SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 2 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)
Texas Delaware
(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
--------------
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Title of Each Class of Proposed Maximum Amount of
Securities to Be Registered Aggregate Offering Price(1) Registration Fee(2)
------------------------------------------------------------------------------
Units of Beneficial
Interest.................... $172,500,000 $47,955
------------------------------------------------------------------------------
------------------------------------------------------------------------------
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(1) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).
(2) 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.
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
+ + +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 March 16, 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 11 to read about certain information you should consider before purchasing trust units.
Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.
Per
Trust
Unit Total
----- -----
Initial public offering price....................................... $ $
Underwriting discount............................................... $ $
Proceeds, before expenses, to Cross Timbers......................... $ $
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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.
[MAP OF UNDERLYING PROPERTIES APPEARS HERE]
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.
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.
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.
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.
Cross Timbers may face conflicts of interest in allocating its resources between additional development of the underlying properties and development of other oil and natural gas properties that it now owns or may own in the future. Cross Timbers allocates resources for development based on expected rates of return. The underlying properties have historically provided attractive rates of return on development projects compared to Cross Timbers' other properties, and are expected to continue to do so in the future.
Substantial Operating Margins
The underlying properties have historically generated substantial operating margins. Production expenses, production and property taxes, transportation costs and overhead on the underlying properties averaged $0.67 per Mcfe during 1998. During the same period, the sales price for oil and natural gas produced from the underlying properties averaged $1.92 per Mcfe, providing an operating margin of $1.25 per Mcfe.
Control of Natural Gas Gathering Systems
Cross Timbers and its affiliates operate natural gas gathering systems for approximately 70% of the production from the underlying properties. This allows Cross Timbers to manage gathering operations to maintain optimum natural gas production.
Proved Reserves
Estimated proved reserves of the underlying properties are approximately 95% natural gas and 5% oil, based on the reserve report. The following table provides, as of December 31, 1998, estimated proved oil and natural gas reserves, and undiscounted and discounted estimated future net revenues, for the underlying properties and the net profits interests. Proved reserves in the table are based on oil and natural gas prices realized by Cross Timbers as of December 31, 1998, which were $11.24 per Bbl of oil and $2.01 per Mcf of natural gas. The amounts of estimated future net revenues from proved reserves shown in the table are before income taxes. Discounted future net revenues are based on a discount rate of 10%, which is the rate required by the Securities and Exchange Commission. Reserve estimates are subject to revision.
Proved Reserves
---------------------------
Estimated Future
Net Revenues from
Gas Proved Reserves
Gas Oil Equivalents ------------------------
(MMcf) (MBbls) (MMcfe) Undiscounted Discounted
------- ------- ----------- ------------ -----------
(in thousands, except
per Unit data)
Underlying properties
(100%):
Anadarko Basin......... 174,433 3,621 196,159 $258,416 $150,711
Green River Basin...... 178,970 270 180,590 242,897 104,193
Hugoton Area........... 161,670 139 162,504 173,205 92,273
------- ----- ------- -------- --------
Total................ 515,073 4,030 539,253 $674,518 $347,177
======= ===== ======= ======== ========
Underlying properties
(80%)................... 412,058 3,224 431,402 $539,615 $277,742
Net profits interests
(a)..................... 282,297 2,193 295,455 $539,615 $277,742
Per trust unit........... -- -- -- $ 13.49 $ 6.94
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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.
1996 1997 1998
---------- ---------- ----------
(in thousands, except per unit data)
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
========== ========== ==========
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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."
(in thousands,
except per unit data)
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
=======
Cash Distribution
as a Percentage of
Amount $9.50 Trust Unit Price
------ ----------------------
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%
=======
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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
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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.
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 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.
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 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.
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:
. payments to Cross Timbers for production and development costs to operate wells;
. payments to Cross Timbers affiliates for marketing, processing and transportation services; and
. overhead fees to operate the underlying properties, which include accounting and other administrative functions.
In addition to providing services, Cross Timbers affiliates purchase production from the underlying properties. Approximately two-thirds of 1998 oil and natural gas sales from the underlying properties were made to Cross Timbers affiliates.
