
securities................... $ -- $ -- $ 44,386 $ 44,386
Short-term debt............... -- -- (4,962) (4,962)
Long-term debt................ (539,000) (538,288) (921,000) (894,750)
Futures contracts............. -- -- -- 3,525
Basis swap agreements......... -- -- -- (690)
Interest rate swap
agreements................... -- -- -- (2,722)
</TABLE>
The fair value of short-term borrowings and bank borrowings approximates the
carrying value because of short-term interest rate maturities. The fair value
of subordinated notes is based on a current market quote, while other long-term
debt is based on the estimated present value of expected cash flows. The fair
value of all other financial instruments is based on current market quotes.
CTF-22
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Concentrations of Credit Risk
Although the Company's cash equivalents and derivative financial instruments
are exposed to the risk of credit loss, the Company does not believe such risk
to be significant. Cash equivalents are high-grade, short-term securities,
placed with highly rated financial institutions. Most of the Company's
receivables are from a broad and diverse group of energy companies and,
accordingly, do not represent a significant credit risk. The Company's gas
marketing activities generate receivables from customers including pipeline
companies, local distribution companies and end-users in various industries.
Letters of credit or other appropriate security are obtained as considered
necessary to limit risk of loss. The Company recorded an allowance for
collectibility of all accounts receivable of $911,000 at December 31, 1997 and
$375,000 at December 31, 1998. Financial and commodity-based swap contracts
expose the Company to the credit risk of non-performance by the counterparty to
the contracts. The Company does not believe this risk is significant since
these contracts are placed with major banks and financial institutions.
CTF-23
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
9. Earnings Per Share
The following reconciles earnings (numerator) and shares (denominator) used
in the computation of basic and diluted earnings per share (in thousands,
except per share data):
<TABLE>
<CAPTION>
Earnings
Earnings Shares per Share
-------- ------ ---------
<S> <C> <C> <C>
1996
Basic
Net income.................................... $ 20,304
Preferred stock dividends..................... (514)
--------
Earnings available to common stock -- basic... 19,790 39,913 $ 0.50
======
Diluted
Effect of dilutive securities:
Stock options............................... -- 361
5 1/4% convertible subordinated notes....... 2,570 6,039
-------- ------
Earnings available to common stock --
diluted...................................... $ 22,360 46,313 $ 0.48
======== ====== ======
1997
Basic
Net income.................................... $ 25,684
Preferred stock dividends..................... (1,779)
--------
Earnings available to common stock -- basic... 23,905 39,773 $ 0.60
======
Diluted
Effect of dilutive securities:
Stock options............................... -- 451
Warrants.................................... -- 3
5 1/4% convertible subordinated notes....... 46 115
-------- ------
Earnings available to common stock --
diluted...................................... $ 23,951 40,342 $ 0.59
======== ====== ======
1998
Basic
Net loss...................................... $(69,719)
Preferred stock dividends..................... (1,779)
--------
Loss available to common stock -- basic....... (71,498) 43,396 $(1.65)
======
Diluted
Effect of dilutive securities (a):
Stock options............................... -- 338
Warrants.................................... -- 23
-------- ------
Loss available to common stock-diluted........ $(71,498) 43,757 $(1.65)(b)
======== ====== ======
</TABLE>
- --------
(a) Based on common shares outstanding at December 31, 1998, potential
conversion of Series A convertible preferred stock becomes dilutive to
earnings per share when annual earnings available to common stock exceeds
approximately $32.4 million and when quarterly earnings available to common
stock exceeds approximately $8.1 million.
(b) Because of the antidilutive effect of dilutive securities on loss per
common share, diluted loss available to common stock is the same as basic.
CTF-24
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
10. Supplemental Cash Flow Information
The consolidated statements of cash flows exclude the following non-cash
transactions:
--The Cook Inlet Acquisition on September 30, 1998 (Note 12), a purchase of
oil-producing properties for 1,921,850 shares of common stock, a related
effective guarantee of $20 per share value (Note 7) and a $6 million note
payable (Note 4)
--Issuance of warrants in 1997 to purchase 937,500 shares of common stock
and exchange of properties valued at $15.7 million, as partial
consideration for producing properties acquired
--Grants of performance shares of 167,625 in 1996, 180,000 in 1997 and
82,125 in 1998 to key employees and nonemployee directors (Note 11)
--Vesting of performance shares of 243,000 in 1997 and 81,000 in 1998
--Receipt of common stock of 457,994 shares (valued at $4,768,000) in 1996,
421,212 shares (valued at $5,430,000) in 1997 and 8,904 shares (valued at
$181,000) in 1998 for the option price of exercised stock options
--Conversion of 5 1/4% convertible subordinated notes of $27.7 million
principal amount into 2,696,521 shares of common stock in 1996 and $29.7
million principal amount into 2,892,363 shares of common stock in 1997
--Exchange of 2,979,249 shares of common stock for 1,138,729 shares of
Series A convertible preferred stock in 1996
Interest payments totaled $16,369,000 in 1996 and $21,276,000 in 1997.
Interest payments during 1998 totaled $57,200,000, including $1,070,000 of
capitalized interest. Income tax payments were $6,000 in 1996 and $941,000 in
1997; during 1998, net income tax refunds were $454,000.
11. Employee Benefit Plans
401(k) Plan
The Company sponsors a 401(k) benefit plan that allows employees to
contribute and defer a portion of their wages. The Company matches employee
contributions of up to 10% of wages (8% of wages prior to January 1, 1998).
Employee contributions vest immediately while the Company's matching
contributions vest 100% after three years of service. All employees over 21
years of age and with at least three months service with the Company may
participate. Company contributions under the plan were $979,000 in 1996,
$1,180,000 in 1997 and $1,766,000 in 1998.
1991 Stock Incentive Plan
A total of 1,012,500 incentive units ("Units"), have been granted to
directors, officers and other key employees under the 1991 Stock Incentive Plan
("1991 Plan"). Units consist of a stock option ("Option") and a stock
appreciation right ("SAR"). An Option provides the right to purchase one share
of common stock at the exercise price, which generally is the market price at
the date the Unit is granted. A SAR entitles the recipient to a payment equal
to twice the excess of the market price of one share of common stock on the
date the Option is exercised over the exercise price. As of December 31, 1998,
3,341 Units remain available for grant under the 1991 Plan. General and
administrative expense includes stock incentive compensation expense related to
SARs of $3.7 million in 1996 and $359,000 in 1997, and a reduction of stock
incentive compensation expense of $299,000 in 1998. SAR cash payments were $7.1
million in 1996, $288,000 in 1997 and $180,000 in 1998.
CTF-25
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
1994 and 1997 Stock Incentive Plans
Under the 1994 Stock Incentive Plan ("1994 Plan") and the 1997 Stock
Incentive Plan ("1997 Plan"), a total of 2,250,000 shares of common stock may
be issued under each plan to directors, officers and other key employees
pursuant to grants of Options or performance shares of common stock
("performance shares"). At December 31, 1998, 25,177 shares remained available
for grant under the 1994 Plan and 102,624 shares remained available for grant
under the 1997 Plan. Options vest and become exercisable on terms specified
when granted by the compensation committee of the Board of Directors. Options
granted under the 1994 Plan are not exercisable prior to six months and no
Option is exercisable after ten years from its grant date. Options granted
under the 1994 Plan and the 1997 Plan generally vest in equal amounts over five
years, with provisions for earlier vesting if specified performance
requirements are met. In May 1998, all options under the 1994 Plan vested by
resolution of the Board of Directors. As of December 31, 1998, there are
356,250 outstanding stock options under the 1997 Plan that vest when the common
stock price reaches $25.
1998 Stock Incentive Plan
In May 1998, the stockholders approved the 1998 Stock Incentive Plan ("1998
Plan") under which 6 million shares of common stock are available for grant.
Grants under the 1998 Plan are subject to the provision that outstanding stock
options and performance shares under all the Company's stock incentive plans
cannot exceed 6% of the Company's outstanding common stock at the time such
grants are made. During 1998, 675,750 stock options were granted under the 1998
Plan. Additionally, 810,375 stock options were designated to be granted to
specific optionees upon each of their exercises of all outstanding vested
options granted under the 1997 Plan. Stock options will vest and become
exercisable annually in equal amounts over a five-year period, with provision
for accelerated vesting of half the options when the common stock price first
closes at or above $25, and of the remainder when the common stock price first
closes at or above $30.
Performance Shares
Performance shares granted under the 1994, 1997 and 1998 Plans are subject
to restrictions determined by the Committee and are subject to forfeiture if
performance targets are not met. Otherwise, holders of performance shares
generally have all the voting, dividend and other rights of other stockholders.
The Company issued performance shares to key employees totaling 154,125 in
1996, 169,875 in 1997 and 72,000 in 1998, of which 243,000 vested in 1997 and
81,000 vested in 1998 when the common stock price reached specified levels.
General and administrative expense includes compensation related to these
performance share grants of $2.5 million in 1996, $3.3 million in 1997 and $1.6
million in 1998. As of December 31, 1998, there are 72,000 performance shares
that vest when the common stock price reaches $22.50. The Company also issued
to nonemployee directors a total of 13,500 performance shares in 1996 and
10,125 performance shares in each of 1997 and 1998, which vested upon grant.
Royalty Trust Option Plan
In May 1998, the stockholders approved the 1998 Royalty Trust Option Plan
("Option Plan"). Under the terms of the Option Plan, the Company may grant to
key employees options to purchase units of beneficial interest in one or more
royalty trusts that may be established by the Company. Such options will allow
the purchase of royalty trust units at fair market value on the date of grant
in an aggregate amount not to exceed $12 million. In December 1998, the Company
granted options to
CTF-26
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
purchase Hugoton Royalty Trust units at a total price of $12 million, subject
to completion of the initial public offering of the Hugoton Royalty Trust
within six months of the date of grant. The options will be priced at the
initial public offering price.
Unit/Option Activity and Balances
The following summarizes Unit and Option activity and balances from 1996
through 1998:
<TABLE>
<CAPTION>
1994, 1997
Weighted and
Average 1991 Plan 1998 Plans
Exercise Incentive Stock
Price Units Options
-------- --------- ----------
<S> <C> <C> <C>
1996
Beginning of year............................. $ 6.27 835,810 1,399,250
Grants...................................... 9.64 -- 303,750
Exercises................................... 5.70 (784,658) (211,079)
Forfeitures................................. 6.61 (189) (4,925)
-------- ----------
End of year................................... 7.32 50,963 1,486,996
======== ==========
Exercisable at end of year.................... 6.66 50,963 1,006,146
======== ==========
1997
Beginning of year............................. $ 7.32 50,963 1,486,996
Grants...................................... 12.11 -- 1,757,250
Exercises................................... 6.75 (26,213) (897,234)
Forfeitures................................. 8.79 -- (18,315)
-------- ----------
End of year................................... 11.11 24,750 2,328,697
======== ==========
Exercisable at end of year.................... 10.96 24,750 1,119,044
======== ==========
1998
Beginning of year............................. $11.11 24,750 2,328,697
Grants...................................... 17.52 -- 1,395,750
Exercises................................... 11.64 (6,750) (1,081,711)
Forfeitures................................. 17.19 -- (21,750)
-------- ----------
End of year................................... 14.23 18,000 2,620,986
======== ==========
Exercisable at end of year.................... 11.03 18,000 1,351,236
======== ==========
</TABLE>
CTF-27
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following summarizes information about Units/Options at December 31,
1998:
<TABLE>
<CAPTION>
Units/Options Outstanding Units/Options Exercisable
---------------------------- ----------------------------
Weighted Weighted Weighted
Average Average Average
Range of Remaining Exercise Exercise
Exercise Prices Number Term Price Number Price
--------------- --------- --------- -------- -------------- -------------
<S> <C> <C> <C> <C> <C>
1991 Plan
$5.32-7.56............ 18,000 3.1 years $ 5.43 18,000 $ 5.43
1994, 1997 and 1998
Plans
$6.61-7.89............ 235,015 6.5 years 7.23 235,015 7.23
$9.67-10.92........... 264,971 7.4 years 9.68 264,971 9.68
$12.04-13.40.......... 762,500 8.4 years 12.27 747,000 12.21
$15.53-18.22.......... 1,358,500 9.4 years 17.58 104,250 15.54
--------- --------------
2,638,986 1,369,236
========= ==============
</TABLE>
Estimated Fair Value of Grants
Using the Black-Scholes option-pricing model and the following assumptions,
the weighted average fair value of option grants was estimated to be $3.82 in
1996, $5.05 in 1997 and $6.82 in 1998.
<TABLE>
<CAPTION>
1996 1997 1998
------- ------- -------
<S> <C> <C> <C>
Risk-free interest rates............................. 6.4% 6.4% 5.6%
Dividend yield....................................... 1.4% 1.6% 3.2%
Weighted average expected lives...................... 6 years 5 years 5 years
Volatility........................................... 35% 47% 52%
</TABLE>
Pro Forma Effect of Recording Stock-Based Compensation at Estimated Fair Value
The following are pro forma earnings (loss) available to common stock and
earnings (loss) per common share for 1996, 1997 and 1998, as if stock-based
compensation had been recorded at the estimated fair value of stock awards at
the grant date, as prescribed by SFAS 123, Accounting for Stock-Based
Compensation (Note 1):
<TABLE>
<CAPTION>
1996 1997 1998
------- ------- --------
(in thousands, except
per share data)
<S> <C> <C> <C>
Earnings (loss) available to common stock:
As reported..................................... $19,790 $23,905 $(71,498)
Pro forma....................................... $19,767 $21,646 $(75,785)
Earnings (loss) per common share:
Basic
As reported................................... $ 0.50 $ 0.60 $ (1.65)
Pro forma..................................... $ 0.50 $ 0.54 $ (1.75)
Diluted
As reported................................... $ 0.48 $ 0.59 $ (1.65)
Pro forma..................................... $ 0.48 $ 0.54 $ (1.75)
</TABLE>
CTF-28
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
12. Acquisitions
On May 14, 1997, the Company acquired primarily gas-producing properties in
Oklahoma, Kansas and Texas for an estimated adjusted purchase price of $39
million from a subsidiary of Burlington Resources Inc. The properties are
primarily operated interests. The Company funded the acquisition with bank debt
and cash flow from operations.
On December 1, 1997, the Company acquired interests in certain producing oil
and gas properties in the San Juan Basin of New Mexico ("Amoco Acquisition")
from a subsidiary of Amoco Corporation ("Amoco") for $252 million, including
warrants to purchase 937,500 shares of the Company's common stock at a price of
$15.31 per share for a period of five years. After adjustments for other
acquisition costs, estimated cash flows through date of closing and
preferential purchase rights exercised by third parties, the properties were
purchased for approximately $195 million, including approximately $5.7 million
value for the warrants. Amoco elected to accept certain producing properties
owned by the Company valued at $15.7 million in lieu of cash, reducing cash
consideration to $173.6 million, which was funded with bank debt. Additional
purchase price revisions may result from post-closing adjustments.
On April 24, 1998, the Company acquired producing properties in the East
Texas Basin from EEX Corporation ("East Texas Basin Acquisition") for $265
million. After purchase price adjustments primarily resulting from net revenues
from the January 1, 1998 effective date through April 24, 1998, the properties
were purchased for an estimated price of $245 million. In connection with the
acquisition, the Company sold a production payment to EEX Corporation for $30
million. The production payment is payable from production from certain
properties acquired in the East Texas Basin Acquisition during the 10-year
period beginning January 1, 2002. EEX Corporation effectively pays all taxes,
royalties and production expenses related to such production. The Company has
the option to repurchase a portion of this production payment each December,
beginning in 1998; this option was not exercised in December 1998. The cost of
the East Texas Basin Acquisition (net of the production payment sold) of $215
million was funded by bank borrowings which were partially repaid by proceeds
from the sale of common stock (Note 7). Purchase price revisions may result
from post-closing adjustments.
On September 30, 1998, the Company acquired oil-producing properties in the
Middle Ground Shoal Field of Alaska's Cook Inlet ("Cook Inlet Acquisition")
from various Shell Oil Company affiliates ("Shell"). The acquired interests
include a 100% working interest in two State of Alaska leases, two offshore
production platforms and a 50% interest in certain operated production
pipelines and onshore processing facilities. The acquisition had an effective
date of July 1, 1998, and is subject to customary post-closing adjustments. The
Company acquired the properties in exchange for 1,921,850 shares of the
Company's common stock. These shares are subject to a contractual $20 price
guarantee, resulting in an accrued liability of $24 million recorded at
December 31, 1998 (Note 7). The Company also executed a non-interest bearing
promissory note to Shell for $6 million. Payments under this note of $3
million, $2 million and $1 million are due when the average NYMEX crude oil
price for 60 consecutive calendar days equals or exceeds $18.50, $19.50 and
$20.50, respectively. The total estimated purchase price of the Cook Inlet
Acquisition is $44.4 million. See Note 3.
On March 1, 1999, the Company and Shell entered into an amended agreement to
postpone Shell's resale of Company common stock to not later than August 16,
1999. Prior to that date, the Company will have the options of purchasing the
common stock from Shell, registering the shares for resale by Shell, or
exchanging the shares with another Company security to be resold by Shell. In
CTF-29
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
the interim, the Company has agreed to make payments to Shell of up to $20
million, including a payment of $5 million on March 2, 1999, and has entered
into gas sales and transportation contracts that provide Shell with an
estimated value of $7.5 million. If Shell's proceeds from the sale of Company
securities exceeds the remaining amount due Shell, the difference will be
refunded to the Company; otherwise the difference will be paid to Shell.
On November 20, 1998, the Company acquired primarily gas-producing
properties in northwest Oklahoma and the San Juan Basin of New Mexico for $33.4
million from Seagull Energy Corp. After purchase price adjustments primarily
resulting from net revenues from the October 1, 1998 effective date through
November 20, 1998, the properties were purchased for an estimated price of
$29.2 million. Additional purchase price revisions may result from post-closing
adjustments. The Company funded the acquisition with existing lines of credit.
These acquisitions have been recorded using the purchase method of
accounting. The following presents unaudited pro forma results of operations
for the years ended December 31, 1997 and 1998 as if these acquisitions and the
April 1998 sale of common stock had been consummated as of January 1, 1997 and
1998. These pro forma results are not necessarily indicative of future results.
<TABLE>
<CAPTION>
Pro Forma (Unaudited)
---------------------
1997 1998
---------- ----------
(in thousands, except
per share data)
<S> <C> <C>
Revenues............................................. $ 366,041 $ 293,201
========== ==========
Net income (loss).................................... $ 59,924 $ (64,374)
========== ==========
Earnings (loss) available to common stock............ $ 58,145 $ (66,153)
========== ==========
Earnings (loss) per common share:
Basic.............................................. $ 1.19 $ (1.41)
========== ==========
Diluted............................................ $ 1.15 $ (1.41)
========== ==========
</TABLE>
The Company filed a registration statement with the Commission in December
1998 to sell approximately 40% of the Hugoton Royalty Trust units to the public
in March or April 1999 (Note 1). The unit sales price is expected to be in the
range of $9.00 to $10.00. Assuming the underwriters' overallotment option is
not exercised, the Company will sell 15,000,000 units, or 37.5% of the Trust.
Based on a mid-range price of $9.50 per unit, net proceeds to be received by
the Company is estimated to be $131.9 million, net of underwriters' discount
and offering expenses. Proceeds from the sale will be used to reduce bank debt.
Pro forma results of operations for the year ended December 31, 1998, as if the
sale of Trust units and the acquisitions described above were consummated as of
January 1, 1998, would be: revenues of $269.2 million, net loss of $63.7
million and loss available to common stock of $65.5 million, or $1.39 per
common share.