Cross Timbers believes that the terms of these contracts are competitive with those that could be obtained from unrelated third parties. Cross Timbers is permitted under the conveyance agreements creating the net profits interests to enter into new 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.
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;
. Cross Timbers could continue to operate an underlying property and earn an overhead fee even though abandonment of the property might be more beneficial to trust unitholders; and
. Cross Timbers could decide to sell or abandon some or all of the underlying properties, and that decision may not be in the best interests of the trust unitholders.
Except for specified matters that require approval of the trust unitholders described in "Description of the Trust Indenture," the documents governing the trust do not provide a mechanism for resolving these conflicting interests.
Trust Unitholders Will Have Limited Voting Rights
Your voting rights as a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re- election of the trustee.
Additionally, trust unitholders have no voting rights in Cross Timbers and therefore will have no ability to influence its operations of the underlying properties.
Trust Unitholders Will Have Limited Ability to Enforce Rights
The trust indenture 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.
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."
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.
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 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.
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."
(in thousands,
except per
unit data)
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
=======
Cash Distribution
as a Percentage of
Amount $9.50 Trust Unit Price
------ ----------------------
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%
=======
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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
Posted Oil Price Wellhead Gas Price
per Bbl per Mcf
---------------- --------------------------
$1.50 $2.00 $2.50 $3.00
----- ----- ----- -----
$10.00........................................... $0.57 $0.95 $1.32 $1.70
15.00........................................... 0.61 0.98 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
Posted Oil Price Wellhead Gas Price
per Bbl per Mcf
---------------- --------------------------
$1.50 $2.00 $2.50 $3.00
----- ----- ----- -----
$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
Posted Oil Price Wellhead Gas Price
per Bbl per Mcf
----------------- --------------------------
$1.50 $2.00 $2.50 $3.00
----- ----- ----- -----
$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
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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.
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."
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.
1996 1997 1998
---------- ---------- ----------
(in thousands, except per unit data)
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
========== ========== ==========
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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.
Producing Acreage and Well Counts
For the following data, "gross" refers to the total wells or acres in which Cross Timbers owns a working interest and "net" refers to gross wells or acres multiplied by the percentage working interest owned by Cross Timbers. Although many of Cross Timbers' wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production.
The underlying properties are interests in developed properties located primarily in natural gas producing regions of Kansas, Oklahoma and Wyoming. The following is a summary of the approximate producing acreage of the underlying properties at December 31, 1998. Undeveloped acreage is not significant.
Gross Net
------- -------
Hugoton Area.................................................... 217,590 200,390
Anadarko Basin.................................................. 152,042 113,946
Green River Basin............................................... 42,654 28,841
------- -------
Total........................................................... 412,286 343,177
======= =======
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The following is a summary of the producing wells on the underlying properties as of December 31, 1998:
Operated Non-Operated
Wells Wells Total
------------- ------------- -------------
Gross Net Gross Net Gross Net
----- ------- ------------- ----- -------
Natural gas........................... 1,005 913.5 253 59.8 1,258 973.3
Oil................................... 140 124.1 7 1.5 147 125.6
----- ------- ----- ------ ----- -------
Total................................. 1,145 1,037.6 260 61.3 1,405 1,098.9
===== ======= ===== ====== ===== =======
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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.
Year Ended December 31
--------------------------------
1996 1997 1998
---------- ---------- ----------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
Completed:
Natural gas wells (a)......................... 39 30.9 79 68.8 64 43.7
Oil wells..................................... 2 2.0 1 1.0 -- --
Non-productive................................. -- -- 2 1.5 1 1.0
--- ---- --- ---- --- ----
Total (b)...................................... 41 32.9 82 71.3 65 44.7
=== ==== === ==== === ====
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(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.
Oil and Natural Gas Sales Prices and Production Costs
The following table shows the average sales prices per Bbl of oil and Mcf of natural gas produced and the production costs, production and property taxes and transportation costs per Mcfe for the underlying properties:
Year Ended December 31
-----------------------
1996 1997 1998
------- ------- -------
Sales prices:
Natural gas (per Mcf)................................ $ 1.84 $ 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
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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;
. 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.
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
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.
Proved Reserves
The following table shows proved reserves, proved developed reserves, future net revenues and discounted present value of future net revenues at December 31, 1998 for the underlying properties, 80% of the underlying properties and the net profits interests.
80% of Net
Underlying Underlying Profits
Properties Properties Interests
---------- ---------- ---------
(in thousands)
Proved reserves
Natural gas (Mcf)............................ 515,073 412,058 282,297
Oil (Bbls)................................... 4,030 3,224 2,193
Natural gas Equivalents (Mcfe)............... 539,253 431,402 295,455
Proved developed reserves
Natural gas (Mcf)............................ 435,328 348,262 249,215
Oil (Bbls)................................... 3,368 2,694 1,934
Natural gas Equivalents (Mcfe)............... 455,536 364,429 260,819
Future net revenues............................ $674,518 $539,615 $539,615
Present value discounted at 10% per annum...... $347,177 $277,742 $277,742
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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.
Underlying Properties
----------------------------
Gas
Gas Oil Equivalents
(Mcf) (Bbls) (Mcfe)
------- ------ -----------
(in thousands)
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
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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.
80% of Net
Underlying Underlying Profits
Properties Properties Interests
---------- ---------- ---------
(in thousands)
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
========== ======== ========
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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,
the spacing and operation of wells and the prevention of waste of oil and gas resources. States may regulate rates of production and may establish maximum daily production allowables from both oil and gas wells based on market demand or resource conservation, or both.
Other Regulation. The Mineral Management Service of the United States Department of Interior is evaluating existing methods of settling royalties on federal and Native American oil and gas leases. A portion of the underlying properties, primarily those located in Wyoming, involve federal leases. Although the final rules could cause an increase in the federal royalties to be paid on these properties and, correspondingly, decrease the revenue to Cross Timbers and the trust from these properties, Cross Timbers does not believe that the proposed rule changes will have a significant detrimental effect on the distributions from the trust.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. Cross Timbers does not believe that compliance with these laws will have a material adverse effect upon the trust unitholders.
Title to Properties
Cross Timbers believes that its title to the underlying properties is, and the trust's title to the net profits interest will be, good and defensible in accordance with standards generally accepted in the oil and gas industry.
The underlying properties are typically subject, in one degree or another, to one or more of the following:
. royalties, overriding royalties and other burdens, under oil and gas leases;
. contractual obligations, including, in some cases, development obligations, arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;
. liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements;
. pooling, unitization and commutation agreements, declarations and orders; and
. easements, restrictions, rights-of-way and other matters that commonly affect property.
To the extent that these burdens and obligations affect Cross Timbers' rights to production and the value of production from the underlying properties, they have been taken into account in calculating the trust's interests and in estimating the size and the value of the reserves attributable to the net profits interests. Cross Timbers believes that the burdens and obligations affecting the underlying properties and the net profits interests are conventional in the industry for similar properties. Cross Timbers also believes that the burdens and obligations do not in the aggregate materially interfere with the use of the underlying properties and will not materially adversely affect the value of the net profits interests.
Although the matter is not entirely free from doubt, Cross Timbers believes that the net profits interests should constitute real property interests under Oklahoma and Wyoming law, but not under Kansas law. Cross Timbers will record the conveyances in the appropriate real property records of Kansas, Oklahoma and Wyoming, the states in which the underlying properties are located. If during the term of the trust Cross Timbers should become a debtor in a bankruptcy proceeding, it is not entirely clear that the net profits interests would be treated as real property interests under the laws of Oklahoma and Wyoming, and they would not be so treated under Kansas law. If a determination were made in a bankruptcy proceeding that a net profits interest did not constitute a real property
interest under applicable state law, it could be designated an executory contract. An executory contract is a term used, but not defined, in the federal bankruptcy code to refer to a contract under which the obligations of both the debtor and the other party are so unsatisfied that the failure of either to complete performance would constitute a material breach excusing performance by the other. If a net profits interest were designated an executory contract and rejected in the bankruptcy proceeding, Cross Timbers would not be required to perform its obligations under the net profits interest and the trust would seek damages as one of Cross Timbers' unsecured creditors. Although no assurance can be given, Cross Timbers does not believe that the net profits interests should be subject to rejection in a bankruptcy proceeding as executory contracts.