CTF-30
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
13. Quarterly Financial Data (Unaudited)
The following are summarized quarterly financial data for the years ended
December 31, 1997 and 1998 (in thousands, except per share data):
<TABLE>
<CAPTION>
Quarter
-----------------------------------
1st 2nd 3rd 4th
------- ------- -------- --------
<S> <C> <C> <C> <C>
1997
Revenues................................. $52,286 $45,520 $ 43,734 $ 56,732
Gross profit (a)......................... $24,625 $16,595 $ 14,242 $ 23,834
Earnings available to common stock....... $10,650 $ 3,735 $ 2,779 $ 6,741
Earnings per common share
Basic.................................. $ 0.26 $ 0.09 $ 0.07 $ 0.17
Diluted................................ $ 0.25 $ 0.09 $ 0.07 $ 0.17
Average shares outstanding............... 40,395 39,498 39,581 39,629
1998
Revenues................................. $49,968 $61,652 $ 67,044 $ 70,822
Gross profit (a)......................... $13,007 $14,510 $ 16,568 $ 9,656
Earnings available to common stock....... $ (184) $ 759 $(31,004) $(41,069)
Earnings per common share
Basic.................................. $ 0.00 $ 0.02 $ (0.69) $ (0.90)
Diluted................................ $ 0.00 $ 0.02 $ (0.69) $ (0.90)
Average shares outstanding............... 39,046 43,940 44,765 45,440
</TABLE>
- --------
(a) Operating income before general and administrative expense.
14. Supplementary Financial Information for Oil and Gas Producing Activities
(Unaudited)
All of the Company's operations are directly related to oil and gas
producing activities located in the United States.
Costs Incurred Related to Oil and Gas Producing Activities
The following table summarizes costs incurred whether such costs are
capitalized or expensed for financial reporting purposes (in thousands):
<TABLE>
<CAPTION>
1996 1997 1998
-------- -------- --------
<S> <C> <C> <C>
Acquisitions:
Producing properties............................ $105,252 $251,663 $339,889
Undeveloped properties.......................... 563 3,964 514
Development (a)................................... 44,758 86,555 69,367
Exploration (b)................................... 280 2,088 8,034
-------- -------- --------
Total......................................... $150,853 $344,270 $417,804
======== ======== ========
</TABLE>
- --------
(a) Includes capitalized interest of $800,000 in 1997 and $1,070,000 in 1998.
No interest was capitalized in prior years.
(b) Primarily includes geological and geophysical costs.
CTF-31
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Proved Reserves
Independent petroleum engineers have estimated the Company's proved oil and
gas reserves, all of which are located in the United States. Proved reserves
are the estimated quantities that geologic and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed
reserves are the quantities expected to be recovered through existing wells
with existing equipment and operating methods. Due to the inherent
uncertainties and the limited nature of reservoir data, such estimates are
subject to change as additional information becomes available. The reserves
actually recovered and the timing of production of these reserves may be
substantially different from the original estimate. Revisions result primarily
from new information obtained from development drilling and production history
and from changes in economic factors.
Standardized Measure
The standardized measure of discounted future net cash flows ("standardized
measure") and changes in such cash flows are prepared using assumptions
required by the Financial Accounting Standards Board. Such assumptions include
the use of year-end prices for oil and gas and year-end costs for estimated
future development and production expenditures to produce year-end estimated
proved reserves. Discounted future net cash flows are calculated using a 10%
rate. Estimated future income taxes are calculated by applying year-end
statutory rates to future pre-tax net cash flows, less the tax basis of related
assets and applicable tax credits.
The standardized measure does not represent management's estimate of the
Company's future cash flows or the value of proved oil and gas reserves.
Probable and possible reserves, which may become proved in the future, are
excluded from the calculations. Furthermore, year-end prices used to determine
the standardized measure of discounted cash flows, are influenced by seasonal
demand and other factors and may not be the most representative in estimating
future revenues or reserve data.
CTF-32
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
<TABLE>
<CAPTION>
Oil Gas Natural Gas
(Bbls) (Mcf) Liquids (Bbls) (a)
------ --------- ------------------
(in thousands)
<S> <C> <C> <C>
Proved Reserves
December 31, 1995......................... 39,988 358,070
Revisions............................... 2,361 29,379
Extensions, additions and discoveries... 2,220 37,480
Production.............................. (3,508) (37,275)
Purchases in place...................... 1,552 153,400
Sales in place.......................... (173) (516)
------ ---------
December 31, 1996......................... 42,440 540,538 --
Revisions............................... (989) (14,182) --
Extensions, additions and discoveries... 9,263 112,906 --
Production.............................. (3,980) (49,587) (80)
Purchases in place...................... 3,195 248,040 13,890
Sales in place.......................... (2,075) (21,940) --
------ --------- ------
December 31, 1997......................... 47,854 815,775 13,810
Revisions............................... (5,893) (5,429) 2,631
Extensions, additions and discoveries... 821 172,059 1,875
Production.............................. (4,598) (83,847) (1,222)
Purchases in place...................... 16,331 311,260 80
Sales in place.......................... (5) (594) --
------ --------- ------
December 31, 1998......................... 54,510 1,209,224 17,174
====== ========= ======
Proved Developed Reserves
December 31, 1995....................... 28,946 320,230
====== =========
December 31, 1996....................... 31,883 466,412
====== =========
December 31, 1997....................... 33,835 677,710 11,494
====== ========= ======
December 31, 1998....................... 42,876 968,495 14,000
====== ========= ======
</TABLE>
- --------
(a) Proved reserves attributable to natural gas liquids were not considered
significant prior to the Amoco Acquisition in December 1997 (Note 12).
Natural gas liquids proved reserves as disclosed include only San Juan
Basin properties purchased in this acquisition.
CTF-33
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves
<TABLE>
<CAPTION>
December 31
----------------------------------
1996 1997 1998
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>
Future cash inflows........................ $2,634,641 $2,604,453 $3,041,776
Future costs:
Production............................... (819,780) (979,317) (1,135,789)
Development.............................. (77,837) (140,594) (228,561)
---------- ---------- ----------
Future net cash flows before income tax.... 1,737,024 1,484,542 1,677,426
Future income tax.......................... (450,987) (291,375) (231,249)
---------- ---------- ----------
Future net cash flows...................... 1,286,037 1,193,167 1,446,177
10% annual discount........................ (579,556) (551,058) (637,774)
---------- ---------- ----------
Standardized measure (a)................... $ 706,481 $ 642,109 $ 808,403
========== ========== ==========
</TABLE>
- --------
(a) Before income tax, the year-end standardized measure (or discounted present
value of future net cash flows) was $946,150,000 in 1996, $782,322,000 in
1997 and $908,606,000 in 1998.
Changes in Standardized Measure of Discounted Future Net Cash Flows
<TABLE>
<CAPTION>
1996 1997 1998
-------- -------- --------
(in thousands)
<S> <C> <C> <C>
Standardized measure, January 1................... $335,156 $706,481 $642,109
-------- -------- --------
Revisions:
Prices and costs................................ 360,053 (388,559) (184,568)
Quantity estimates.............................. 34,099 55,497 65,600
Accretion of discount........................... 37,291 86,845 71,942
Future development costs........................ (36,267) (120,073) (104,636)
Income tax...................................... (169,118) 99,455 40,011
Production rates and other...................... (155) (1,614) (296)
-------- -------- --------
Net revisions................................. 225,903 (268,449) (111,947)
Extensions, additions and discoveries............. 49,802 92,582 96,829
Production........................................ (97,106) (125,343) (146,498)
Development costs................................. 33,484 73,062 56,904
Purchases in place (a)............................ 160,670 207,387 271,806
Sales in place.................................... (1,428) (43,611) (800)
-------- -------- --------
Net change.................................... 371,325 (64,372) 166,294
-------- -------- --------
Standardized measure, December 31................. $706,481 $642,109 $808,403
======== ======== ========
</TABLE>
- --------
(a) Based on the year-end present value (at year-end prices and costs) plus the
cash flow received from such properties during the year, rather than the
estimated present value at the date of acquisition.
CTF-34
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Year-end oil prices used in the estimation of proved reserves and
calculation of the standardized measure were, $18.00 for 1995, $24.25 for 1996,
$15.50 for 1997 and $9.50 for 1998. Year-end average gas prices were $1.68 for
1995, $3.02 for 1996, $2.20 for 1997 and $2.01 for 1998. Year-end average
natural gas liquids prices were $11.07 for 1997 and $3.99 for 1998. Proved oil
and gas reserves at December 31, 1998 include 209,000 Bbls and 8,278,000 Mcf,
and the standardized measure includes $7,930,000 attributable to the Company's
ownership of approximately 22% of the Cross Timbers Royalty Trust. Year-end
1998 oil and gas reserves also include 3,224,000 Bbls and 412,058,000 Mcf, and
the standardized measure includes $347.2 million attributable to the Company's
100% ownership of the Hugoton Royalty Trust.
Price and cost revisions are primarily the net result of changes in year-end
prices, based on beginning of year reserve estimates. Quantity estimate
revisions are primarily the result of extended economic life of proved reserves
and proved undeveloped reserve additions attributable to increased development
activity.
CTF-35
<PAGE>
CROSS TIMBERS OIL COMPANY
PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The accompanying Pro Forma Consolidated Financial Statements have been
prepared by recording pro forma adjustments to the historical consolidated
financial statements of the Company. The Pro Forma Consolidated Balance Sheet
as of December 31, 1998 has been prepared as if the Trust Offering, as
described in Note 3, was consummated on December 31, 1998. The Pro Forma
Consolidated Statement of Operations for the year ended December 31, 1998 has
been prepared as if the EEX Acquisition and certain other 1998 acquisition
transactions ("Other 1998 Acquisitions") and the Trust Offering were
consummated immediately prior to January 1, 1998.
The Pro Forma Consolidated Financial Statements are not necessarily
indicative of the financial position or results of operations which would have
occurred had the transactions occurred on the assumed dates. Additionally,
future results may vary significantly from the results reflected in the Pro
Forma Consolidated Statement of Operations due to normal production declines,
changes in prices, future transactions and other factors. These statements
should be read in conjunction with the Company's audited consolidated financial
statements and the related notes for the year ended December 31, 1998, included
in this prospectus.
CTF-36
<PAGE>
CROSS TIMBERS OIL COMPANY
PRO FORMA CONSOLIDATED BALANCE SHEET (Unaudited)
December 31, 1998
<TABLE>
<CAPTION>
Pro Forma
Adjustments
(Note 4)
------------------
Historical Trust Offering (a) Pro Forma
---------- ------------------ ----------
(in thousands)
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents......... $ 12,333 $ -- $ 12,333
Other current assets.............. 125,245 -- 125,245
---------- --------- ----------
Total Current Assets............ 137,578 -- 137,578
---------- --------- ----------
Property and Equipment, at cost..... 1,370,518 (128,107) 1,242,411
Accumulated depreciation,
depletion and amortization....... (319,507) 35,457 (284,050)
---------- --------- ----------
Net Property and Equipment...... 1,051,011 (92,650) 958,361
---------- --------- ----------
Other Assets........................ 19,005 -- 19,005
---------- --------- ----------
TOTAL ASSETS........................ $1,207,594 $ (92,650) $1,114,944
========== ========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued
liabilities...................... $ 93,583 $ -- $ 93,583
Other current liabilities......... 6,005 -- 6,005
---------- --------- ----------
Total Current Liabilities....... 99,588 -- 99,588
---------- --------- ----------
Long-term Debt...................... 921,000 (131,875) 789,125
---------- --------- ----------
Deferred Income Taxes Payable....... 6,892 -- 6,892
---------- --------- ----------
Other Long-term Liabilities......... 2,663 -- 2,663
---------- --------- ----------
Stockholders' Equity:
Preferred stock................... 28,468 -- 28,468
Common stock...................... 541 -- 541
Additional paid-in capital........ 338,503 -- 338,503
Treasury stock.................... (118,555) -- (118,555)
Retained earnings (deficit)....... (71,506) 39,225 (32,281)
---------- --------- ----------
Total Stockholders' Equity...... 177,451 39,225 216,676
---------- --------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY............................. $1,207,594 $ (92,650) $1,114,944
========== ========= ==========
</TABLE>
See Accompanying Notes to Pro Forma Consolidated Financial Statements.
CTF-37
<PAGE>
CROSS TIMBERS OIL COMPANY
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
For the Year Ended December 31, 1998
<TABLE>
<CAPTION>
Pro Forma Adjustments (Note 4)
--------------------------------------------------
EEX Other 1998
Acquisition Acquisitions Trust Total
Historical (b) (c) Other Offering (d) Pro Forma
---------- ----------- ------------ -------- ------------ ---------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C> <C>
REVENUES
Oil and condensate..... $ 56,164 $ 1,224 $12,422 $ -- $ (1,949) $ 67,861
Gas and natural gas
liquids............... 182,587 21,985 8,083 -- (22,068) 190,587
Gas gathering,
processing and
marketing............. 9,438 -- -- -- -- 9,438
Other.................. 1,297 -- -- -- -- 1,297
--------- ------- ------- -------- -------- ---------
Total Revenues......... 249,486 23,209 20,505 -- (24,017) 269,183
--------- ------- ------- -------- -------- ---------
EXPENSES
Production............. 63,148 2,512 6,404 1,931 (e) (5,724) 68,271
Exploration............ 8,034 -- -- -- -- 8,034
Taxes, transportation
and other............. 29,105 2,362 1,423 -- (2,721) 30,169
Depreciation, depletion
and amortization...... 83,560 -- -- 18,980 (f) (7,486) 95,054
Impairment............. 2,040 -- -- -- -- 2,040
General and
administrative........ 13,479 -- -- (1,330)(e) -- 12,149
Gas gathering and
processing............ 8,360 -- -- -- -- 8,360
Trust development
costs................. 1,498 -- -- -- -- 1,498
--------- ------- ------- -------- -------- ---------
Total Expenses......... 209,224 4,874 7,827 19,581 (15,931) 225,575
--------- ------- ------- -------- -------- ---------
OPERATING INCOME........ 40,262 18,335 12,678 (19,581) (8,086) 43,608
--------- ------- ------- -------- -------- ---------
OTHER INCOME (EXPENSE)
Gain (loss) on
investment in equity
securities............ (93,719) -- -- -- -- (93,719)
Interest expense, net.. (52,113) -- -- (3,334)(g) 9,089 (46,358)
--------- ------- ------- -------- -------- ---------
Total Other Income
(Expense)............. (145,832) -- -- (3,334) 9,089 (140,077)
--------- ------- ------- -------- -------- ---------
INCOME (LOSS) BEFORE
INCOME TAX............. (105,570) 18,335 12,678 (22,915) 1,003 (96,469)
Income Tax Expense
(Benefit).............. (35,851) -- -- 2,754 (h) 341 (32,756)
--------- ------- ------- -------- -------- ---------
NET INCOME (LOSS)....... (69,719) 18,335 12,678 (25,669) 662 (63,713)
Preferred Stock
Dividends.............. 1,779 -- -- -- -- 1,779
--------- ------- ------- -------- -------- ---------
EARNINGS (LOSS)
AVAILABLE TO COMMON
STOCK.................. $ (71,498) $18,335 $12,678 $(25,669) $ 662 $ (65,492)
========= ======= ======= ======== ======== =========
EARNINGS (LOSS) PER
COMMON SHARE
Basic.................. $ (1.65) $ (1.39)
========= =========
Diluted................ $ (1.65) $ (1.39)
========= =========
Weighted Average Common
Shares Outstanding..... 43,396 3,598 (i) 46,994
========= ======== =========
</TABLE>
See Accompanying Notes to Pro Forma Consolidated Financial Statements.
CTF-38
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. Basis of Presentation
The accompanying Pro Forma Consolidated Balance Sheet at December 31, 1998
has been prepared assuming Cross Timbers Oil Company ("the Company")
consummated the sale of 15,000,000, or 37.5%, of the Hugoton Royalty Trust
units to the public ("Trust Offering") on December 31, 1998 (Note 3). The Pro
Forma Consolidated Statement of Operations for the year ended December 31, 1998
has been prepared assuming the Company consummated the Trust Offering, EEX
Acquisition and Other 1998 Acquisitions immediately prior to January 1, 1998.
The Pro Forma Consolidated Statement of Operations is not necessarily
indicative of the results of operations had the above described transactions
occurred on the assumed dates.
2. Acquisitions
EEX Acquisition
On April 24, 1998, the Company acquired producing properties in the East
Texas Basin from EEX Corporation ("East Texas Basin Acquisition") for $265
million. After purchase price adjustments primarily resulting from net revenues
from the January 1, 1998 effective date through April 24, 1998, the properties
were purchased for an estimated price of $245 million. In connection with the
acquisition, the Company sold a production payment to EEX Corporation for $30
million. The cost of the East Texas Basin Acquisition (net of the production
payment sold) of $215 million was funded by bank borrowings which were
partially repaid by proceeds from the sale of 7,203,450 shares of the Company's
common stock on April 27, 1998. Purchase price revisions may result from post-
closing adjustments.
Other 1998 Acquisitions
The acquisitions described in the following paragraphs are collectively
referred to as the "Other 1998 Acquisitions."
On September 30, 1998, the Company acquired oil-producing properties in the
Middle Ground Shoal Field of Alaska's Cook Inlet ("Cook Inlet Acquisition")
from various Shell Oil Company affiliates ("Shell"). The acquired interests
include a 100% working interest in two State of Alaska leases, two offshore
production platforms and a 50% interest in certain operated production
pipelines and onshore processing facilities. The acquisition had an effective
date of July 1, 1998, and is subject to customary post-closing adjustments. The
Company acquired the properties in exchange for 1,921,850 shares of the
Company's common stock that are subject to a contractual $20 price guarantee.
The Company also executed a non-interest bearing promissory note to Shell for
$6 million. The total estimated purchase price of the Cook Inlet Acquisition of
$44.4 million is subject to post-closing adjustments.
On November 20, 1998, the Company acquired primarily gas-producing
properties in northwest Oklahoma and the San Juan Basin of New Mexico for $33.4
million from Seagull Energy Corp. After purchase price adjustments primarily
resulting from net revenues from the October 1, 1998 effective date through
November 20, 1998, the properties were purchased for an estimated price of
$29.2 million. Additional purchase price revisions may result from post-closing
adjustments. The Company funded the acquisition with bank debt.
3. Hugoton Royalty Trust Offering
In December 1998, the Company formed the Hugoton Royalty Trust by conveying
an 80% net profits interest in properties principally located in the Hugoton
area of Kansas and Oklahoma, the
CTF-39
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The Company
plans to sell 15,000,000, or 37.5%, of the Hugoton Royalty Trust units to the
public in March or April 1999. An additional 15%, or 2,250,000 units, may be
sold pursuant to exercise of the underwriters' overallotment option. The
Company expects that the offering price to the public will be between $9.00 and
$10.00 per Trust unit.
4. Pro Forma Adjustments
Pro forma adjustments necessary to adjust the Consolidated Balance Sheet and
Statement of Operations are as follows:
(a) To record net proceeds of $131,875,000 received by the Company upon
consummation of the Trust Offering, reflecting the sale of 15,000,000
Hugoton Royalty Trust Units by the Company to the public at an assumed
price of $9.50 per unit, less underwriters' discount and estimated
expenses, resulting in an estimated $39,225,000 gain on sale and
increase in retained earnings.
(b) To record revenue and direct operating expenses of the EEX Acquisition
for the period from January 1, 1998 through the date of acquisition.
Revenue and direct operating expenses subsequent to the date of
acquisition are included in the historical results of operations.
(c) To record revenue and direct operating expenses of the Other 1998
Acquisitions for the period from January 1, 1998 through the date of
acquisition. Revenue and direct operating expenses subsequent to the
date of acquisition are included in the historical results of
operations.
(d) To record reduction of revenue and expenses related to the sale of
37.5% of Hugoton Royalty Trust units, assuming the underwriters'
overallotment option is not exercised (Note 3), reduction in interest
expense attributable to decreased long-term debt upon application of
net proceeds of $131,875,000 from the Trust Offering (Note 4(a)) and
related increase in federal income tax at a corporate rate of 34%.
Interest expense was determined using the weighted average interest
rate incurred by the Company under its revolving credit facilities.
(e) To record the estimated increase in general and administrative expense
($690,000), an allocation from general and administrative expense to
production expense ($2,020,000, less billing to joint owners of
$89,000) attributable to the EEX Acquisition and the Other 1998
Acquisitions for the period from January 1, 1998 through the date of
acquisition.
(f) To record estimated depreciation and depletion expense attributable to
the EEX Acquisition and the Other 1998 Acquisitions using the unit-of-
production method applied to the cost of the properties acquired for
the period from January 1, 1998 through the date of acquisition.
(g) To record the increase in interest expense attributable to increased
long-term debt to finance the purchase of the EEX Acquisition and the
Other 1998 Acquisitions, to the extent financed by long-term debt, for
the period from January 1, 1998 through the date of acquisition.
Interest expense was determined using the weighted average interest
rate incurred by the Company under its revolving credit facilities.
(h) To record federal income tax at a corporate rate of 34% related to net
pro forma adjustments.
(i) To record increase in weighted average common shares outstanding for
the period from January 1, 1998 through the date of acquisition
resulting from the sale of 7,203,450 common shares in April 1998, the
proceeds from which partially funded the EEX Acquisition, and from the
issuance of 1,921,850 common shares to Shell to fund the Cook Inlet
Acquisition.
CTF-40
<PAGE>
CROSS TIMBERS OIL COMPANY
NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
5. Pro Forma Supplemental Oil and Gas Reserve Information
Estimated Quantities of Pro Forma Proved Oil and Gas Reserves
Pro forma reserve estimates at December 31, 1998 are based on reports
prepared by independent petroleum engineers for proved reserves of the Company,
using December 31, 1998 prices and costs.
Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which, based on geologic and engineering data, are
estimated to be reasonably recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed reserves are
those which are expected to be recovered through existing wells with existing
equipment and operating methods. Because of inherent uncertainties and the
limited nature of reservoir data, such estimates are subject to change as
additional information becomes available.
Pro Forma Proved Oil and Gas Reserves at December 31, 1998
<TABLE>
<CAPTION>
Natural Gas
Oil (Bbls) Gas (Mcf) Liquids (Bbls)
---------- --------- --------------
(in thousands)
<S> <C> <C> <C>
Proved reserves.......................... 53,301 1,054,702 17,174
====== ========= ======
Proved developed reserves................ 41,865 837,896 14,000
====== ========= ======
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating to Pro Forma
Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows ("Standardized
Measure") is prepared using assumptions required by the Financial Accounting
Standards Board. Such assumptions include the use of year-end prices for oil
and gas and year-end costs for estimated future development and production
expenditures to produce year-end estimated proved reserves. Discounted future
net cash flows are calculated using a 10% rate.
The Standardized Measure does not represent the Company's estimate of future
net cash flows or the value of proved oil and gas reserves. Probable and
possible reserves, which may become proved in the future, are excluded from the
calculations. Furthermore, year-end prices, used to determine the standardized
measure of discounted cash flows, are influenced by seasonal demand and other
factors and may not be the most representative in estimating future revenues or
reserve data.
Pro Forma Standardized Measure of Discounted Future Net Cash Flows at December
31, 1998
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
Future cash inflows.......................................... $ 2,715,478
Future costs:
Production................................................. (1,026,311)
Development................................................ (214,097)
-----------
Future net cash inflows before income tax.................... 1,475,070
Future income tax............................................ (210,898)
-----------
Future net cash flows........................................ 1,264,172
10% annual discount.......................................... (559,130)
-----------
Standardized measure of discounted future net cash flows..... $ 705,042
===========
</TABLE>
CTF-41
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
Cross Timbers Oil Company:
We have audited the accompanying statements of revenues and direct operating
expenses of the EEX Acquisition (see Note 1) for the years ended December 31,
1997, 1996 and 1995. These financial statements are the responsibility of the
management of Cross Timbers Oil Company. 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 statements. An audit also
includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, such statements present fairly, in all material respects, the
revenues and direct operating expenses of the EEX Acquisition described in Note
1 for the years ended December 31, 1997, 1996 and 1995 in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
February 15, 1999
CTF-42
<PAGE>
EEX ACQUISITION
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
For the Years Ended December 31, 1995, 1996 and 1997 and
the Period January 1 through April 24, 1998
(in thousands)
<TABLE>
<CAPTION>
January 1
Year Ended December 31, through
----------------------- April 24,
1995 1996 1997 1998
------- ------- ------- -----------
(Unaudited) ---
<S> <C> <C> <C> <C> <C>
REVENUES
Oil................................... $ 4,811 $ 5,734 $ 5,298 $ 1,224
Gas................................... 77,399 92,532 88,747 21,985
------- ------- ------- -------
Total............................... 82,210 98,266 94,045 23,209
------- ------- ------- -------
DIRECT OPERATING EXPENSES
Production............................ 8,346 8,055 6,933 2,512
Taxes on production and property...... 9,054 10,155 10,109 2,362
------- ------- ------- -------
Total............................... 17,400 18,210 17,042 4,874
------- ------- ------- -------
EXCESS OF REVENUES OVER DIRECT
OPERATING EXPENSES..................... $64,810 $80,056 $77,003 $18,335
======= ======= ======= =======
</TABLE>
See Accompanying Notes to Statements of Revenues and Direct Operating Expenses.
CTF-43
<PAGE>
EEX ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
1. Basis of Presentation
On April 24, 1998, Cross Timbers Oil Company ("the Company") acquired
producing properties in the East Texas Basin from EEX Corporation ("EEX
Acquisition") for $265 million. After purchase price adjustments primarily
resulting from net revenues from the January 1, 1998 effective date through
April 24, 1998, the properties were purchased for an estimated price of $245
million. In connection with the acquisition, the Company sold a production
payment to EEX Corporation for $30 million. The production payment is payable
from production from certain properties acquired in the EEX Acquisition during
the 10-year period beginning January 1, 2002. EEX Corporation effectively pays
all taxes, royalties and production expenses related to such production. The
Company has the option to repurchase a portion of this production payment each
December, beginning in 1998; this option was not exercised in December 1998.
The cost of the EEX Acquisition (net of the production payment sold) of $215
million was funded by bank debt which was partially repaid by net proceeds of
$133.3 million from the sale of 7,203,450 shares of the Company's common stock
in a public offering on April 27, 1998. Purchase price revisions may result
from post-closing adjustments.
The accompanying statements of revenues and direct operating expenses do not
include general and administrative expense, interest income or expense, a
provision for depreciation, depletion and amortization or any provision for
income taxes because the property interests acquired represent only a portion
of a business and the costs incurred by EEX Corporation are not necessarily
indicative of the costs to be incurred by the Company.
Historical financial information reflecting financial position, results of
operations and cash flows of the EEX Acquisition is not presented because the
entire acquisition cost was assigned to the oil and gas property interests.
Accordingly, the historical statements of revenues and direct operating
expenses have been presented in lieu of the financial statements required under
Rule 3-05 of Securities and Exchange Commission Regulation S-X.
2. Supplemental Oil and Gas Reserve Information (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves
The proved reserve information presented below has been estimated by the
Company's internal engineers, and reviewed by independent petroleum engineers,
using December 31, 1997 prices and costs. Proved reserves are estimated
quantities of crude oil and natural gas which, based on geologic and
engineering data, are estimated to be reasonably recoverable in future years
from known reservoirs under existing economic and operating conditions. Proved
developed reserves are those which are expected to be recovered through
existing wells with existing equipment and operating methods. Because of
inherent uncertainties and the limited nature of reservoir data, such estimates
are subject to change as additional information becomes available.
Proved Oil and Gas Reserves at December 31, 1997
<TABLE>
<CAPTION>
Oil Gas
(Bbls) (Mcf)
------ -------
(in thousands)
<S> <C> <C>
Proved reserves............................................... 1,599 232,229
===== =======
Proved developed reserves..................................... 1,365 191,293
===== =======
</TABLE>
CTF-44
<PAGE>
EEX ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES--(Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
The standardized measure of discounted future net cash flows ("Standardized
Measure") is prepared using assumptions required by the Financial Accounting
Standards Board. Such assumptions include the use of year-end prices for oil
and gas and year-end costs for estimated future development and production
expenditures to produce year-end estimated proved reserves. Discounted future
net cash flows are calculated using a 10% rate.
The Standardized Measure does not represent the Company's estimate of future
net cash flows or the value of proved oil and gas reserves. Probable and
possible reserves, which may become proved in the future, are excluded from the
calculations. Furthermore, year-end prices, used to determine the standardized
measure of discounted cash flows, are influenced by seasonal demand and other
factors and may not be the most representative in estimating future revenues or
reserve data.
Standardized Measure of Discounted Future Net Cash Flows at December 31, 1997
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
Future cash inflows......................................... $ 590,952
Future costs:
Production................................................ (187,402)
Development............................................... (36,754)
---------
Future net cash inflows..................................... 366,796
10% annual discount......................................... (142,534)
---------
Standardized measure of discounted future net cash flows
before income taxes........................................ $ 224,262
=========
</TABLE>
CTF-45
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
Cross Timbers Oil Company:
We have audited the accompanying statement of revenues and direct operating
expenses of the Amoco Acquisition (see Note 1) for the year ended December 31,
1996. 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 statements. 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, such statement presents fairly, in all material respects, the
revenues and direct operating expenses of the Amoco Acquisition described in
Note 1 for the year ended December 31, 1996 in conformity with generally
accepted accounting principles.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
February 11, 1998
CTF-46
<PAGE>
AMOCO ACQUISITION
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
For the Year Ended December 31, 1996 and
the Period January 1 through December 1, 1997
(in thousands)
<TABLE>
<CAPTION>
January 1
Year Ended through
December 31, December 1,
1996 1997
------------ -----------
(Unaudited)
<S> <C> <C>
REVENUES
Oil................................................. $ 2,039 $ 1,478
Gas................................................. 35,186 33,428
------- -------
Total............................................. 37,225 34,906
------- -------
DIRECT OPERATING EXPENSES
Production.......................................... 6,656 4,981
Taxes on production and property.................... 3,561 3,436
------- -------
Total............................................. 10,217 8,417
------- -------
EXCESS OF REVENUES OVER DIRECT OPERATING EXPENSES..... $27,008 $26,489
======= =======
</TABLE>
See Accompanying Notes to Statements of Revenues and Direct Operating Expenses.
CTF-47
<PAGE>
AMOCO ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
1. Basis of Presentation
On December 1, 1997, Cross Timbers Oil Company ("the Company") acquired
interests in certain producing oil and gas properties in the San Juan Basin of
New Mexico from a subsidiary of Amoco Corporation ("Amoco Acquisition"). The
purchase was made pursuant to a Purchase and Sale Agreement dated September 29,
1997, with a stated purchase price of $252 million and warrants to purchase
937,500 shares of the Company's common stock at a price of $15.31 per share for
a period of five years. After adjustments for other acquisition costs,
estimated cash flows through date of closing and preferential purchase rights
exercised by third parties, the properties were purchased for approximately
$195 million, including approximately $5.7 million value for the warrants.
Amoco elected to accept certain producing properties owned by the Company
valued at $15.7 million in lieu of cash, reducing cash consideration to $173.6
million, which was funded by bank debt. Additional purchase price revisions may
result from post-closing adjustments.
The accompanying statements of revenues and direct operating expenses do not
include general and administrative expense, interest income or expense, a
provision for depreciation, depletion and amortization or any provision for
income taxes because the property interests acquired represent only a portion
of a business and the costs incurred by Amoco Corporation are not necessarily
indicative of the costs to be incurred by the Company.
Historical financial information reflecting financial position, results of
operations and cash flows of the Amoco Acquisition is not presented because the
entire acquisition cost was assigned to the oil and gas property interests.
Accordingly, the historical statements of revenues and direct operating
expenses have been presented in lieu of the financial statements required under
Rule 3-05 of Securities and Exchange Commission Regulation S-X.
2. Supplemental Oil and Gas Reserve Information (Unaudited)
Estimated Quantities of Proved Oil and Gas Reserves
Reserve information presented below has been estimated by the Company's
internal engineers using December 31, 1996 prices and costs. Proved reserves
are estimated quantities of crude oil and natural gas which, based on geologic
and engineering data, are estimated to be reasonably recoverable in future
years from known reservoirs under existing economic and operating conditions.
Proved developed reserves are those which are expected to be recovered through
existing wells with existing equipment and operating methods. Because of
inherent uncertainties and the limited nature of reservoir data, such estimates
are subject to change as additional information becomes available.
Proved Oil and Gas Reserves at December 31, 1996
<TABLE>
<CAPTION>
Natural Gas
Liquid
Oil (Bbls) Gas (Mcf) (Bbls)
---------- -------- -----------
(in thousands)
<S> <C> <C> <C>
Proved reserves............................. 1,356 226,946 14,423
===== ======= ======
Proved developed reserves................... 1,147 195,243 12,409
===== ======= ======
</TABLE>
CTF-48
<PAGE>
AMOCO ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES--(Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
The standardized measure of discounted future net cash flows ("Standardized
Measure") is prepared using assumptions required by the Financial Accounting
Standards Board. Such assumptions include the use of year-end prices for oil
and gas and year-end costs for estimated future development and production
expenditures to produce year-end estimated proved reserves. Discounted future
net cash flows are calculated using a 10% rate.
The Standardized Measure does not represent the Company's estimate of future
net cash flows or the value of proved oil and gas reserves. Probable and
possible reserves, which may become proved in the future, are excluded from the
calculations. Furthermore, year-end prices, used to determine the standardized
measure of discounted cash flows, are influenced by seasonal demand and other
factors and may not be the most representative in estimating future revenues or
reserve data.
Standardized Measure of Discounted Future Net Cash Flows at December 31, 1996
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
Future cash inflows......................................... $ 901,823
Future costs:
Production................................................ (310,767)
Development............................................... (13,111)
---------
Future net cash inflows..................................... 577,945
10% annual discount......................................... (296,502)
---------
Standardized measure of discounted future net cash flows
before income taxes........................................ $ 281,443
=========
</TABLE>
CTF-49
<PAGE>
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
1,405 active wells and are located primarily in Kansas, Oklahoma, and Wyoming.
The aggregate results of our evaluations are as follows:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
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$
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
- -----------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
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,
<PAGE>
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
<PAGE>
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.
<PAGE>
Attachment 2
PROVED RESERVES DEFINITIONS
IN ACCORDANCE WITH
SECURITIES AND EXCHANGE COMMISSION REGULATION S-X
PROVED OIL AND GAS RESERVES
- ---------------------------
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements but not on
escalations based upon future conditions.
1. Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any, and (b)
the immediately adjoining portions not yet drilled but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
2. Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the proved
classification when successful testing by a pilot project or the operation
of an installed program in the reservoirs provides support for the
engineering analysis on which the project or program was based.
3. Estimates of proved reserves do not include the following:
a. Oil that may become available from known reservoirs but is classified
separately as indicated additional reserves.
b. Crude oil, natural gas, and natural gas liquids, the recovery of which
is subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors.
c. Crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects.
d. Crude oil, natural gas, and natural gas liquids, that may be recovered
from oil shales, coal, gilsonite, and other such sources.
Depending upon their status of development, proved reserves are subdivided
into proved developed reserves and proved undeveloped reserves.
PROVED DEVELOPED OIL AND GAS RESERVES
- -------------------------------------
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as proved developed
reserves only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
PROVED UNDEVELOPED OIL AND GAS RESERVES
- ---------------------------------------
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
<PAGE>
EXHIBIT B
[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 1,405 active wells located
primarily in Kansas, Oklahoma, and Wyoming. The aggregate results of our
evaluations are as follows:
<TABLE>
<CAPTION>
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$
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
Attachment 2
PROVED RESERVES DEFINITIONS
IN ACCORDANCE WITH
SECURITIES AND EXCHANGE COMMISSION REGULATION S-X
PROVED OIL AND GAS RESERVES
- ---------------------------
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements but not on
escalations based upon future conditions.
1. Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any, and (b)
the immediately adjoining portions not yet drilled but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
2. Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the proved
classification when successful testing by a pilot project or the operation
of an installed program in the reservoirs provides support for the
engineering analysis on which the project or program was based.
3. Estimates of proved reserves do not include the following:
a. Oil that may become available from known reservoirs but is classified
separately as indicated additional reserves.
b. Crude oil, natural gas, and natural gas liquids, the recovery of which
is subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors.
c. Crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects.
d. Crude oil, natural gas, and natural gas liquids, that may be recovered
from oil shales, coal, gilsonite, and other such sources.
Depending upon their status of development, proved reserves are subdivided
into proved developed reserves and proved undeveloped reserves.
PROVED DEVELOPED OIL AND GAS RESERVES
- -------------------------------------
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as proved developed
reserves only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
PROVED UNDEVELOPED OIL AND GAS RESERVES
- ---------------------------------------
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
No dealer, salesperson or other person is authorized to give any information or
to represent anything not contained in this prospectus. You must not rely on
any unauthorized information or representations. This prospectus is an offer to
sell the Trust Units offered hereby, but only under circumstances and in
jurisdictions where it is lawful to do so. The information contained in this
prospectus is current only as of its date.
---------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
-----
<S> <C>
Prospectus Summary....................................................... 3
Risk Factors............................................................. 12
Forward Looking Statements............................................... 17
Use of Proceeds.......................................................... 17
Cross Timbers............................................................ 17
The Trust................................................................ 18
Projected Cash Distributions............................................. 18
The Underlying Properties................................................ 23
Computation of Net Proceeds.............................................. 35
Federal Income Tax Consequences.......................................... 38
State Tax Considerations................................................. 43
ERISA Considerations..................................................... 44
Description of the Trust Indenture....................................... 45
Description of the Trust Units........................................... 48
Selling Trust Unitholder................................................. 50
Legal Matters............................................................ 51
Experts.................................................................. 51
Available Information.................................................... 51
Glossary of Certain Oil and Natural Gas Terms............................ 53
Index to Financial Statements............................................ F-1
Underwriting............................................................. U-1
Information about Cross Timbers Oil Company.............................. CT-1
Index to Cross Timbers Financial Statements.............................. CTF-1
Summary Reserve Reports........................................Exhibits A and B
</TABLE>
---------------
Through and including , 1999 (the 25th day after the date of this
prospectus), all dealers effecting transactions in these securities, whether or
not participating in this offering, may be required to deliver a prospectus.
This is in addition to a dealer's obligation to deliver a prospectus when
acting as an underwriter and with respect to an unsold allotment or
subscription.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
All capitalized terms used and not defined in Part II of this Registration
Statement shall have the meanings assigned to them in the Prospectus forming a
part of this Registration Statement.
Item 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:
<TABLE>
<S> <C>
Registration Fee................................................. $ 47,955
NASD Filing Fee.................................................. 19,820
Printing and Engraving Expenses.................................. 325,000
Legal Fees and Expenses.......................................... 385,000
Accountants' Fees and Expenses................................... 155,000
Miscellaneous Fees and Expenses.................................. 117,225
----------
Total............................................................ $1,050,000
==========
</TABLE>
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
<PAGE>
The above discussion of the Company's Certificate of Incorporation and of
Sections 102(b)(7) and 145 of the DGCL is not intended to be exhaustive and is
qualified in its entirety by such Certificate of Incorporation and statutes.