Marketing
A subsidiary of Cross Timbers markets Cross Timbers' natural gas production and the natural gas output of the gathering and processing systems operated by other Cross Timbers subsidiaries. The natural gas is sold on a monthly basis to third parties for the best available price, although Cross Timbers occasionally enters into forward contracts for future deliveries. Oil production is generally marketed at the 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.
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 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 in computing royalties payable for natural gas produced from federal leases and lands owned by Native Americans, Cross Timbers has mismeasured the volume of natural gas and wrongfully analyzed its heating content. The suit, which was brought under the qui tam provisions of the U.S. False Claims Act, seeks treble damages for the unpaid royalties, with interest, civil penalties and an order for Cross Timbers to cease the allegedly improper measuring practices. 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
. 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;
. 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
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;
. 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.
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
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
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.
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.
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
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.
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 is in the best interests of the trust unitholders, constitutes a material part of the trust's assets and holders representing 80% of the outstanding trust units approve the sale.
Upon termination of the trust the trustee must sell the net profits interests. No trust unitholder approval is required.
The trustee will distribute the net proceeds from any sale of the net profits interests to the trust unitholders.
The trustee may require any trust unitholder to dispose of his trust units if an administrative or judicial proceeding seeks to cancel or forfeit any of the property in which the trust holds an interest
because of the nationality or any other status of that trust unitholder. If a trust unitholder fails to dispose of his trust units, the trustee has the right to purchase them and to borrow funds to make that purchase.
The trustee may agree to modifications of the terms of the conveyances or to settle disputes involving the conveyances. The trustee may not agree to modifications or settle disputes involving the royalty part of the conveyances if these actions would change the character of the net profits interests in such a way that 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;
. 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 at the end of the last business day of the month (the "monthly record date") will receive a pro- rata distribution no later than 10 business days after the monthly record date. The first distribution 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
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,
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.
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SELLING TRUST UNITHOLDER
Cross Timbers currently owns 100% of the 40,000,000 outstanding trust units. It is offering 15,000,000 trust units in this offering, or 17,250,000 trust units if the underwriters exercise their over-allotment option in full.
Cross Timbers has reserved $12 million of trust units for issuance in Cross Timbers' 1998 Royalty Trust Option Plan. It has granted options covering all trust units in the plan to its executive officers at an exercise price equal to the public offering price in this offering. The options are exercisable for a period of three years, beginning at the date of grant. Assuming the sale of all trust units offered in this offering and the exercise in full of the underwriters' over-allotment option, after taking into account the trust units reserved for the plan, Cross Timbers will have trust units, or % of the outstanding trust units available for future sale or distribution.
Cross Timbers has announced that it may form additional royalty trusts with other properties. It may exchange trust units for oil and natural gas properties or use them for other corporate purposes.
Prior to this offering there has been no public market for the trust units. Cross Timbers cannot predict the effect on future market prices, if any, of market sales of trust units or the availability of trust units for sale if it disposes of its remaining trust units. Nevertheless, sales of substantial amounts of trust units in the public market could adversely affect prevailing market prices.
LEGAL MATTERS
Counsel for Cross Timbers, Kelly, Hart & Hallman, P.C., Fort Worth, Texas, will give a legal opinion 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 set forth in the section of this prospectus captioned "Federal Income Tax Consequences." Morris, Laing, Evans, Brock & Kennedy, Chartered, Wichita, Kansas, will give the Kansas tax opinion set forth in the section of this prospectus captioned "State Tax Considerations." Certain members of Kelly, Hart & Hallman, P.C. currently own approximately 23,200 shares of common stock of Cross Timbers, and certain partners of Butler & Binion, L.L.P. own 95,985 shares of common stock of Cross Timbers.
EXPERTS
Certain information appearing in this prospectus regarding the December 31, 1998 estimated quantities of reserves of the underlying properties and net profits interests owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Miller and Lents, Ltd. independent petroleum engineers.