Additionally, the Company has acquired directors' and officers' insurance in
the amount of $10 million.
Item 16. Exhibits.
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
1.1* --Form of Underwriting Agreement.
3.1* --Certificate of Incorporation of Cross Timbers Oil Company, as
amended through and restated on April 21, 1998.
3.2 --Bylaws of Cross Timbers Oil Company (incorporated by reference to
Exhibit 3.4 to Registration Statement on Form S-1, File No. 33-
59820).
4.1.1 --Hugoton Royalty Trust Indenture, as amended and restated as of March
24, 1999.
4.2 --Form of Certificate of Designations of Series A Convertible
Preferred Stock, par value $.01 per share (incorporated by reference
to Exhibit 4 to Form 8-A/A, Amendment No. 1, dated September 3,
1996).
4.3 --Indenture dated as of April 1, 1997, between Cross Timbers Oil
Company and The Bank of New York, as Trustee for the 9 1/4% Senior
Subordinated Notes due 2007 (incorporated by reference to Exhibit 4.1
to Registration Statement of Form S-4, File No. 333-26603).
4.4 --Indenture dated as of October 28, 1997, between Cross Timbers Oil
Company and the Bank of New York, as Trustee for the 8 3/4% Senior
Subordinated Notes due 2009 (incorporated by reference to Exhibit 4.1
to Registration Statement on Form S-4, File No. 333-39097).
4.5 --Preferred Stock Purchase Rights Agreement between Cross Timbers Oil
Company and ChaseMellon Shareholder Services, LLC (incorporated by
reference to Exhibit 4.1 to Form 8-A dated September 8, 1998).
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.
10.1.1* --Form of 80% Net Overriding Royalty Conveyance--Kansas as amended and
restated.
10.2.1* --Form of 80% Net Overriding Royalty Conveyance--Oklahoma as amended
and restated.
10.3.1* --Form of 80% Net Overriding Royalty Conveyance--Wyoming as amended
and restated.
10.4* --Revolving Credit Agreement dated November 16, 1998, between Cross
Timbers Oil Company and certain commercial banks named therein.
10.5 --Employment Agreement between Cross Timbers Oil Company and Bob R.
Simpson, dated February 21, 1995 (incorporated by reference to
Exhibit 10.6 to Form 10-K for the year ended December 31, 1994).
10.6 --Employment Agreement between Cross Timbers Oil Company and Steffen
E. Palko, dated February 21, 1995 (incorporated by reference to
Exhibit 10.7 to Form 10-K for the year ended December 31, 1994).
10.7 --Cross Timbers Oil Company 1991 Stock Incentive Plan (incorporated by
reference to Exhibit 10.7 to Registration Statement on Form S-1, File
No. 33-59820).
10.8 --Form of grant under Cross Timbers Oil Company 1991 Stock Incentive
Plan (incorporated by reference to Exhibit 10.8 to Registration
Statement on Form S-1, File No. 33-59820).
10.9 --Cross Timbers Oil Company 1994 Stock Incentive Plan (incorporated by
reference to Exhibit 4.4 to Registration Statement on Form S-8, File
No. 33-81766).
10.10 --Form of grant under Cross Timbers Oil Company 1994 Stock Incentive
Plan (incorporated by reference to Exhibit 4.5 to Registration
Statement on Form S-8, File No. 33-81766).
</TABLE>
II-2
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.11 --Cross Timbers Oil Company 1997 Stock Incentive Plan, as amended
February 25, 1998 (incorporated by reference to Exhibit 10.8 to Form
10-K for the year ended December 31, 1997).
10.12 --Form of grant under Cross Timbers Oil Company 1997 Stock Incentive
Plan, as amended February 25, 1998 (incorporated by reference to
Exhibit 10.9 to Form 10-K for the year ended December 31, 1997).
10.13 --Cross Timbers Oil Company 1998 Stock Incentive Plan (incorporated by
reference to Exhibit 4.4 to Registration Statement on Form S-8, File
No. 333-69977).
10.14 --Form of grant under Cross Timbers Oil Company 1998 Stock Incentive
Plan (incorporated by reference to Exhibit 4.5 to Registration
Statement on Form S-8, File No. 333-69977).
10.15 --Cross Timbers Oil Company 1998 Royalty Trust Option Plan
(incorporated by reference to Exhibit B to the 1998 Proxy Statement
filed on April 24, 1998.
10.16 --Registration Rights Agreement among Cross Timbers Oil Company and
partners of Cross Timbers Oil Company, L.P. (incorporated by
reference to Exhibit 10.9 to Registration Statement on Form S-1, File
No. 33-59820).
10.17 --Warrant Agreement dated December 1, 1997 by and between Cross
Timbers Oil Company and Amoco Corporation (incorporated by reference
to Exhibit 10.11 to Form 10-K for the year ended December 31, 1997).
10.18 --Cross Timbers Oil Company Management Group Employee Severance
Protection Plan (incorporated by reference to Exhibit 10.13 to Form
10-K for the year ended December 31, 1998).
12.1* --Computation of Ratio of Earnings to Fixed Charges of Cross Timbers
Oil Company.
21.1* --Subsidiaries of Cross Timbers Oil Company.
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 relating to Hugoton Royalty Trust.
27.2* --Financial Data Schedule relating to Cross Timbers Oil Company.
</TABLE>
- --------
* 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.
II-3
<PAGE>
(c) for purposes of determining any liability under the Securities Act of
1933, the information omitted from the form of prospectus filed as part of this
registration statement in reliance upon Rule 430A and contained in a form of
prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h)
under the Securities Act shall be deemed a part of this registration statement
as of the time it was declared effective.
(d) for the purpose of determining any liability under the Securities Act of
1933, each post-effective amendment that contains a form of prospectus shall be
deemed to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed to be
the initial bona fide offering thereof.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
Registrant pursuant to the foregoing provisions, or otherwise, the 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-4
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the Company 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 April 8, 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.
<TABLE>
<S> <C> <C>
/s/ Bob R. Simpson* Director, Chairman of the April 8, 1999
______________________________________ Board and Chief Executive
Bob R. Simpson Officer (Principal
Executive Officer)
/s/ Steffen E. Palko* Director, Vice Chairman of April 8, 1999
______________________________________ the Board and President
Steffen E. Palko
/s/ J. Richard Seeds Director, Executive Vice April 8, 1999
______________________________________ President
J. Richard Seeds
/s/ J. Luther King, Jr.* Director April 8, 1999
______________________________________
J. Luther King, Jr.
/s/ Jack P. Randall* Director April 8, 1999
______________________________________
Jack P. Randall
/s/ Scott G. Sherman* Director April 8, 1999
______________________________________
Scott G. Sherman
/s/ Louis G. Baldwin Senior Vice President and April 8, 1999
______________________________________ Chief Financial Officer
Louis G. Baldwin (Principal Financial
Officer)
/s/ Bennie G. Kniffen Senior Vice President and April 8, 1999
______________________________________ Controller (Principal
Bennie G. Kniffen Accounting Officer)
</TABLE>
*By: /s/ J. Richard Seeds
------------------------------
J. Richard Seeds
Attorney-in-Fact
II-5
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
4.1.1 --Hugoton Royalty Trust Indenture, as Amended and Restated as of March
24, 1999.
23.1 --Consent of Arthur Andersen LLP.
</TABLE>
<PAGE>
EXHIBIT 4.1.1
================================================================================
HUGOTON ROYALTY TRUST
ROYALTY TRUST INDENTURE
(Amended and Restated as of March 24, 1999)
December 1, 1998
================================================================================
<PAGE>
TABLE OF CONTENTS
<TABLE>
<S> <C>
ARTICLE I. DEFINITION..................................................... 1
Section 1.01. Defined Terms......................................... 1
ARTICLE II. NAME AND PURPOSE OF THE TRUST................................ 4
Section 2.01. Name.................................................. 4
Section 2.02. Purposes.............................................. 4
Section 2.03. Nature of the Trust................................... 5
Section 2.04. Transfer of Trust Property to the Trust;
Closing Matters...................................... 5
ARTICLE III. ADMINISTRATION OF THE TRUST................................. 6
Section 3.01. General................................................ 6
Section 3.02. Limited Power to Dispose of Royalties.................. 6
Section 3.03. No Power to Engage in Business or Make Investments..... 7
Section 3.04. Interest on Cash on Hand............................... 7
Section 3.05. Power to Settle Claims................................. 7
Section 3.06. Power to Contract for Services......................... 7
Section 3.07. Payment of Liabilities of Trust........................ 8
Section 3.08. Establishment of Reserves.............................. 8
Section 3.09. Limited Power to Borrow................................ 8
Section 3.10. Income and Principal................................... 8
Section 3.11. Term of Contracts...................................... 8
Section 3.12. Transactions between Related Parties................... 9
Section 3.13. No Bond Required....................................... 9
Section 3.14. Timing of Trust Income and Expenses.................... 9
Section 3.15. Divestiture of Units................................... 9
Section 3.16. Filing of Registration Statements, Listing of Units... 10
Section 3.17. Reserve Reports....................................... 12
Section 3.18. Miscellaneous.......................................... 13
ARTICLE IV. BENEFICIAL SHARES AND CERTIFICATES............................ 13
Section 4.01. Creation and Distribution.............................. 13
Section 4.02. Beneficial Interest of Unitholders..................... 13
Section 4.03. Execution of Certificates.............................. 14
Section 4.04. Registration and Transfer of Unit...................... 14
Section 4.05. Mutilated, Lost, Stolen and Destroyed Certificates..... 15
Section 4.06. Protection of Trustee.................................. 15
Section 4.07. Determination of Ownership of Certificates............. 15
ARTICLE V. ACCOUNTING AND DISTRIBUTION; REPORTS.......................... 16
Section 5.01. Fiscal Year and Accounting Method...................... 16
Section 5.02. Distributions.......................................... 16
Section 5.03. Income Tax Reporting................................... 16
Section 5.04 Reports to Unitholders................................. 16
Section 5.05. Filings................................................ 17
Section 5.06. Information to be Supplied by Grantor and Trustee..... 17
Section 5.07. Reliance on Information............................... 17
</TABLE>
<PAGE>
<TABLE>
<S> <C>
ARTICLE VI. LIABILITY OF TRUSTEE, INDEMNIFICATION
AND METHOD OF SUCCESSION.................................................. 18
Section 6.01. Liability of Trustee................................... 18
Section 6.02. Indemnification of Trustee............................. 18
Section 6.03. Guaranty.............................................. 19
Section 6.04. Contribution.......................................... 19
Section 6.05. Indemnification Procedures............................ 19
Section 6.06. Resignation of Trustee................................. 20
Section 6.07. Removal of Trustee..................................... 20
Section 6.08. Appointment of Successor Trustee....................... 20
Section 6.09. Laws of Other Jurisdictions............................ 21
Section 6.10. Force Majeure......................................... 21
ARTICLE VII. COMPENSATION OF THE TRUSTEE................................. 22
Section 7.01. Compensation of Trustee................................ 22
Section 7.02. Expenses............................................... 22
Section 7.03. Other Services......................................... 22
Section 7.04. Source of Funds........................................ 22
ARTICLE VIII. MEETINGS OF UNITHOLDERS.................................... 22
Section 8.01. Purpose of Meetings.................................... 22
Section 8.02. Call and Notice of Meetings............................ 22
Section 8.03. Voting................................................. 23
Section 8.04. Conduct of Meetings.................................... 23
Section 8.05. Unitholder Proposals.................................. 23
ARTICLE IX. DURATION, REVOCATION AND TERMINATION OF TRUST................ 24
Section 9.01. Revocation............................................. 24
Section 9.02. Termination............................................ 24
Section 9.03. Disposition and Distribution of Properties............. 24
ARTICLE X. AMENDMENTS.................................................... 25
Section 10.01. Prohibited............................................ 25
Section 10.02. Permitted............................................. 25
ARTICLE XI. ARBITRATION.................................................. 25
ARTICLE XII. MISCELLANEOUS............................................... 28
Section 12.01. Inspection of Trustee's Books......................... 28
Section 12.02. Trustee's Employment of Experts....................... 28
Section 12.03. Merger or Consolidation of Trustee.................... 28
Section 12.04. Filing of this Indenture.............................. 29
Section 12.05. Severability.......................................... 29
Section 12.06. Notices............................................... 29
Section 12.07. Counterparts.......................................... 30
Section 12.08. Successors............................................ 30
</TABLE>
<PAGE>
HUGOTON ROYALTY TRUST INDENTURE
This Royalty Trust Indenture ("Indenture") of Hugoton Royalty Trust (the
"Trust") is entered into as of December 1, 1998, between Cross Timbers Oil
Company, a Delaware corporation ("Grantor"), as Grantor, and NationsBank, N.A.,
a banking association organized under the laws of the United States (the
"Bank"), as trustee.
WHEREAS, Grantor is engaged in the business of developing and producing oil
and gas and owns various mineral interests in properties that contain proved
reserves of oil and gas and are currently producing oil and gas; and
WHEREAS, Grantor has determined to convey to the Trust the Royalties
(hereinafter defined) pursuant to the Conveyances (hereinafter defined) in
consideration for the issuance by the Trust to Grantor of 40,000,000 Units
(hereinafter defined) representing the ownership of undivided Beneficial
Interest (hereinafter defined) in the assets of the Trust;
NOW, THEREFORE, in furtherance of forming the Trust, Grantor has delivered
to the Bank, on behalf of the Trust, One Thousand Dollars ($1,000.00) upon
execution of this Indenture, which Bank accepts and agrees to hold in trust,
together with the Royalties to be received hereunder, for the purposes, and in
accordance with the duties, terms and conditions hereof.
ARTICLE I. DEFINITIONS
Section 1.01. Defined Terms. As used herein, the following terms are used
with the meanings indicated:
"Affiliate" of a Person means another Person controlled by,
controlling or under common control with such Person. As used herein,
"control" (including the terms "controlling", "controlled by" and "under
common control with") means the possession, directly or indirectly, of the
power to direct or cause the direction of the management and policies of a
Person, whether through the ownership of voting securities, by contract or
otherwise.
"Beneficial Interest" means the aggregate equitable interest of the
Unitholders in the Trust Estate as expressly set out in this Trust
Indenture and all other rights of beneficiaries of express trusts created
under the Texas Trust Code, subject to the limitations set forth in this
Trust Indenture.
"Business Day" means any day that is not a Saturday, Sunday or other
day on which national banking institutions in the City of Fort Worth,
Texas, are closed as authorized or required by law or a holiday determined
by the New York Stock Exchange as "affecting 'ex' dates."
1
<PAGE>
"Certificate" means a certificate issued by the Trustee pursuant to
Article IV evidencing the ownership of one or more Units.
"Code" means the Internal Revenue Code of 1986, as amended.
"Closing" means the closing of the initial public offering of Units
contemplated by the Securities Act Registration Statement.
"Conveyances" means the Net Overriding Royalty Conveyances effective
as of December 1, 1998 between Grantor and the Trust pursuant to which the
Royalties are to be conveyed to the Trust.
"Distribution Date" means the date of a distribution, which shall be
on or before ten Business Days after the Monthly Record Date.
"Effective Time" means 12:01 A.M. on December 1, 1998.
"Environmental Laws" means all applicable federal, state and local
laws, regulations, ordinances, rules, orders, permits and governmental
restrictions relating to the environment, the effect of the environment on
human health or safety, pollutants, contaminants, hazardous substances, or
hazardous waste, in effect on the date of this Indenture, and all binding
judicial and administrative interpretations thereof.
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
"Exchange Act Registration Statement" means the registration statement
by which the Units may be registered under Section 12 of the Exchange Act.
"Indenture" means this instrument, as originally executed, or, if
amended or supplemented, as so amended or supplemented.
"Monthly Distribution Amount" means for each Monthly Period an amount
determined by the Trustee (pursuant to Section 5.02 hereof) to be equal to
the excess, if any, of (a) the cash received by the Trustee during the
Monthly Period attributable to the Royalties, plus any cash available for
distribution as a result of the reduction or elimination during the Monthly
Period of any existing cash reserve created pursuant to Section 3.08 hereof
to provide for the payment of liabilities of the Trust, plus any other cash
receipts of the Trust during the Monthly Period including any cash received
from interest earned pursuant to Section 3.04, over (b) the liabilities of
the Trust paid during the Monthly Period, plus the amount of any cash used
pursuant to Section 3.08 hereof in the Monthly Period to establish or
increase a cash reserve for the payment of any accrued, future or
contingent liabilities of the Trust. Without limiting the foregoing, the
liabilities of the Trust to be paid during the first Monthly Period shall
include liabilities incurred prior to the Effective Time that relate to the
formation of the Trust or for which the Trust or
2
<PAGE>
Trustee is otherwise responsible for payment. If the Monthly Distribution
Amount determined in accordance with the preceding sentence shall for any
Monthly Period be a negative amount, then the Monthly Distribution Amount
shall be zero, and such negative amount shall reduce the next Monthly
Distribution Amount. Notwithstanding the foregoing, the Monthly
Distribution Amount for any Monthly Period shall not include any amount
which would have been required to be reported to any securities exchange or
quotation system on which the Units are listed or admitted in connection
with the establishment of an 'ex' date in order to be distributed to
Unitholders who were such on the Monthly Record Date for such Monthly
Period but was not so reported unless the securities exchange or quotation
system agrees to such amount being a part of that Monthly Period's Monthly
Distribution Amount or the Trustee receives an opinion of counsel, in a
form reasonably satisfactory to the Trustee, stating that none of the
Trust, the Trustee or any owner of Units will be adversely affected by such
inclusion. An amount which pursuant to the preceding sentence is not
included in the Monthly Distribution Amount for that Monthly Period shall
be included in the Monthly Distribution Amount for the next Monthly Period
(unless it is reserved pursuant to Section 3.08 hereof).
"Monthly Period" means, for the initial period, the period which
commences on the Effective Time and continues through and includes the
Monthly Record Date occurring in March 1999, and for succeeding periods the
period which commences on the day following a Monthly Record Date and
continues through and includes the next succeeding Monthly Record Date.
"Monthly Record Date" for each month means the close of business on
the last Business Day of such month unless the Trustee determines that a
different date is required to comply with applicable law or the rules of
any exchange or quotation system on which the Units may be listed or
admitted for trading, in which event it means such different date.
"NASD" means the National Association of Securities Dealers, Inc.
"NASDAQ" means the National Association of Securities Dealers
Automated Quotation System.
"NYSE" means the New York Stock Exchange.
"Person" means an individual, a corporation, partnership, limited
liability company, trust, estate or other organization.
"Reserve Report" means a report of estimated proved reserves
attributable to the Royalties and the present value thereof prepared on the
basis required by the SEC for inclusion in financial statements filed with
the SEC.
"Royalties" means the net overriding royalty interests conveyed to the
Trustee pursuant to the Conveyances.
3
<PAGE>
"SEC" means the Securities and Exchange Commission and any agency
which may succeed to its responsibilities and functions after the date
hereof.
"Securities Act" means the Securities Act of 1933, as amended.
"Securities Act Registration Statement" means a registration statement
filed under and complying with the requirements of the Securities Act, and
the rules and regulations promulgated thereunder, in respect of the
offering and sale of all or a fraction of the Units to the public and the
transactions related thereto.
"Subject Interests" has the meaning set forth in the Conveyances.
"Transferee", as to any Unitholder or former Unitholder, means any
Person succeeding to the interest of such Unitholder or former Unitholder
in one or more Units of the Trust, whether as purchaser, donee, legatee or
otherwise.
"Trust" means the express trust created hereby which shall be held and
administered as provided herein and in accordance with the terms and
provisions (not inconsistent with any terms and provisions hereof) of the
Texas Trust Code.
"Trust Estate" means the assets held by the Trustee under this
Indenture, and shall include both income and principal if separate accounts
or records are kept therefor.
"Trustee" means the initial trustee under this instrument, or any
successor, during the period it is so serving in such capacity.
"Unit" means an undivided fractional interest in the Beneficial
Interest, determined as hereinafter provided.
"Unitholder" means the owner of one or more Units as reflected on the
books of the Trustee pursuant to Article IV.
ARTICLE II. NAME AND PURPOSE OF THE TRUST
Section 2.01. Name. The Trust shall be known as the Hugoton Royalty Trust,
and the Trustee may transact the affairs of the Trust in that name.
Section 2.02. Purposes. The purposes of the Trust are:
(a) to receive, hold, protect and conserve, for the benefit of the
Unitholders, the Trust Estate;
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(b) to convert the Royalties to cash either (1) by retaining them and
collecting the proceeds from production payable with respect thereto until
production has ceased or the Royalties have otherwise terminated or (2) by
selling or otherwise disposing of all or a part of the Royalties in
accordance with and subject to the terms of this Indenture;
(c) to pay, or provide for the payment of, any costs and liabilities
incurred in carrying out the purposes of the Trust, and thereafter to
distribute the remaining amounts of cash received by the Trust to the
Unitholders pro rata based on the number of Units owned; and
(d) subject to Section 3.03 of this Indenture, to engage in such other
activities as are necessary or convenient for the attainment of any of the
foregoing or are incident thereto and which may be engaged in or carried
out by a trust under the Texas Trust Code.
Section 2.03. Nature of the Trust. It is the intention and agreement of
Grantor and the Trustee to create an express trust within the meaning of Section
111.004(4) of the Texas Trust Code, for the benefit of the owners of Units, and
a grantor trust for federal income tax purposes of which the owners of Units are
the grantors. As set forth above and amplified herein, the Trust is intended to
be limited to the receipt of revenues attributable to the Royalties and the
distribution of such revenues, after payment of or provision for Trust expenses
and liabilities, to the Unitholders. It is neither the purpose nor the intention
of the parties hereto to create, and nothing in this Trust Indenture shall be
construed as creating, a partnership, joint venture, joint stock company or
business association between or among Unitholders, present or future, or among
or between Unitholders, or any of them, and the Trustee or Grantor.
Section 2.04. Transfer of Trust Property to the Trust; Closing Matters.
Upon the execution of this Indenture, Grantor has paid to the Trustee, in trust,
and the Trustee has accepted, for the uses and purposes provided herein, the sum
of One Thousand Dollars ($1,000.00) in consideration for 40,000,000 Units to be
issued by the Trust to Grantor, which Units shall collectively represent the
entire Beneficial Interest in accordance with Section 4.01 of this Indenture.
At or before the Closing, Grantor shall grant, bargain, sell, convey and assign
the Royalties to the Trust for the uses and purposes provided herein and for the
benefit of the Unitholders, pursuant to the Conveyances. The Units to be issued
by the Trust to Grantor in accordance with the first sentence of this Section
2.04 shall be evidenced by one or more Certificates (which may be temporary
Certificates) issued in such denominations and otherwise in accordance with
written instructions furnished to the Trustee. Upon receipt of written transfer
instructions from Grantor, the Trustee shall prepare Certificates (which may be
temporary Certificates) in proper form duly executed and countersigned in
accordance with Section 4.03 of this Indenture in such names and in such
denominations as Grantor may request in writing not less than two full Business
Days before the Closing. For the purpose of expediting the checking and
packaging of the Certificates so prepared by the Trustee pursuant to the
preceding sentence, the Trustee shall make such Certificates available for
inspection by the representatives of the several underwriters named in the
Securities Act Registration Statement. The Trustee shall deliver such
Certificates to such location and at such time as is stated in the written
transfer instructions from Grantor and shall release such Certificates (a) upon
the receipt from Grantor of one or more Certificates, duly endorsed for
transfer, that evidence a number of
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Units equal to or not less than the number of Units evidenced by the
Certificates to be so released and (b) in accordance with the instructions of
Grantor. At the Closing, the Trustee shall receive the following documents dated
as of the date of the Closing: (i) local counsel opinions and opinions of Kelly,
Hart & Hallman, P.C. and Butler & Binion, L.L.P. addressed to the Trustee
substantially in the forms of the opinions to be delivered by such counsel at
the Closing pursuant to the underwriting agreement referred to in the Securities
Act Registration Statement (the "Underwriting Agreement"), (ii) a certificate of
Grantor signed by an executive officer certifying that the representations and
warranties of Grantor contained in the Underwriting Agreement are true and
correct as of the date of the Closing and (iii) such other documents or
certificates as the Trustee may reasonably request; provided, that the
certificate regarding Grantor's representations and warranties set forth in said
Underwriting Agreement may be to the best knowledge of the officer certifying as
to such representations and warranties, and shall exclude information furnished
to Grantor in writing by or on behalf of the Trustee.
ARTICLE III. ADMINISTRATION OF THE TRUST
Section 3.01. General. The Trustee accepts the Trust created by this
Indenture and agrees to perform its duties in accordance with the terms of this
Indenture. Subject to the limitations set forth in this Indenture, the Trustee
is authorized to take such action as in its judgment is necessary or advisable
best to achieve the purposes of the Trust, including the authority to enter into
the Conveyances, to agree to modifications or settlements of the terms of the
Conveyances or to settle disputes with respect thereto, so long as such
modifications or settlements do not alter the nature of the Royalties as rights
to receive a share of the proceeds of oil and gas produced from the properties
presently burdened by such Royalties which are free of any obligation for
operating expenses and as rights which do not possess any operating rights or
obligations. The Trustee may not dispose of all or any portion of the Royalties
except as provided in Sections 3.02, 3.05, 3.09 and 9.03 of this Indenture.
Section 3.02. Limited Power to Dispose of Royalties.
(a) In the event the Trustee determines it to be in the best interest
of the Unitholders the Trustee may sell, at any time and from time to time,
all or any part of any of the Royalties for cash in such a manner as it
deems in the best interest of the Unitholders if approved by the
Unitholders present or represented at a meeting held in accordance with the
requirements of Article VIII. This Section 3.02(a) shall not be construed
to require approval of the Unitholders for any sale or other disposition of
all or any part of the Royalties pursuant to Sections 3.02(b), 3.05, 3.09
or 9.03. The Trustee is authorized to retain any of the Royalties in the
form in which such property was transferred to the Trustee, without regard
to any requirement to diversify investments or other requirements.
(b) Grantor may at any time and from time to time notify the Trustee
that it desires to sell for cash any of the Subject Interests to any Person
not an Affiliate of Grantor free of and unburdened by the Royalties, and
upon receipt of such notice the Trustee shall be required to join in such
sale and execute and deliver a partial release, assignment or such other
instrument as Grantor may reasonably request to evidence that such Subject
Interest is being sold free and unburdened by the Royalties; provided,
however, that the Trustee shall not be required to join in such sale if the
value of the Royalties (determined as provided below) associated with the
Subject Interests to be so sold in any calendar year pursuant to this
Section 3.02(b) exceeds one
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percent (1%) of the value of all the Royalties before such sale. The net
proceeds from any sale pursuant to this Section 3.02(b) shall be allocated
twenty percent (20%) to Grantor and eighty percent (80%) to the Trust. For
purposes of this Section 3.02(b), the value of the Royalties associated
with the Subject Interests to be sold and of all the Royalties shall be the
discounted present value of the future net revenue attributable to the
proved reserves attributable to such Royalties, respectively, as determined
by reference to the Reserve Report as of December 31 of the year preceding
the closing of the sale. The use of such values is solely for the purpose
of determining compliance with this Section 3.02(b) and it is recognized
that the proceeds of sale may be greater or lesser than the value so
determined.
Section 3.03. No Power to Engage in Business or Make Investments. The
Trustee shall not, in its capacity as Trustee under the Trust, engage in any
business or commercial activity of any kind whatsoever and shall not, under any
circumstances, use any portion of the Trust Estate to acquire any oil and gas
lease, royalty or other mineral interest other than the Royalties, or, except as
permitted in Sections 3.04 and 3.15, acquire any other asset. The Trustee shall
have no right or duty to operate the Subject Interests burdened by the Royalties
or to market any production therefrom. The Trustee shall not accept
contributions to the Trust other than the Royalties and the initial cash
deposit.
Section 3.04. Interest on Cash on Hand. Cash being held by the Trustee as
a reserve for liabilities or for distribution at the next Distribution Date
shall be invested (in the Trustee's discretion) in: (a) obligations issued (or
unconditionally guaranteed) by the United States of America or any agency or
instrumentality thereof (provided such agency or instrumentality obligations are
secured by the full faith and credit of the United States of America), (b)
repurchase agreements secured by obligations qualifying under subparagraph (a)
above, or (c) certificates of deposit of any bank having capital, surplus and
undivided profits in excess of $100,000,000; provided such repurchase agreements
or certificates of deposit shall bear interest at a rate that is not less than
the greater of (i) the interest rate that the Bank or its successor pays in the
normal course of business on amounts placed with it, taking into account the
amounts involved, the period held and other relevant factors, or (ii) the rate
of interest paid on obligations qualifying under subparagraph (a) above. Any
such obligations, repurchase agreements or certificates representing funds to be
distributed at the next Distribution Date must mature on or before such
Distribution Date and must be held to maturity. To the extent not prohibited by
Section 113.057 of the Texas Trust Code, any such cash may be placed with the
Bank or any successor bank serving as Trustee.
Section 3.05. Power to Settle Claims. Subject to the limitations
specified in Article XI, the Trustee is authorized to prosecute or defend, or to
settle by arbitration or otherwise, any claim of or against the Trustee, the
Trust or the Trust Estate, to waive or release rights of any kind and to pay or
satisfy any debt, tax or claim upon any evidence by it deemed sufficient,
without the joinder or consent of any Unitholder. Such authority shall include,
but not be limited to, the authority to dispose of or relinquish title to any of
the Royalties that are the subject of such a dispute upon receipt of such
evidence. The Trustee agrees to respond definitively to, and within a
commercially reasonable time period following its receipt of, any written
request by Grantor relating to any such claim and complying with the last
sentence of this Section 3.05, and the failure of the Trustee so to respond
definitively and timely shall conclusively estop the Trustee from thereafter
claiming a right that is inconsistent with the stated intent as set forth in the
notice and materially detrimental to Grantor or its Affiliates with respect
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to such requested matter. Any request made by Grantor intended to be governed by
this Section 3.05 shall specifically reference this Section.
Section 3.06. Power to Contract for Services. In the administration of the
Trust, the Trustee is empowered to employ oil and gas consultants, independent
reservoir engineers, accountants (who may be the same accounting firm who are
engaged as outside auditors for Grantor), attorneys (who may be counsel to
Grantor unless Grantor otherwise notifies the Trustee in writing), transfer
agents and other professional and expert persons and to employ or contract for
clerical and other administrative assistance (including assistance from Grantor
or its Affiliates) and to make payments of all fees for services or expenses in
any manner thus incurred out of the Trust Estate.
Section 3.07. Payment of Liabilities of Trust. The Trustee shall, to the
extent that funds of the Trust are available therefor (which shall not include
funds previously set aside for payment of a Monthly Distribution Amount), make
payment of all liabilities of the Trust, including, but without limiting the
generality of the foregoing, all expenses, taxes, liabilities of all kinds,
including compensation to it for its services hereunder, and compensation to
such parties as may be employed as provided for in Section 3.06 hereof.
Section 3.08. Establishment of Reserves. With respect to any liability
which is contingent or uncertain in amount or which otherwise is not currently
due and payable, the Trustee in its sole discretion may, but is not obligated
to, establish a cash reserve for the payment of such liability.
Section 3.09. Limited Power to Borrow. If at any time the cash on hand and
to be received by the Trust and available to pay liabilities is not, or will not
be, in the judgment of the Trustee, sufficient to pay liabilities of the Trust
as they become due or to purchase Units if required under Section 3.15(b), the
Trustee is authorized to borrow the funds required to pay such liabilities or
make such purchases. In such event, no further distributions will be made to
Unitholders (except in respect of previously determined Monthly Distribution
Amounts) until the indebtedness created by such borrowing has been paid in full.
Such funds may be borrowed from any Person, including, without limitation, the
Bank or any other fiduciary hereunder. To secure payment of such indebtedness,
the Trustee is authorized to mortgage, pledge, grant security interests in or
otherwise encumber (and to include as a part thereof any and all terms, powers.
remedies, covenants and provisions deemed necessary or advisable in the
Trustee's discretion, including, without limitation, the power of sale with or
without judicial proceedings) the Trust Estate, or any portion thereof,
including the Royalties, and to carve out and convey production payments.
Section 3.10. Income and Principal. The Trustee shall not be required to
keep separate accounts or records for income and principal or maintain any
reserves for depletion of the Royalties. However, if the Trustee does keep such
separate accounts or records, then the Trustee is authorized to treat all or any
part of the receipts from the Royalties as income or principal, and in general
to determine all questions as between income and principal and to credit or
charge to income or principal or to apportion between them any receipt or gain
and any charge, disbursement or loss as is deemed advisable under the
circumstances of each case. Regardless of any such characterization, however,
the Trustee shall not make any distribution, accumulate any funds, or maintain
any reserve except as expressly provided in this Indenture.
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Section 3.11. Term of Contracts. In exercising the rights and powers
granted hereunder, the Trustee is authorized to make the term of any transaction
or contract or other instrument extend beyond the term of the Trust.
Section 3.12. Transactions between Related Parties. The Trustee shall not
be prohibited in any way in exercising its powers from making contracts or
having dealings with itself in any other capacity (fiduciary or otherwise) or
with Grantor.
Section 3.13. No Bond Required. The Trustee shall not be required to
furnish any bond or security of any kind.
Section 3.14. Timing of Trust Income and Expenses. The Trustee will use
all reasonable efforts to cause the Trust and the Unitholders to recognize
income and expenses on Monthly Record Dates. The Trustee will invoice the Trust
for services rendered by the Trustee only on a Monthly Record Date and shall
cause the Trust to pay any such invoices only on the Monthly Record Date on
which an invoice is rendered and will use all reasonable efforts to cause all
Persons to whom the Trust becomes liable to invoice the Trust for such liability
on a Monthly Record Date and to cause the Trust to pay any such liabilities on
the Monthly Record Date on which such liability is invoiced. In connection with
the requirements of any securities exchange on which the Units are listed or
market system through which Units are traded, the Trustee will, if required by
such securities exchange or market system, use all reasonable efforts to
determine the Monthly Distribution Amount and report such amount to the exchange
or market system at such time as may be required by such securities exchange or
market system. Nothing in this Section 3.14 shall be construed as requiring the
Trustee to cause payment to be made for Trust liabilities on any date other than
on such date as in its sole discretion it shall deem to be in the best interest
of the Unitholders.
Section 3.15. Divestiture of Units. If at any time the Trust or the
Trustee is named a party in any judicial or administrative proceeding which
seeks the cancellation or forfeiture of any property in which the Trust has an
interest because of the nationality, or any other status, of any one or more
Unitholders, the following procedures will be applicable:
(a) The Trustee will promptly give written notice ("Notice") to each
Unitholder ("Ineligible Holder") whose nationality or other status is an
issue in the proceeding as to the existence of such controversy related to
the Royalties, the Trust or the Trust Units. The Notice will contain a
reasonable summary of such controversy and will constitute a demand to each
Ineligible Holder that he dispose of his Units to a party which would not
be an Ineligible Holder within 30 days after the date of the Notice.
(b) If any Ineligible Holder fails to dispose of his Units as required
by the Notice, the Trustee will have the right to purchase, and will
purchase, any such Units at any time during the 90 days after the
expiration of the 30-day period specified in the Notice. The purchase price
on a per Unit basis will be determined as of the last Business Day
("determination day") preceding the end of the 30-day period specified in
the Notice and will equal the following per Unit amount: (i) if the Units
are then listed on a securities exchange the price will equal the closing
price of the Units on such exchange (or, if the Units are then listed on
more than one exchange, on the largest such exchange in terms of the volume
of Units traded thereon during the preceding
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twelve months) on the determination day if any Units were sold on such
exchange on such day or, if not, on the last preceding day on which any
Units were sold on such exchange or (ii) if the Units are not then listed
on any securities exchange, but are traded through a market system, the
price will equal the mean between the closing bid and asked prices for the
Units in such market system on the determination day if quotations for such
prices on such day are available or, if not, on the last preceding day for
which such quotations are available or (iii) if the Units are not then
listed on any stock exchange or traded through any market system, the price
will be determined by multiplying the present value of the estimated future
net revenues attributable to proved reserves of the Royalties as reflected
in the latest Reserve Report prepared for the Trust (minus all liabilities
of the Trust) by 1.4 and by then dividing such amount by the number of
Units (including the Units to be purchased) then outstanding. Such purchase
will be accomplished by tender of the above cash price to the Ineligible
Holder at his address as shown on the records of the Trustee, either in
person or by mail as provided in Section 12.06, accompanied by notice of
cancellation. Concurrently with such tender the Trustee shall cancel or
cause to be cancelled all Certificates representing Units then owned by
such Ineligible Holder and for which tender has been made, and the Trustee
shall issue or cause to be issued to itself a Certificate or Certificates
representing the same number of Units as were so cancelled. Upon such
cancellation, the Ineligible Holder shall part with the Beneficial Interest
attributable to the Units theretofore owned by him and all interests,
rights and benefits of the Ineligible Holder as a Unitholder shall
terminate. In the event the tender is refused by the Ineligible Holder or
if he cannot be located after reasonable efforts to do so, the tendered sum
shall be held by the Trustee in an interest bearing account for the benefit
of such Ineligible Holder, until proper claim for same (together with
interest accrued thereon) has been made by such Holder, but subject to
applicable laws concerning unclaimed property.
(c) The Trustee may, in its sole discretion, cancel any Units acquired
in accordance with the foregoing procedures or may sell such Units, either
publicly or privately, in accordance with all applicable laws. The proceeds
of any such sale of Units, less the expenses of such sale, will constitute
revenues of the Trust.
Section 3.16. Filing of Registration Statements, Listing of Units.
(a) The Trustee shall, in connection with the initial public offering
of the Units and otherwise, upon the request of Grantor, on behalf of the
Trust, cooperate with Grantor and otherwise use its best efforts to cause:
(i) one or more Securities Act Registration Statements to be
prepared, signed, filed and declared effective by the SEC;
(ii) an Exchange Act Registration Statement to be prepared,
signed, filed and become effective;
(iii) the Units to be qualified or exempted from qualification
under the securities or Blue Sky laws of the several states; and
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(iv) the Units to be listed for trading on the NYSE or another
national securities exchange, as it shall select, or, if listing on a
national securities exchange is not feasible or is undesirable, to
cause the Units to be admitted for quotation on the NASDAQ.
(b) Grantor shall be obligated and entitled, at its own expense except
as otherwise herein provided, to take or cause to be taken all steps
customary or appropriate to the accomplishment of the objectives set forth
above including, without limitation, engaging counsel for itself and
approving special counsel for the Trust, engaging accountants for the
Trust, contracting for all printing and engraving services, making all
filings and applications necessary to the foregoing and paying all filing
and application fees associated therewith. The Trustee shall execute, by
and on behalf of the Trust, any documents incidental or related to the
foregoing as reasonably requested by Grantor. Notwithstanding anything in
this Section 3.16 to the contrary, unless required by the SEC, the Trustee
shall not be required to sign any Securities Act Registration Statement or
Exchange Act Registration Statement in connection with the initial public
offering or any subsequent offering of the Units. If the Trustee does not
sign any Securities Act Registration Statement or Exchange Act Registration
Statement on behalf of the Trust in connection with the initial public
offering or any subsequent offering of the Units by Grantor, then Grantor
may sign on behalf of the Trust.