The financial statements of Cross Timbers incorporated by reference in this prospectus, and statements of revenues and direct operating expenses of the underlying properties and the statement of assets and trust corpus of Hugoton Royalty Trust included in this Prospectus and elsewhere in the registration statement, have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports with respect thereto, and are included herein in reliance upon the authority of said firm as experts in accounting and auditing.
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
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.
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.
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.
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.
INDEX TO FINANCIAL STATEMENTS
Underlying Properties Report of Independent Public Accountants................................ F-2 Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 1996, 1997 and 1998....................................... F-3 Notes to Financial Statements........................................... F-4 Hugoton Royalty Trust Report of Independent Public Accountants................................ F-8 Statement of Assets and Trust Corpus as of December 31, 1998............ F-9 Note to Statement of Assets and Trust Corpus............................ F-10 Pro Forma Statement of Distributable Income for the Year Ended December 31, 1998 (Unaudited).......................................... F-12 Notes to Pro Forma Statement of Distributable Income (Unaudited)........ F-13 |
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
UNDERLYING PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
For the Years Ended December 31, 1996, 1997 and 1998
1996 1997 1998
------- ------- -------
(in thousands)
Revenues
Gas sales............................................. $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
======= ======= =======
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See Accompanying Notes to Financial Statements.
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.
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS--(Continued)
Sales from the Underlying Properties to the Company's wholly owned subsidiaries are as follows (in thousands):
1996 1997 1998
------- ------- -------
TGPC................................................. $13,944 $16,837 $13,248
RGC.................................................. 9,969 10,390 8,344
CTES................................................. 13,228 32,348 30,042
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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 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 in computing royalties payable for natural gas produced from federal leases and lands owned by Native Americans, the Company has mismeasured the volume of natural gas and wrongfully analyzed its heating content. The suit, which was brought under the qui tam provisions of the U.S. False Claims Act, seeks treble damages for the unpaid royalties (with interest), civil penalties and an order for the Company to cease the allegedly improper measuring practices. 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 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%.
UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS--(Continued)
Year-end posted West Texas Intermediate crude oil prices were $18.00 per barrel for 1995, $24.25 per barrel for 1996, $15.50 per barrel for 1997, and $9.50 per barrel for 1998. Year-end weighted average spot natural gas prices were $1.76 per Mcf for 1995, $2.84 per Mcf for 1996, $2.01 per Mcf for 1997, and $2.01 per Mcf for 1998.
The standardized measure of future net cash flows is not intended to represent the fair value of the Underlying Properties. Numerous uncertainties are inherent in estimating volumes and values of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the original estimates. Also, because natural gas prices are influenced by seasonal demand, use of year-end prices, as required by the Financial Accounting Standards Board, may not be representative in estimating future revenues or reserve data.
Reserve estimates for Underlying Properties that were acquired between 1996 and 1998 are not available for periods prior to the date they were acquired by the Company. Estimated proved reserves and the related standardized measure of these properties were calculated as of December 31, 1995, 1996 and 1997, by adding production prior to the date acquired to estimates as of the acquisition dates.
Gas (Mcf) Oil (Bbls)
Proved Reserves --------- ----------
(in thousands)
Balance, December 31, 1995.............................. 445,045 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
======= =====
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Proved Developed Reserves
Gas (Mcf) Oil (Bbls)
--------- ----------
(in thousands)
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
======= =====
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UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS--(Continued)
Standardized Measure of Discounted
Future Net Cash Flows Relating to
Proved Reserves
December 31,
----------------------------------
1996 1997 1998
---------- ---------- ----------
(in thousands)
Future cash inflows.................... $1,411,655 $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
December 31,
----------------------------------
1996 1997 1998
---------- ---------- ----------
(in thousands)
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
========== ========== ==========
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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
HUGOTON ROYALTY TRUST
STATEMENT OF ASSETS AND TRUST CORPUS
December 31, 1998
(in thousands)
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
========
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See Accompanying Note to Statement of Assets and Trust Corpus.
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.
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.