(c) Except as precluded in Article VI, the reasonable fees, charges,
expenses, disbursements and other costs incurred by the Trustee in
connection with the discharge of its duties under this Section 3.16 shall
be paid by Grantor.
(d) The Trustee shall cooperate with and assist Grantor in every
reasonable way and in good faith in accomplishing the foregoing. Among
other things, the Trustee shall permit counsel, special counsel and
accountants engaged by Grantor and other representatives of Grantor
reasonable access to information responsive to the requirements of the
Securities Act, the Exchange Act, the securities or Blue Sky laws of the
several states, the rules of any securities exchange upon which listing is
to be sought and the rules of the NASD, and to Trustee personnel having
such information, as fully and to the same extent as if the Trustee were
proceeding for its own purposes to accomplish such objectives. The Trustee
agrees to provide Grantor with the authority and, if required pursuant to
Section 3.16(b) above, the signatures required for the filing of the
Securities Act Registration Statements, the Exchange Act Registration
Statement, and registration statements, notices of exemption, applications
for exemption, consents to service of process and all other documents
necessary to comply with the Blue Sky laws of the several states, a listing
application with the NYSE or any other national securities exchange or an
application for quotation on the NASDAQ. The Trustee shall also provide
Grantor upon request with a Unitholders' list as of the latest Monthly
Record Date in such form as Grantor may reasonably request.
(e) After the registration of the Units pursuant to the Exchange Act
and/or the listing of the Units on the NYSE or another national securities
exchange or the admission for quotation of the Units on the NASDAQ, the
Trustee, on behalf of the Trust, shall cause the Trust to comply with all
of the rules, orders and regulations of the SEC, such exchange or the
NASDAQ,
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and take all such other actions necessary for the Units to remain so
registered, listed or admitted for quotation until the Trust is terminated.
(f) The Trustee shall be empowered to, in connection with the initial
public offering of the Units or such other public offering of Units, upon
request of Grantor, in the name and on behalf of the Trust, enter into any
underwriting or similar securities purchase agreement for the purpose of
causing the Trust to provide certain warranties and agreements, including,
without limitation, providing, jointly and severally with the Grantor,
indemnification in favor of the underwriters and their control persons for
material misstatements and omissions made in connection with the public
offering (and related contribution agreements), and in connection therewith
the Trustee shall, upon request of Grantor, provide certificates and other
documents (provided that in no event shall the Trustee be required to sign
any registration statement under the Securities Act or Exchange Act unless
required to do so by the SEC) and engage legal counsel to provide opinions
of counsel reasonably requested by the underwriters under such agreements;
provided that the warranties and agreements or obligations of the Trust
under this paragraph (f) shall be limited solely to the assets of the Trust
and shall not result in the incurrence of any liability by the Trustee or
any Unitholder.
(g) To the fullest extent permitted by law, Grantor agrees to defend,
indemnify and hold the Trust and the Trustee harmless from and against any
loss, cost, claim, damage, expense or liability, joint or several, or any
action in respect thereof, to which the Trust or the Trustee or the
officers, employees or agents of the Trustee or any controlling person of
the Trustee becomes subject, under the Securities Act or the Exchange Act,
or otherwise, insofar as such loss, cost, claim, damage, expense or
liability or action arises out of, or is based upon, (i) any untrue
statement or alleged untrue statement of a material fact contained in any
Securities Act Registration Statement or Exchange Act Registration
Statement, or any other document filed by or on behalf of Grantor with the
SEC, or any other statement publicly made by or on behalf of Grantor, or
(ii) the omission or alleged omission to state in any Securities Act
Registration Statement or Exchange Act Registration Statement, or any other
document, or any other statement publicly made by or on behalf of Grantor,
any material fact required to be stated therein or necessary to make the
statements therein not misleading; provided, however, that Grantor shall
not be liable in any case to the extent that any such loss, cost, claim,
damage, expense, liability or action arises out of, or is based upon, (A)
any fraudulent misrepresentation, gross negligence or willful misconduct of
the Trustee or (B) any untrue statement or alleged untrue statement or
omission or alleged omission included in any such Securities Act
Registration Statement or Exchange Act Registration Statement, or any other
document filed by or on behalf of Grantor, the Trust or the Trustee with
the SEC, or any other statement publicly made by or on behalf of Grantor,
the Trust or the Trustee in reliance upon and in conformity with written
information furnished by or on behalf of the Trustee specifically for
inclusion therein. This provision shall in no way limit the general rights
to indemnification and contribution and limitations on liability of the
Trust and Trustee set forth in Article VI of this Indenture or elsewhere
herein.
Section 3.17. Reserve Reports. If a Reserve Report for the Royalties is
not provided by Grantor pursuant to Section 4.08 of the Conveyances, the Trustee
shall cause a Reserve Report for the Royalties to be prepared as of December 31
of each year, in accordance with criteria established by the SEC
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showing estimated proved oil and gas reserves attributable to the Royalties as
of December 31 of such year and other reserve information required in order for
the Trustee to furnish the information required in Sections 5.03 and 5.04 of
this Indenture. The Reserve Reports shall be prepared by a firm of independent
petroleum engineers selected by the Trustee. Such Reserve Report shall also show
estimated future net revenues and the net present value (discounted at 10
percent or such other rate required by the SEC) of the estimated future net
revenues (calculated in accordance with criteria established by the SEC) of
proved reserves attributable to the Royalties. The costs of such Reserve
Reports, whether provided by Grantor or obtained by the Trustee, shall
constitute an administrative expense of the Trust payable out of the Trust
Estate pursuant to Section 3.07. Grantor shall assist the Trustee in the
preparation of the Reserve Reports by furnishing all current and existing
reserve, production and geophysical data in its possession relating to the
Royalties reasonably requested by or on behalf of the independent petroleum
engineers selected by the Trustee as necessary to prepare such Reserve Reports;
provided, that Grantor shall not be required to disclose or produce any
information, documents or other materials which (a) were generated for analysis
or discussion purposes or contain interpretative data or (b) are subject to the
attorney-client or attorney-work product privileges, or any other privileges to
which Grantor may be entitled pursuant to applicable law.
Section 3.18. Miscellaneous. Except as otherwise provided in this
Indenture, this Indenture and the Trust shall be governed, construed,
administered and controlled by and under the laws of the State of Texas, and the
rights, powers, duties and liabilities of the Trustee shall be in accordance
with and governed by the terms and provisions of the Texas Trust Code and other
applicable laws of the State of Texas as in effect at any applicable time.
ARTICLE IV. BENEFICIAL SHARES AND CERTIFICATES
Section 4.01. Creation and Distribution. The entire Beneficial Interest
shall be divided into 40,000,000 Units. The ownership of the Units shall be
evidenced by Certificates in substantially the form of Schedule 1 attached to
this Indenture, containing such changes or alterations of form, but not
substance, as the Trustee shall from time to time, in its discretion, deem
necessary or desirable.
Section 4.02. Beneficial Interest of Unitholders. Each Unit shall
represent pro rata undivided ownership of the Beneficial Interest and shall
entitle its holder to participate pro rata in the rights and benefits of the
Unitholders under this Indenture. A Unitholder (by assignment or otherwise)
shall take and hold each Unit subject to all the terms and provisions of this
Indenture and the Conveyances, which shall be binding upon and inure to the
benefit of the heirs, personal representatives, successors and assigns of the
Unitholder. By an assignment or transfer of one or more Units represented by a
Certificate, the assignor thereby shall, effective as of the close of business
on the date of transfer and with respect to such assigned or transferred Unit or
Units, part with, except as provided in Section 4.04 in the case of a transfer
after a Monthly Record Date and prior to the corresponding monthly payment date,
(i) all his Beneficial Interest attributable thereto; (ii) all his rights in, to
and under such Certificate; and (iii) all interests, rights and benefits under
this Trust of a Unitholder which are attributable to such Unit or Units as
against all other Unitholders and the Trustee. The Certificates, the Units and
the rights, benefits and interests evidenced by either or both (including,
without limiting the foregoing, the entire Beneficial Interest) are and shall be
held and construed to be in all respects intangible personal property, and the
Certificates and Units evidenced thereby shall be bequeathed, assigned, disposed
of and distributed as intangible personal property. No Unitholder as such shall
have any legal or equitable title
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in or to any real or personal property interest which is a part of the Trust
Estate, including, without limiting the foregoing, the Royalties or any part
thereof, but the sole interest of each Unitholder shall be such Unitholder's
Beneficial Interest and the obligation of the Trustee to hold, manage and
dispose of the Trust Estate and to account for the proceeds thereof as herein
provided. No Unitholder shall have the right to call for or demand or secure any
partition or distribution of the Royalties during the continuance of the Trust
or during the period of liquidation and winding up under Section 9.03 of this
Indenture.
Section 4.03. Execution of Certificates.
(a) All Certificates shall be signed by a duly authorized officer of
the Trustee. Certificates may be signed on behalf of the Trustee by such
persons as at the actual date of the signing of such Certificates shall be
the proper officers of the Trustee, although at the nominal date of such
Certificates any such person shall not have been such officer of the
Trustee. Any such signature may be the manual or facsimile signature (to
the extent permitted by law or the rules or regulations of any stock
exchange or quotation system on which the Units are listed or traded) of
such officers and may be affixed, imprinted or otherwise reproduced on the
Certificate.
(b) Pending the preparation of definitive Certificates, the Trustee
shall execute, and the transfer agent and registrar for the Units appointed
in accordance with Section 3.06 of this Indenture shall countersign and
register, temporary Certificates, as directed in a certificate of an
officer of Grantor. Temporary Certificates may contain such references to
any provisions of this Indenture as may be appropriate. Each temporary
Certificate shall be executed by the Trustee and signed and registered upon
the same conditions and in substantially the same manner, and with like
effect as the definitive Certificates.
(c) As promptly as practicable, the Trustee shall execute and furnish
definitive Certificates and thereupon temporary Certificates may be
surrendered in exchange therefor without charge to the Unitholders at the
principal office of the transfer agent at which Certificates may be
presented for transfer pursuant to Section 4.04 hereof, and the Trustee (or
the transfer agent and registrar if the Trustee is not serving in such
capacities) shall sign and register in exchange for such temporary
Certificates a like aggregate amount of definitive Certificates. Until so
exchanged, the temporary Certificates shall be entitled to the same
benefits under this Indenture as definitive Certificates.
Section 4.04. Registration and Transfer of Units. The Units shall be
transferable as against the Trustee as provided herein, and then only on the
records of the Trustee and, except as provided in Section 3.15 hereof, upon the
surrender of Certificates, if any, and compliance with such reasonable
regulations as it may prescribe. No service charge shall be made to Unitholders
or Transferees for any transfer of a Unit, but the Trustee may require payment
of a sum sufficient to cover any tax or other governmental charge that may be
imposed in relation thereto. Until any such transfer is completed, the Trustee
may treat the owner of any Unit as shown by its records as the owner of the Unit
for all purposes and shall not be charged with notice of any claim or demand
respecting such Unit or the Beneficial Interest represented thereby by any other
party. Any such transfer of a Unit shall, as to the
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Trustee, transfer to the Transferee as of the close of business on the date of
transfer all of the Beneficial Interest of the transferor; provided that a
transfer of a Unit after any Monthly Record Date shall not transfer to the
Transferee the right of the transferor to any sum payable to such transferor as
title holder of the Certificate of record on said Monthly Record Date. As to
matters affecting the title, ownership, warranty or transfer of Units and
Certificates, except as provided to the contrary herein, Article 8 of the
Uniform Commercial Code, the Texas Uniform Act for Simplification of Fiduciary
Security Transfers under Chapter 33 of the Texas Business and Commerce Code and
other statutes and rules with respect to the transfer of securities, each as
adopted and then in force in the State of Texas, shall govern and apply. The
death of any Unitholder shall not entitle the Transferee to an accounting or
valuation for any purpose, but such Transferee shall succeed to all rights of
the deceased Unitholder under this Indenture upon proper proof of title
satisfactory to the Trustee.
Section 4.05. Mutilated, Lost, Stolen and Destroyed Certificates. If any
Certificate is lost, stolen, destroyed or mutilated, the Trustee, in its
discretion and upon proof satisfactory to the Trustee, together with receipt by
the Trustee of a surety bond sufficient in the opinion of the Trustee to
indemnify the Trustee and the Trust against all losses and expenses that may
reasonably be expected to be incurred in connection therewith (if deemed
advisable by the Trustee), and surrender of the mutilated Certificate, will
issue a new Certificate to the holder of such lost, stolen, destroyed or
mutilated Certificate as shown by the records of the Trustee, upon payment of a
reasonable charge of the Trustee and any reasonable expenses incurred by it in
connection therewith.
Section 4.06. Protection of Trustee. The Trustee shall be protected in
acting or relying upon any notice, certificate, assignment or other document or
instrument believed by the Trustee to be genuine and to be signed by the proper
party or parties, including, without limitation, any instructions or documents
received from Grantor in connection with this Indenture. Except as provided
herein to the contrary, the Trustee is specifically authorized to rely upon the
application of Article 8 of the Uniform Commercial Code, the application of the
Texas Uniform Act for Simplification of Fiduciary Security Transfers under
Chapter 33 of the Texas Business and Commerce Code and the application of other
statutes and rules with respect to the transfer of securities, each as adopted
and then in force in the State of Texas, as to all matters affecting title,
ownership, warranty or transfer of the Certificates and the Units represented
thereby, without any personal liability for such reliance, and the indemnity
granted under Section 6.02 of this Indenture shall specifically extend to any
matters arising as a result thereof.
Section 4.07. Determination of Ownership of Certificates. In the event of
any disagreement between persons claiming to be Transferees of any Unit, and in
addition to any other rights it may have under applicable law, the Trustee shall
be entitled, at its option, to refuse to recognize any such claim so long as
such disagreement shall continue. In so refusing, the Trustee may elect to make
no delivery or other disposition of the interest represented by the Certificate
involved, or any part thereof, or of any sum or sums of money, accrued or
accruing thereunder, and, in so doing, the Trustee shall not be or become liable
to any Person for the failure or refusal of the Trustee to comply with such
conflicting claims, and the Trustee shall be entitled to continue so to refrain
and refuse so to act, until
(a) the rights of the adverse claimants have been adjudicated by
arbitration (pursuant to Article XI) or by a final nonappealable judgment
of a court assuming and having jurisdiction of the parties and the interest
and money involved, or
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(b) all differences have been resolved by valid agreement between said
parties and the Trustee shall have been notified thereof in writing signed
by all of the interested parties.
ARTICLE V. ACCOUNTING AND DISTRIBUTION; REPORTS
Section 5.01. Fiscal Year and Accounting Method. The fiscal year of the
Trust shall be the calendar year. The Trustee shall maintain its books in
accordance with generally accepted accounting principles or such other method as
will provide appropriate financial data responsive to the needs of the
Unitholders and which shall comply with Sections 5.03 and 5.04.
Section 5.02. Distributions. The Trustee shall determine the Monthly
Distribution Amount for each month and shall establish a cash reserve equal to
such amount on the Monthly Record Date for such month. On the Distribution Date
for such Monthly Distribution Amount, the Trustee will distribute pro rata to
the Unitholders of record on such Monthly Record Date such Monthly Distribution
Amount.
Section 5.03. Income Tax Reporting. For federal or state income tax
purposes, the Trustee shall file for the Trust such returns and statements as in
its judgment are required to comply with applicable provisions of the Code and
regulations and any applicable state laws and regulations, in either case to
permit each Unitholder to report such Unitholder's share of the income and
deductions of the Trust. The Trustee will treat all income and deductions of the
Trust for each month as having been realized on the Monthly Record Date for such
month unless otherwise advised by its counsel or the Internal Revenue Service.
The Trustee will report as a grantor trust until and unless it receives an
opinion of tax counsel that such reporting is no longer proper. Within 75 days
following the end of each fiscal year, the Trustee shall mail, to each
Unitholder of record on a Monthly Record Date during such fiscal year, a report
which shall show in reasonable detail such information as is necessary to permit
all holders of record of Units on a Monthly Record Date during such fiscal year
to make calculations necessary for tax purposes, including depletion.
Section 5.04 Reports to Unitholders. As promptly as practicable following
the end of each calendar quarter except the fourth calendar quarter, (a) the
Trustee shall mail to each Person who was a Unitholder of record on a Monthly
Record Date during such quarter a report which shall show in reasonable detail
such information as is necessary to permit holders of Units to make all
calculations necessary for tax purposes including depletion, and (b) the Trustee
shall mail to each Person who was a Unitholder of record on the last Monthly
Record Date during such calendar quarter a report, which may be a copy of the
Trust's report on Form 10Q under the Exchange Act, which shall show the assets
and liabilities of the Trust at the end of such quarter and distributable income
of the Trust for such quarter. Within 120 days following the end of each fiscal
year, the Trustee shall mail, to each Unitholder of record on a date to be
selected by the Trustee, an annual report containing financial statements
audited by a nationally recognized firm of public accountants selected by the
Trustee. Notwithstanding the foregoing, the Trustee will furnish to the
Unitholders such reports, in such manner and at such times, as are at any time
required by law or by rules or regulations of any securities exchange or
quotation system on which the Units are listed or admitted for trading.
Section 5.05. Filings. The Trustee is authorized to make all Exchange Act
filings on behalf of the Trust required by applicable law or regulation. It is
the intention of Grantor that the Units be listed
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on the NYSE, and, in this regard, Grantor shall advise the Trustee of any
actions (consistent with the purposes of the Trust) that the Trustee should take
in connection with the effectuation of such listing. If listing is accomplished,
the Trustee shall take all reasonable actions necessary to maintain such
listing, including compliance with the stock exchange's rules and the filing of
any reports required by the stock exchange. Grantor shall prepare and file all
filings and reports required under the Securities Act or state securities or
Blue Sky laws. The Trustee is authorized to and shall take all reasonable
actions to prepare and mail to Unitholders, any reports, press releases or
statements, financial or otherwise, that Grantor notifies the Trustee in writing
are required to be provided by the Trust to Unitholders by law or governmental
regulation or the requirements of any securities exchange or quotation system on
which the Units are listed or admitted for trading, subject to receipt by the
Trustee of a satisfactory opinion of counsel confirming the necessity of such
reports, if such an opinion is deemed necessary by the Trustee.
Section 5.06. Information to be Supplied by Grantor and Trustee. Grantor
shall provide, or cause to be provided, to the Trustee on a timely basis (a) an
annual audited statement of revenues and direct operating expenses of the
Subject Interests and quarterly statements of revenues and direct operating
expenses of the Subject Interests, which quarterly statements may be on a
condensed basis and need not be audited by a firm of independent accountants and
(b) such other information as is not known to the Trustee or is otherwise more
easily available to Grantor than to the Trustee concerning the Royalties
(including information with respect to the properties burdened by the Royalties)
and related matters as shall be necessary for Trustee to comply with the
reporting obligations of the Trust pursuant to the Exchange Act, the
requirements of any securities exchange or quotation system on which the Units
are listed or admitted for trading and this Indenture, including, without
limitation, Sections 5.03, 5.04 and 5.05 hereof. For purposes of this Section
5.06, the phrase "timely basis" shall mean not less than 10 days prior to the
date on which the Trustee is required to comply with such reporting obligations
of the Trust. In addition, Grantor shall provide to the Trustee on a timely
basis, for use in connection with the Trust's Form 10-K annual report, a
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" relating to such financial statements. Notwithstanding any
provision to the contrary in this Indenture or the Conveyances, Grantor and its
Affiliates shall not be required to disclose, produce or prepare any
information, documents or other materials which (i) were generated for analysis
or discussion purposes or contain interpretative data or (ii) are subject to the
attorney-client or attorney-work-product privileges, or any other privileges to
which they may be entitled pursuant to applicable law. At least one Business
Day prior to reporting the Monthly Distribution Amount to the securities
exchange or market system in accordance with Section 3.14, the Trustee shall
provide to Grantor a written and reasonably detailed report showing such Monthly
Distribution Amount and each administrative cost of the Trust paid or payable
for such Monthly Period, including, but not limited to, each out-of-pocket
expenditure, and all Trustee compensation. The Trustee will respond promptly to
Grantor's reasonable questions regarding such report.
Section 5.07. Reliance on Information. The Trustee, so long as acting in
good faith, shall be entitled to rely, without investigation, on all information
provided to it by Grantor for purposes of complying with the reporting
obligations of the Trust as contemplated by Section 5.06, including, without
limitation, information regarding depletion and entitlement to tax credits under
Section 29 of the Code. Notwithstanding any time limit imposed by applicable
laws or regulations or by the provisions of this Indenture, if, due to the
unavailability prior to the expiration of any such time limit of information
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necessary, or a delay in receipt by the Trustee of information necessary, for
preparation of a report required to be filed, made or delivered by the Trustee,
the Trustee shall be unable to prepare and file or mail such report within such
time limit, the Trustee shall prepare and file or mail such report as soon as
practicable after such information is received.
ARTICLE VI. LIABILITY OF TRUSTEE,
INDEMNIFICATION AND METHOD OF SUCCESSION
Section 6.01. Liability of Trustee.
(a) Except as otherwise provided herein and specifically except as
provided in subparagraph (b) below, the Trustee, in carrying out its powers
and performing its duties, may act in its discretion directly, or at the
expense of the Trust, through agents or attorneys pursuant to agreements
entered into with any of them, and shall be personally or individually
liable only for fraud or gross negligence or for acts or omissions in bad
faith as adjudicated by final, nonappealable judgment of a court of
competent jurisdiction and shall not individually or personally be liable
for any act or omission of any agent or employee of the Trustee unless the
Trustee has acted in bad faith or with gross negligence in the selection
and retention of such agent or employee.
(b) If the Trustee enters into a contract on behalf of the Trust
Estate without ensuring that any liability arising out of such contract
shall be satisfiable only out of the Trust Estate and shall not in any
event, including the exhaustion of the Trust Estate, be satisfiable out of
amounts at any time distributed to any Unitholder or out of any other
assets owned by any Unitholder, then Trustee, vis-a-vis the Unitholders,
shall be fully and exclusively liable for such liability, but shall have
the right to be indemnified and reimbursed from the Trust Estate to the
extent provided in Section 6.02.
Section 6.02. Indemnification of Trustee. The Trustee and its officers,
agents and employees when acting in such capacity shall be indemnified by, and
receive reimbursement from, the Trust Estate against and from any and all
liability, expense, claims, damages or loss incurred by it individually or as
Trustee in the administration of the Trust and the Trust Estate or any part or
parts thereof, including, without limitation, any liability, expense, claims,
damages or loss arising out of or in connection with any liability under
Environmental Laws, or in the doing of any act done or performed or omission
occurring on account of its being Trustee or acting in such capacity, except
such liability, expense, claims, damages or loss as to which it is liable under
Section 6.01. Trustee shall have a lien upon the Trust Estate to secure it for
such indemnification and reimbursement and for compensation to be paid to
Trustee. Except as provided in Section 4.05, neither the Trustee nor any
officer, agent or employee of the Trustee shall be entitled to any reimbursement
or indemnification from any Unitholder for any liability, expense, claims,
damages or loss incurred by the Trustee or any such officer, agent or employee,
their right of reimbursement and indemnification, if any, being limited solely
to the Trust Estate (and Grantor pursuant to Section 6.03), whether or not the
Trust Estate is exhausted without full reimbursement or indemnification of the
Trustee or any such officer, agent or employee.
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Section 6.03. Guaranty. If the Trust Estate is exhausted without the
Trustee (or any officer, agent or employee of the Trustee) being fully
reimbursed as provided in Section 6.02 above, then Grantor shall fulfill the
remaining indemnity obligation to the Trustee.
Section 6.04. Contribution. If the indemnification provided for in this
Indenture shall for any reason (including, without limitation, due to violation
of public policy) be unavailable to or insufficient to hold harmless the Trustee
in respect of any liability, expense, claims, damages or loss as to which the
Trustee would otherwise be entitled to indemnification pursuant to Section
3.16(f), 6.02 or 6.03, then Grantor and the Trust shall, in lieu of indemnifying
the Trustee, contribute to the amount paid or payable by the Trustee as a result
of such liability, expense, claims, damages or loss, in such proportion as shall
be appropriate to reflect the relative fault of Grantor (with respect to
contribution by the Trust or Grantor) or the Trustee with respect to the events,
acts or circumstances giving rise to the liability, expense, claims, damages or
loss, as well as any other relevant equitable considerations. For purposes of
determining contribution liability with respect to claims based upon the
Securities Act or Exchange Act, relative fault shall be determined by reference
to whether the untrue or alleged untrue statement of a material fact or
omission or alleged omission to state a material fact relates to information
supplied by Grantor or by the Trustee. The Trustee shall look first to the
Trust Estate for contribution under this Section 6.04, and then to Grantor to
the extent the assets of the Trust Estate are not sufficient to reimburse the
Trustee fully for all such liability, expense, claims, damages or loss.
Section 6.05. Indemnification Procedures. If any action or proceeding
shall be brought or asserted against the Trust, or the Trustee or any officer,
agent or employee thereof (each referred to as an "Indemnified Party" and,
collectively, the "Indemnified Parties") in respect of which indemnity may be
sought from Grantor or the Trust (the "Indemnifying Party") pursuant to Sections
6.02 or 6.03 of this Indenture, of which the Indemnified Party shall have
received notice, the Indemnified Party shall promptly notify the Indemnifying
Party in writing, and the Indemnifying Party shall assume the defense thereof,
including the employment of counsel reasonably satisfactory to the Indemnified
party and the payment of all costs and expenses; provided, however, that the
failure so to notify the Indemnifying Party of the commencement of any such
action or proceeding shall not relieve the Indemnifying Party from any liability
that it may have to any Indemnified Party unless the Indemnifying Party or
Grantor is prejudiced or damaged by the failure to receive prompt notice. The
Indemnified Party shall have the right to employ separate counsel in any such
action and to participate in the defense thereof, but the fees and expenses of
such counsel shall be at the expense of the Indemnified Party unless (i) the
Indemnifying Party has agreed to pay such fees and expenses, (ii) the
Indemnifying Party shall have failed to assume the defense of such action or
proceeding and employ counsel reasonably satisfactory (including the
qualifications of such counsel) to the Indemnified Party on any such action or
proceeding or (iii) the named parties to any such action or proceeding include
both the Indemnified Party and the Indemnifying Party and the Indemnified Party
shall have been advised by counsel that there may be one or more legal defenses
available to such Indemnified Party that are different from or in addition to
those available to the Indemnifying Party or any other Indemnified Party (in
which case, if the Indemnified Party notifies the Indemnifying Party in writing
that it elects to employ separate counsel at the expense of the Indemnifying
Party, the Indemnifying Party shall not have the right to assume the defense of
such action or proceeding on behalf of the Indemnified Party and the Indemnified
Party may employ such counsel for the defense of such action or proceeding as is
reasonably satisfactory to the Indemnifying Party; it being understood, however,
that except in the case of the addition of counsel caused by the existence
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or development of a conflict rendering unified representation impermissible or
unadvisable, the Indemnifying Party shall not, in connection with any one such
action or proceeding or separate but substantially similar or related actions or
proceeding in the same jurisdiction arising out of the same general allegations
or circumstances, be liable for the fees and expenses of more than one separate
firm of attorneys for the Indemnified Parties at any time). The Indemnifying
Party shall not be liable for any settlement of any such action or proceeding
effected without the written consent of the Indemnifying Party, but, if settled
with such written consent, or if there be a final judgment for the plaintiff in
any such action or proceeding, the Indemnifying Party agrees (to the extent
stated above) to indemnify and hold harmless the Indemnified Party from and
against any liability, expense, claims, damages or loss by reason of such
settlement or judgment. The Indemnified Party and the Indemnifying Party (if not
Grantor) shall, if so requested by Grantor, provide reports to Grantor on the
status of such actions or proceedings.
Section 6.06. Resignation of Trustee. The Trustee may resign, with or
without cause, at any time by notice to Grantor and each of the then Unitholders
of record. Such notice shall specify a date when such resignation shall take
effect, which shall be a Business Day not less than ninety days after the date
such notice is mailed; provided, however, that in no event shall any resignation
of the Trustee be effective until a qualified successor Trustee has accepted
appointment as successor Trustee. In case of such resignation, the Trustee will
use its best efforts to nominate a successor, and will call a meeting of
Unitholders for the purpose of appointing a successor, and will solicit proxies
for such meeting. If the Trustee has given notice of resignation in accordance
with this Section 6.06 and a successor has not accepted its appointment as
successor Trustee during the 180-day period following the receipt by Grantor of
such notice of resignation, the annual fee payable to the Trustee as set forth
on Schedule 2 attached hereto shall be increased as of the end of such 180-day
period by ten percent and shall further be increased by ten percent for each
month to a maximum of three times the fee payable at the time the notice of
resignation was received by Grantor until a successor has accepted its
appointment as successor Trustee.
Section 6.07. Removal of Trustee. The Trustee may be removed, with or
without cause, at a meeting held in accordance with the requirements of Article
VIII by the affirmative vote of the holders of a majority of all the Units then
outstanding; provided, however, that any removal of the Trustee shall be
effective only at such time as a qualified successor Trustee has accepted
appointment as successor Trustee.
Section 6.08. Appointment of Successor Trustee. In the event of a vacancy
in the position of Trustee or if the Trustee has given notice of its intention
to resign, the Unitholders present or represented at a meeting held in
accordance with the requirements of Article VIII may appoint a successor
Trustee. Nominees for appointment may be made by (i) the resigned or resigning
Trustee, (ii) any Unitholder or Unitholders owning of record at least 15% of the
Units then outstanding, or (iii) Grantor. Any such successor Trustee shall be a
bank or trust company having a capital, surplus and undivided profits (as of the
end of its last fiscal year prior to its appointment) of at least $100,000,000.
In the event that a vacancy in the position of Trustee continues for sixty days,
a successor Trustee may be appointed by any State or Federal District Court
having jurisdiction in Tarrant County, Texas, upon the application of Grantor or
any Unitholder, and in the event any such application is filed, such court may
appoint a temporary trustee at any time after such application is filed, which
shall, pending the final
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appointment of a Trustee, have such powers and duties as the court appointing
such temporary trustee shall provide in its order of appointment, consistent
with the provisions of this Indenture.
Immediately upon the appointment of any successor Trustee, all rights,
titles, duties, powers and authority of the predecessor Trustee hereunder shall
be vested in and undertaken by the successor Trustee which shall be entitled to
receive from the predecessor Trustee all of the Trust Estate held by it
hereunder and all records and files in connection therewith. Any resigning or
removed Trustee shall account to its successor for its administration of the
Trust. No successor Trustee shall be obligated to examine or seek alteration of
any account of any preceding Trustee, nor shall any successor Trustee be liable
personally for failing to do so or for any act or omission of any preceding
Trustee. The preceding sentence shall not prevent any successor Trustee or
anyone else from taking any action otherwise permissible in connection with any
such account.
Section 6.09. Laws of Other Jurisdictions. If, notwithstanding the other
provisions of this Indenture, the laws of jurisdictions other than Texas (each
being referred to below as "such jurisdiction") apply to the administration of
properties under this Indenture, the following provisions shall apply. If it is
necessary or advisable for a trustee to serve in such jurisdiction and if the
Trustee is disqualified from serving in such jurisdiction or for any other
reason fails or ceases to serve there, an ancillary trustee meeting the
requirements set forth in the third sentence of Section 6.08 shall be designated
in writing by the Trustee. To the extent permitted under the laws of such
jurisdiction, the Trustee may remove the ancillary trustee in such jurisdiction,
without cause and without necessity of court proceeding or Unitholder approval,
and may or may not appoint a successor ancillary trustee in such jurisdiction
from time to time. The ancillary trustee serving in such jurisdiction is
requested and authorized, to the extent not prohibited under the laws of such
jurisdiction, to appoint the Trustee to handle the details of administration in
such jurisdiction. The ancillary trustee in such jurisdiction shall have all
rights, powers, discretions, responsibilities and duties as are delegated in
writing by the Trustee, subject to such limitations and directions as shall be
specified by the Trustee in the instrument evidencing such appointment. Any
ancillary trustee in such jurisdiction shall be responsible for all assets with
respect to which such trustee is empowered to act. To the extent the provisions
of this Indenture and Texas law cannot be applicable to the administration in
such jurisdiction, the rights, powers, duties and liabilities of the ancillary
trustee in such jurisdiction shall be the same (or as near the same as permitted
under the laws of such jurisdiction if applicable) as if governed by Texas law.
In all events, the administration in such jurisdiction shall be as free and
independent of court control and supervision as permitted under he laws of such
jurisdiction. Whenever the term "Trustee" is applied in this Indenture to the
administration in such jurisdiction, it shall refer only to the trustee then
serving in such jurisdiction.
Section 6.10. Force Majeure. No party to this Indenture (or its
Affiliates) shall incur any liability to any other party to this Indenture or to
any Unitholder if, by reason of any current or future law or regulation
thereunder of the federal government or any other governmental authority, or by
reason of any act of God, war or other circumstance beyond its control, such
party is prevented or forbidden from doing or performing any act or thing
required by the terms hereof to be done or performed; nor shall any party to
this Indenture incur any liability to any other party to this Indenture or any
Unitholder by reason of any nonperformance or delay caused as aforesaid in the
performance of any act or thing required by the terms hereof to be done or
performed, or by reason of any exercise of, or failure to exercise, any
discretion provided for herein caused as set forth above.
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ARTICLE VII. COMPENSATION OF THE TRUSTEE
Section 7.01. Compensation of Trustee. The Trustee shall receive
compensation for its services as Trustee hereunder and as transfer agent as set
forth in Schedule 2 attached hereto.
Section 7.02. Expenses. The reasonable out-of-pocket costs incurred by the
Trustee, including, but not limited to, charges for SEC, NYSE and other fees,
Reserve Reports (including those contemplated by Section 4.08 of each of the
Conveyances), the audit contemplated by Section 4.07 of each of the Conveyances,
long distance telephone calls, overtime necessitated by rush orders, travel,
legal, accounting and other professional services, printing, stationery,
binders, envelopes, ledger sheets, transfer sheets, checks, Certificate list
sheets, postage and insurance will be reimbursed to the Trustee at actual cost.
Section 7.03. Other Services. The Trustee shall be reimbursed for actual
reasonable expenditures made on account of any unusual duties in connection with
matters pertaining to the Trust. In the event of litigation involving the Trust,
audits or inspection of the records of the Trust pertaining to the transactions
affecting the Trust or any other unusual or extraordinary services rendered in
connection with the administration of the Trust, Trustee shall be entitled to
receive reasonable compensation for the services rendered; provided, however,
the Trustee shall not be entitled to reimbursement or compensation for services
that unreasonably duplicate services provided by or through Grantor.
Section 7.04. Source of Funds. All compensation, reimbursements and other
charges owing to the Trustee will be payable by the Trust out of the Trust
Estate.
ARTICLE VIII. MEETINGS OF UNITHOLDERS
Section 8.01. Purpose of Meetings. A meeting of the Unitholders may be
called at any time and from time to time pursuant to the provisions of this
Article VIII to transact any matter that the Unitholders may be authorized to
transact.
Section 8.02. Call and Notice of Meetings. Any such meeting of the
Unitholders may be called by the Trustee in its discretion and will be called by
the Trustee at the written request of Grantor or Unitholders owning of record
not less than 15% in number of the Units then outstanding. All such meetings
shall be held at such time and at such place in Tarrant County, Texas, as the
notice of any such meeting may designate. Except as may otherwise be required by
applicable law or by any securities exchange or market system on which the Units
are admitted for trading, written notice of every meeting of the Unitholders
signed by the Trustee setting forth the time and place of the meeting and in
general terms the matters proposed to be acted upon at such meeting shall be
given in person or by mail not more than sixty nor less than twenty days before
such meeting is to be held to all of the Unitholders of record as of a record
date set by the Trustee (the "Record Date Unitholders") which shall be not more
than sixty days before the date of such mailing. No matter other than that
stated in the notice shall be acted upon at any meeting. If such notice is
given to any Unitholder by mail, it shall be directed to him at his last address
as shown by the ownership ledger of the Trustee and shall be deemed duly given
when so addressed and deposited in the United States mail, postage paid. Only
Record Date Unitholders shall be entitled to notice of and to exercise rights at
or in connection with the meeting. Any action required
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by this Indenture to be taken at a meeting of the Unitholders, or any action
which may be taken at a meeting of the Unitholders, may not be taken and shall
not be effective without an actual meeting of the Unitholders, prior written
notice to the Unitholders thereof and a vote by the Unitholders with respect
thereto.
Section 8.03. Voting. Each Record Date Unitholder shall be entitled to one
vote for each Unit owned by him, and any Record Date Unitholder may vote in
person or by duly executed written proxy. At any such meeting the presence in
person or by proxy of Record Date Unitholders holding a majority of the Units
outstanding at the record date shall constitute a quorum, and, except as
otherwise specifically provided herein, any matter shall be deemed to have been
approved by the Unitholders if it is approved by the vote of a majority in
interest of such Record Date Unitholders constituting a quorum, although less
than a majority of all of the Units at the time outstanding, except that the
affirmative vote by the Record Date Unitholders of 80% or more of all the Units
outstanding at the record date shall be required to:
(a) approve or authorize any sale of all or any material part of the
assets of the Trust (excluding sales or dispositions authorized under
Sections 3.02(b), 3.05, 3.09 or 9.03), or
(b) terminate the Trust pursuant to Section 9.02(c), or
(c) approve any amendment to or affecting this Indenture, except that
amendments prohibited by Section 10.01 shall not be effected in any event
and amendments authorized by Section 10.02 shall not require the approval
of any Unitholder.
Section 8.04. Conduct of Meetings. The Trustee may make such reasonable
regulations consistent with the provisions hereof as it may deem advisable for
any meeting of the Unitholders, including regulations covering the closing of
the transfer books of the Trustee for purposes of determining Unitholders
entitled to notice of or to vote at any meeting, the appointment of proxies, the
appointment and duties of inspectors of votes, the submission and examination of
proxies, Certificates and other evidence of the right to vote, the preparation
and use at the meeting of a list authenticated by or on behalf of the Trustee of
the Unitholders entitled to vote at the meeting and such other matters
concerning the calling and conduct of the meeting as it shall deem advisable.
Section 8.05. Unitholder Proposals. In the event a meeting of Unitholders
is called for any purpose at the request of any Unitholder or Unitholders
pursuant to the provisions of this Article VIII, the Unitholder or Unitholders
requesting such meeting shall be required to prepare and file a proxy statement
with the SEC and the NYSE regarding such meeting in satisfaction of all
applicable SEC and NYSE rules and regulations and at the expense of such
requesting Unitholder or Unitholders. The Unitholder or Unitholders requesting
such meeting shall bear the expense of distributing to Unitholders the notice of
meeting and the proxy statement related thereto. The Trustee shall cooperate in
the preparation of any such proxy statement and any related materials and shall
provide such information for inclusion therein as and to the extent reasonably
necessary at the expense of the Trust.