Gas (Mcf) Oil (Bbls)
--------- ----------
(in thousands)
Proved Reserves
Balance, December 31, 1998.............................. 282,297 2,193
======= =====
Proved Developed Reserves
Balance, December 31, 1998.............................. 249,215 1,934
======= =====
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Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Reserves at December 31, 1998
(in thousands)
Future cash inflows.......................................... $595,301
Future production taxes and transportation................... 55,686
--------
Future net cash flows........................................ 539,615
10% discount factor.......................................... 261,873
--------
Standardized measure of discounted future net cash flows..... $277,742
========
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HUGOTON ROYALTY TRUST
PRO FORMA STATEMENT OF DISTRIBUTABLE INCOME (Unaudited)
For the Year Ended December 31, 1998
(in thousands, except for per Unit amounts)
Pro Forma
Adjustments (Note
2)
-------------------
Underlying Other Cash
Properties Costs (a) Basis (b) Pro Forma
---------- --------- --------- ---------
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
=======
|
See Accompanying Notes to Unaudited Pro Forma Statement of Distributable Income.
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.
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 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 in computing royalties payable for natural gas produced from federal leases and lands owned by Native Americans, the Company has mismeasured the volume of natural gas and wrongfully analyzed its heating content. The suit, which was brought under the qui tam provisions of the U.S. False Claims Act, seeks treble damages for the unpaid royalties (with interest), civil penalties and an order for the Company to cease the allegedly improper measuring practices. 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
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.
Gas (Mcf) Oil (Bbls)
--------- ----------
(in thousands)
Proved Reserves
Balance, January 1, 1998................................ 279,024 2,431
Revisions ............................................ (11,541) (255)
Extensions, discoveries and other additions........... 24,177 133
Production............................................ (9,363) (116)
------- -----
Balance, December 31, 1998.............................. 282,297 2,193
======= =====
Proved Developed Reserves
January 1, 1998......................................... 249,148 2,136
======= =====
December 31, 1998....................................... 249,215 1,934
======= =====
|
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves at December 31, 1998
(in thousands)
Future cash inflows.......................................... $595,301
Future production taxes and transportation................... 55,686
--------
Future net cash flows........................................ 539,615
10% discount factor.......................................... 261,873
--------
Standardized measure of discounted future net cash flows..... $277,742
========
Changes in Standardized Measure of Discounted Future Net Cash
Flows from Proved Reserves
(in thousands)
Standardized measure, January 1, 1998........................ $292,749
--------
Extensions, discoveries and other additions.................. 21,742
Trust royalty income ........................................ (18,231)
Changes in prices and other.................................. (45,289)
Accretion of discount........................................ 26,771
--------
(15,007)
--------
Standardized measure, December 31, 1998...................... $277,742
========
|
UNDERWRITING
Cross Timbers and the underwriters named below (the "Underwriters") have entered into an underwriting agreement with respect to the trust units being offered. Subject to certain conditions, each Underwriter has severally agreed to purchase the number of trust units indicated in the following table. Goldman, Sachs & Co., Lehman Brothers Inc., Bear, Stearns & Co., Inc., Dain Rauscher Wessels, a division of Dain Rauscher Incorporated, Donaldson, Lufkin & Jenrette Securities Corporation and A. G. Edwards & Sons, Inc. are representatives of the Underwriters.
Number of
Underwriter Trust Units
----------- -----------
Goldman, Sachs & Co ...........................................
Lehman Brothers Inc. ..........................................
Bear, Stearns & Co. Inc........................................
Dain Rauscher Wessels, a division of Dain Rauscher
Incorporated............................................
Donaldson, Lufkin & Jenrette Securities Corporation............
A.G. Edwards & Sons, Inc.......................................
----------
Total........................................................ 15,000,000
==========
|
If the Underwriters sell more trust units than the total number shown in the table above, the Underwriters have an option to buy up to an additional 2,250,000 trust units from Cross Timbers to cover such sales. They may exercise that option for 30 days. If any trust units are purchased pursuant to this option, the Underwriters will severally purchase trust units in approximately the same proportion shown in the table above.
The following table shows the per trust unit and total underwriting discounts and commissions to be paid to the Underwriters by Cross Timbers. These amounts are shown assuming both no exercise and full exercise of the Underwriters' option to purchase 2,250,000 additional trust units.