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ARTICLE IX. DURATION, REVOCATION AND TERMINATION OF TRUST
Section 9.01. Revocation. The Trust is and shall be irrevocable and
Grantor, as such, retains no power to alter, amend or terminate the Trust. The
Trust shall be terminable only as provided in Section 9.02, and shall continue
until so terminated.
Section 9.02. Termination. The Trust shall terminate upon the first to
occur of the following events:
(a) the disposition of all of the Royalties pursuant to the terms of
this Indenture;
(b) at such time as the aggregate Gross Proceeds (as defined in the
Conveyances) with respect to the Subject Interests for each of two
successive years after the year 1999 is less than $1,000,000 per year;
(c) a vote in favor of termination by the Unitholders present or
represented at a meeting held in accordance with the requirements of
Article VIII; or
(d) the expiration of twenty-one years after the death of the last
survivor of the lawful descendants of any degree of the signers of the
Declaration of Independence in being on the date of execution hereof.
Section 9.03. Disposition and Distribution of Properties. For the purpose
of liquidating and winding up the affairs of the Trust at its termination, the
Trustee shall continue to act as such and exercise each power until its duties
have been fully performed and the Trust Estate finally distributed. Upon the
termination of the Trust, the Trustee shall sell for cash in one or more sales
all the properties other than cash then constituting the Trust Estate. The
Trustee shall as promptly as possible distribute the proceeds of any such sales
and any other cash in the Trust Estate according to the respective interests and
rights of the Unitholders, after paying, satisfying and discharging all of the
liabilities of the Trust, or, when necessary, setting up reserves in such
amounts as the Trustee in its discretion deems appropriate for contingent
liabilities. In the event that any property which the Trustee is required to
sell is not sold by the Trustee within two years after the termination of the
Trust, the Trustee shall cause such property to be sold at public auction to the
highest cash bidder. Notice of such sale by auction shall be mailed at least
thirty days prior to such sale to each Unitholder of record as of a date set by
the Trustee at such Unitholder's address as it appears upon the books of the
Trustee. Grantor may purchase all or any portion of the Trust Estate properties
at any sale pursuant to this Section. The Trustee shall not be required to
obtain approval of the Unitholders prior to selling property pursuant to this
Section 9.03. In connection with sales pursuant to this Section 9.03, the
Trustee may accept any offer to purchase the properties constituting the Trust
Estate that it deems reasonable in its discretion and shall have no liability in
connection with any such sales except under the circumstances described in
Section 6.01(a). The Trustee may engage the services of one or more investment
advisers or other parties deemed by the Trustee to be qualified as experts on
such matters to assist with such sales and shall be entitled to rely on the
advice f such professionals as contemplated by Section 12.02. Upon making final
distribution to the Unitholders, the Trustee shall be under no further liability
except as provided in Section 6.01(b).
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ARTICLE X. AMENDMENTS
Section 10.01. Prohibited. After the Closing, no amendment may be made to
any provision of the Indenture which would
(a) alter the purposes of the Trust or permit the Trustee to engage in
any business or investment activities or any activity substantially
different from that specified herein;
(b) alter the rights of the Unitholders vis-a-vis each other; or
(c) permit the Trustee to distribute the Royalties in kind either
during the continuation of the Trust or during the period of liquidation or
winding up under Section 9.03.
Section 10.02. Permitted. Prior to the Closing, this Indenture may be
amended by Grantor and the Trustee, jointly, and no party shall have any
liability to any Unitholder therefor, including for any amendment that increases
or decreases any right, benefit or liability of any present or future
Unitholder. After the Closing, Grantor and the Trustee may, jointly, from time
to time, supplement or amend this Indenture, without the approval of the
Unitholders, in order to cure any ambiguity, to correct or supplement any
provision herein which may be defective or inconsistent with any other provision
hereof, or to change the name of the Trust, provided that such supplement or
amendment does not adversely affect the interests of the Unitholders. All other
amendments to the provisions of the Indenture shall be made only by a vote of
the Unitholders present or represented at a meeting held in accordance with the
requirements of Article VIII. The Trustee shall approve all amendments permitted
under this Section 10.02, provided all prior conditions are satisfied and there
is no adverse effect on the Trust or the Trustee. In connection with any
request by Grantor to supplement or amend this Indenture to cure any ambiguity,
defect or inconsistency, Grantor shall provide to the Trustee, and it shall be a
condition to the Trustee's approval thereof, an officer's certificate and an
opinion of counsel deemed satisfactory to the Trustee to support a determination
of the existence of an ambiguity, defect or inconsistency that may properly be
cured under this Section 10.01 and applicable law. The Trustee shall be
entitled to rely on such officers' certificate and opinion, and such officers'
certificate and opinion shall be full and complete authorization and protection
in respect of any action taken or suffered by it hereunder in good faith and in
accordance therewith.
ARTICLE XI. ARBITRATION
THE PARTIES TO THIS INDENTURE AGREE THAT ANY DISPUTE, CONTROVERSY OR CLAIM
THAT MAY ARISE BETWEEN OR AMONG GRANTOR (ON THE ONE HAND) AND THE TRUST OR THE
TRUSTEE (ON THE OTHER HAND) IN CONNECTION WITH OR OTHERWISE RELATING TO THIS
INDENTURE OR THE CONVEYANCES OR THE APPLICATION, IMPLEMENTATION, VALIDITY OR
BREACH OF THIS INDENTURE OR THE CONVEYANCES OR ANY PROVISION OF THIS INDENTURE
OR THE CONVEYANCES (INCLUDING, WITHOUT LIMITATION, CLAIMS BASED ON CONTRACT,
TORT OR STATUTE), SHALL BE FINALLY, CONCLUSIVELY AND EXCLUSIVELY SETTLED BY
BINDING ARBITRATION IN FORT WORTH, TEXAS IN ACCORDANCE WITH THE COMMERCIAL
ARBITRATION RULES (THE "RULES") OF THE AMERICAN ARBITRATION ASSOCIATION OR ANY
SUCCESSOR THERETO ("AAA") THEN IN EFFECT. THE PARTIES
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TO THIS INDENTURE (AND ON BEHALF OF THE TRUST) HEREBY EXPRESSLY WAIVE THEIR
RIGHT TO SEEK REMEDIES IN COURT, INCLUDING, WITHOUT LIMITATION, THE RIGHT TO
TRIAL BY JURY, WITH RESPECT TO ANY MATTER SUBJECT TO ARBITRATION PURSUANT TO
THIS ARTICLE XI. ANY PARTY TO THIS INDENTURE MAY BRING AN ACTION, INCLUDING,
WITHOUT LIMITATION, A SUMMARY OR EXPEDITED PROCEEDING, IN ANY COURT HAVING
JURISDICTION, TO COMPEL ARBITRATION OF ANY DISPUTE, CONTROVERSY OR CLAIM TO
WHICH THIS ARTICLE XI APPLIES. EXCEPT WITH RESPECT TO THE FOLLOWING PROVISIONS
(THE "SPECIAL PROVISIONS") WHICH SHALL APPLY WITH RESPECT TO ANY ARBITRATION
PURSUANT TO THIS ARTICLE XI, THE INITIATION AND CONDUCT OF ARBITRATION SHALL BE
AS SET FORTH IN THE RULES, WHICH RULES ARE INCORPORATED IN THIS INDENTURE BY
REFERENCE WITH THE SAME EFFECT AS IF THEY WERE SET FORTH IN THIS INDENTURE.
(a) In the event of any inconsistency between the Rules and the
Special Provisions, the Special Provisions shall control. References in
the Rules to a sole arbitrator shall be deemed to refer to the tribunal of
arbitrators provided for under subparagraph (c) below in this Article XI.
(b) The arbitration shall be administered by AAA.
(c) The arbitration shall be conducted by a tribunal of three
arbitrators. Within ten days after arbitration is initiated pursuant to
the Rules, the initiating party or parties (the "Claimant") shall send
written notice to the other party or parties (the "Respondent"), with a
copy to the Dallas office of AAA, designating the first arbitrator (who
shall not be a representative or agent of any party but may or may not be
an AAA panel member and, in any case, shall be reasonably believed by the
Claimant to possess the requisite experience, education and expertise in
respect of the matters to which the claim relates to enable such person to
completely perform arbitral duties). Within ten days after receipt of such
notice, the Respondent shall send written notice to the Claimant, with a
copy to the Dallas office of AAA and to the first arbitrator, designating
the second arbitrator (who shall not be a representative or agent of any
party, but may or may not be an AAA panel member and, in any case, shall be
reasonably believed by the Respondent to possess the requisite experience,
education and expertise in respect of the matters to which the claim
relates to enable such person to competently perform arbitral duties).
Within ten days after such notice from the Respondent is received by the
Claimant, the Respondent and the Claimant shall cause their respective
designated arbitrators to select any mutually agreeable AAA panel member as
the third arbitrator. If the respective designated arbitrators of the
Respondent and the Claimant cannot so agree within said ten day period,
then the third arbitrator will be determined pursuant to the Rules. For
purposes of this Article XI, Grantor (on the one hand) and the Trust and
the Trustee (on the other hand) shall each be entitled to the selection of
one arbitrator. Prior to commencement of the arbitration proceeding, each
arbitrator shall have provided the parties with a resume outlining such
arbitrator's background and qualifications and shall certify that such
arbitrator is not a representative or agent of any of the parties. If any
arbitrator shall die, fail to act, resign, become disqualified or otherwise
cease to act, then the arbitration proceeding shall be delayed
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for fifteen days and the party by or on behalf of whom such arbitrator was
appointed shall be entitled to appoint a substitute arbitrator (meeting the
qualifications set forth in this Article XI) within such fifteen day
period; provided, however, that if the party by or on behalf of whom such
arbitrator was appointed shall fail to appoint a substitute arbitrator
within such fifteen day period, the substitute arbitrator shall be a
neutral arbitrator appointed by the AAA arbitrator within fifteen days
thereafter.
(d) All arbitration hearings shall be commenced within one hundred
twenty days after arbitration is initiated pursuant to the Rules, unless,
upon a showing of good cause by a party to the arbitration, the tribunal of
arbitrators permits the extension of the commencement of such hearing;
provided, however, that any such extension shall not be longer than sixty
days.
(e) All claims presented for arbitration shall be particularly
identified and the parties to the arbitration shall each prepare a
statement of their position with recommended courses of action. These
statements of position and recommended courses of action shall be submitted
to the tribunal of arbitrators chosen as provided hereinabove for binding
decision. The tribunal of arbitrators shall not be empowered to make
decisions beyond the scope of the position papers.
(f) The arbitration proceeding will be governed by the substantive
laws of the State of Texas and will be conducted in accordance with such
procedures as shall be fixed for such purpose by the tribunal of
arbitrators, except that (i) discovery in connection with any arbitration
proceeding shall be conducted in accordance with the Federal Rules of Civil
Procedure and applicable case law, (ii) the tribunal of arbitrators shall
have the power to compel discovery and (iii) unless the parties otherwise
agree and except as may be provided in this Article XI, the arbitration
shall be governed by the United States Arbitration Act, 9 U.S.C. (S)(S)
1-16, to the exclusion of any provision of state law or other applicable
law or procedure inconsistent therewith or which would produce a different
result. The parties shall preserve their right to assert and to avail
themselves of the attorney-client and attorney-work-product privileges, and
any other privileges to which they may be entitled pursuant to applicable
law. No party to the arbitration or any arbitrator may compel or require
mediation and/or settlement conferences without the prior written consent
of all such parties and the tribunal of arbitrators.
(g) The tribunal of arbitrators shall make an arbitration award as
soon as possible after the later of the close of evidence or the submission
of final briefs, and in all cases the award shall be made not later than
thirty days following submission of the matter. The finding and decision
of a majority of the arbitrators shall be final and shall be binding upon
the parties. Judgment upon the arbitration award or decision may be entered
in any court having jurisdiction thereof or application may be made to any
such court for a judicial acceptance of the award and an order of
enforcement, as the case may be. The tribunal of arbitrators shall have
the authority to assess liability for pre-award and post-award interest on
the claims, attorneys' fees, expert witness fees and all other expenses of
arbitration as such arbitrators shall deem appropriate based on the outcome
of the claims arbitrated. Unless otherwise agreed by the parties to the
arbitration in writing, the arbitration award shall include findings of
fact and conclusions of law.
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(h) Nothing in this Article XI shall be deemed to (i) limit the
applicability of any otherwise applicable statute of limitations or repose
or any waivers contained in this Indenture, (ii) constitute a waiver by any
party hereto of the protections afforded by 12 U.S.C. (S) 91 or any
successor statute thereto or any substantially equivalent state law, or
(iii) restrict the right of the Trustee to make application to any state or
federal district court having jurisdiction in Tarrant County, Texas, to
appoint a successor Trustee or to request instructions with regard to any
provision in this Indenture when the Trustee is unsure of its obligations
thereunder.
(i) This Article XI shall preclude participation by the Trust in any
class action brought against Grantor by any Person who is not a Unitholder
and the Trustee shall opt out of any such class action in which the Trust
is a purported class member.
ARTICLE XII. MISCELLANEOUS
Section 12.01. Inspection of Trustee's Books. Each Unitholder and such
Unitholder's duly authorized agents, attorneys and auditors shall have the
right, at such Unitholder's own expense and during reasonable business hours, to
examine and inspect the records of the Trust and the Trustee, including lists of
Unitholders, for any proper purpose in reference thereto. For purposes of
determining whether a purpose asserted by a Unitholder is a "proper purpose,"
the Trustee, in the absence of controlling precedent applicable to trusts
organized under the Texas Trust Code, may rely on any reasonably analogous
precedent, including laws and court decisions relating to corporations of the
State of Texas or other jurisdictions.
Section 12.02. Trustee's Employment of Experts. The Trustee may, but shall
not be required to, consult with counsel, who may be its own counsel,
accountants, geologists, engineers and other parties deemed by the Trustee to be
qualified as experts on the matters submitted to them, and the opinion or advice
of any such parties on any matter submitted to them by the Trustee shall be full
and complete authorization and protection in respect of any action taken or
suffered by it hereunder in good faith and in accordance with the opinion of any
such party. The Trustee is authorized to make payments of all reasonable and
necessary fees billed by third parties for services or expenses thus incurred
out of the Trust Estate.
Section 12.03. Merger or Consolidation of Trustee. Neither a change of
name of the Trustee nor any merger or consolidation of it or of its corporate
powers with another bank or with a trust company shall affect its right or
capacity to act hereunder. Upon any merger, consolidation, sale of assets or
other transaction involving the Trustee in which the Trustee is not the
surviving entity, the surviving entity in such transaction shall automatically
become Trustee of the Trust and succeed to all rights, titles, duties, powers
and authority of the predecessor Trustee hereunder, without the requirement of
Unitholder approval or any other action, provided such surviving entity has
succeeded to the rights and obligations of the predecessor Trustee in accordance
with applicable law and is a bank or trust company having capital, surplus and
undivided profits (as of the end of its last fiscal year prior to the
consummation of such transaction) of at least $100,000,000.
Section 12.04. Filing of this Indenture. Neither this Indenture nor any
executed copy hereof need be filed in any county in which any of the Trust
Estate is located, but the same may be filed for
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record in any county by the Trustee. In order to avoid the necessity of filing
this Indenture for record, the Trustee agrees that for the purpose of vesting
the record title to the Royalties in any successor Trustee, the succeeded
Trustee will, upon appointment of any successor Trustee, execute and deliver to
such successor Trustee appropriate assignments or conveyances.
Section 12.05. Severability. If any provision of this Indenture or the
application thereof to any Person or circumstances shall be finally determined
by a court of proper jurisdiction to be illegal, invalid or unenforceable to any
extent, the remainder of this Indenture or the application of such provision to
Persons or circumstances, other than those as to which it is held illegal,
invalid or unenforceable, shall not be affected thereby, and every provision of
this Indenture shall be valid and enforced to the fullest extent permitted by
law.
Section 12.06. Notices. Any and all notices or demands permitted or
required to be given under this Indenture shall be in writing and shall be
validly given or made if (a) personally delivered, (b) delivered and confirmed
by telecopier or like instantaneous transmission service, or by Federal Express
or other overnight courier delivery service, which shall be effective as of
confirmation of receipt by the courier at the address for notice hereinafter
stated, (c) solely in the case of notice to any Unitholder, by press release in
a nationally recognized and distributed media, or (d) deposited in the United
States mail, first class, postage prepaid, certified or registered, return
receipt requested, addressed as follows:
If to the Trustee, to:
NationsBank, N.A.
901 Main Street, 17th Floor
Dallas, Texas 75202
Attention: Ron E. Hooper, Vice President
Telecopier No.: (214) 508-2431
If to Grantor, to:
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, Texas 76102-6298
Attention: Corporate Secretary
Telecopier No. (817) 870-1671
If to a Unitholder, to:
the Unitholder
at its last address as shown on the
ownership records maintained by the Trustee.
Notice which is mailed in the manner specified shall be conclusively deemed
given three days after the date postmarked or upon receipt, whichever is sooner.
Any party to this Indenture may change its address for the purpose of receiving
notices or demands by notice given as provided in this Section 12.06.
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Section 12.07. Counterparts. This Indenture may be executed in a number of
counterparts, each of which shall constitute an original, but such counterparts
shall together constitute but one and the same instrument.
Section 12.08. Successors. This Indenture shall inure to the benefit of
and be binding upon the parties hereto and their respective successors and
assigns.
Section 12.09. Amended and Restated Indenture. This Amended and Restated
Indenture amends and restates fully the Indenture previously executed by Grantor
and the Bank and such previously executed Indenture is fully replaced and
superseded by this Indenture.
IN WITNESS WHEREOF, Grantor and Trustee have caused this Indenture to be
duly executed the day and year first above written at Fort Worth, Tarrant
County, Texas.
CROSS TIMBERS OIL COMPANY
ATTEST:
By:
- ------------------------------ ------------------------------
Name: Frank G. McDonald Name: Bennie G. Kniffen
Title: Assistant Secretary Title: Senior Vice President
- GRANTOR -
ATTEST: NATIONSBANK, N.A.
By:
- ------------------------------ ------------------------------
Name: Don A. Yuchs Name: Ron E. Hooper
Title: Assistant Vice President Title: Vice President
- TRUSTEE -
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SCHEDULE 2
TRUSTEE COMPENSATION
A. Administrative Fee
1. For all administrative and other services to be provided by the
Trustee under the Indenture including, but not limited to, costs of
Trustee's personnel, the Trustee will be paid, from the Trust Estate,
the sum of $35,000 per year, with such fee to be paid in equal monthly
installments.
2. The Administrative Fee provided above will be adjusted annually,
beginning April 1, 2000. The adjustment shall be computed by
multiplying the current Administrative Fee by the percentage increase
or decrease in the average weekly earnings of Crude Petroleum and Gas
Production Workers for the last calendar year compared to the calendar
year preceding as shown by the index of average weekly earnings of
Crude Petroleum and Gas Production Workers as published by the United
States Department of Labor, Bureau of Labor Statistics. The adjusted
Administrative Fee shall be the Administrative Fee currently in use,
plus or minus the computed adjustment.
B. Termination Fee
Upon termination of the Trust, the Trustee shall be paid a Termination Fee
of $15,000.
C. The fees provided above are in addition to out-of-pocket cost
reimbursements permitted under the Indenture.
<PAGE>
EXHIBIT 23.1
INDEPENDENT PUBLIC ACCOUNTANTS' CONSENT
As independent public accountants, we hereby consent to the use of our
reports in this Registration Statement Amendment No. 3 on Form S-1 of Hugoton
Royalty Trust and on Form S-1 of Cross Timbers Oil Company (the Company),
Registration No. 333-68441, dated February 18, 1999, March 15, 1999, March 12,
1999, February 15, 1999 and February 11, 1998, and to all references to our
firm included in or made a part of this Registration Statement.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
April 8, 1999