Paid by Cross Timbers
-------------------------
No Exercise Full Exercise
----------- -------------
Per trust unit....................................... $ $
Total................................................ $ $
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Trust units sold by the Underwriters to the public will initially be offered at the initial public offering price shown on the cover of this prospectus. Any trust units sold by the Underwriters to securities dealers may be sold at a discount of up to $ per trust unit from the initial public offering price. Any such securities dealers may resell any trust units purchased from the Underwriters to certain other brokers or dealers at a discount of up to $ per trust unit from the initial public offering price. If all the trust units are not sold at the initial offering price, the representatives may change the offering price and the other selling terms.
Cross Timbers and its executive officers have agreed with the Underwriters not to dispose of or hedge any of their trust units or securities convertible into or exchangeable for trust units during the period from the date of this prospectus continuing through the date 180 days after the date of this prospectus, except with the prior written consent of the representatives. This agreement does not apply to any existing employee benefit plans.
Prior to the Offering, there has been no public market for the trust units. The initial public offering price has been negotiated among Cross Timbers and the representatives. Among the factors to be considered in determining the initial public offering price of the trust units, in addition to prevailing market conditions, will be estimates of distributions to trust unitholders and overall quality of the underlying properties.
The trust units have been approved for listing on the New York Stock Exchange under the symbol "HGT." In order to meet one of the requirements for listing the trust units on the New York Stock Exchange, the Underwriters have undertaken to sell lots of 100 or more trust units to a minimum of 2,000 beneficial holders.
In connection with the Offering, the Underwriters may purchase and sell trust units in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the Underwriters of a greater number of trust units than they are required to purchase in the Offering. Stabilizing transactions consist of certain bids or purchases made for the purpose of preventing or retarding a decline in the market price of the trust units while the Offering is in progress.
The Underwriters also may impose a penalty bid. This occurs when a particular Underwriter repays to the Underwriters a portion of the underwriting discount it received because the representatives repurchased trust units sold by or for the account of such Underwriter in stabilizing or short covering transactions.
These activities by the Underwriters may stabilize, maintain or otherwise affect the marketprice of the trust units. As a result, the price of the trust units may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the Underwriters at any time. These transactions may be effected on the New York Stock Exchange, in the over-the-counter market or otherwise.
The Underwriters do not expect sales to discretionary accounts to exceed five percent of the total number of trust units offered.
Cross Timbers estimates that total expenses of the Offering, other than underwriting discounts and commissions, will be approximately $650,000.
Cross Timbers and the trust have agreed to indemnify the several Underwriters against certain liabilities, including liabilities under the Securities Act of 1933. The trust's indemnity obligations are limited to the assets of the trust, and neither the trustee nor any unitholder will have any obligation to indemnify the Underwriters.
INFORMATION ABOUT
CROSS TIMBERS OIL COMPANY
The trust units are not interests in or obligations of Cross Timbers Oil Company.
CT-1
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:
Reserves
--------------------------------
Year Costs Bbls of Oil Bcf of Natural Gas
---- ------------- ------------- ------------------
(in millions) (in millions)
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.......................... 341 16.3 311.3
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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
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
. 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):
Proved Reserves
-------------------------------- Discounted
Natural Present Value before
Gas Liquids Income Tax of Proved
Oil (Bbls) Gas (Mcf) (Bbls) Reserves
---------- --------- ----------- --------------------
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%
====== ========= ====== ================
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(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
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
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 Cross Timbers' 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
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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.
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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:
December 31
--------------------------------
1996 1997 1998
---------- ---------- ----------
(in thousands)
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
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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
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:
Non-
Operated Operated
Wells Wells Total
------------- ----------- -------------
Gross Net Gross Net Gross Net
----- ------- ----- ----- ----- -------
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
===== ======= ===== ===== ===== =======
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Two gross (1.5 net) oil well and 86 gross (60 net) natural gas wells produce from two formations.
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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.
Year Ended December 31
---------------------------------
1996 1997 1998
---------- ----------- ----------
Gross Net Gross Net Gross Net
----- ---- ----- ----- ----- ----
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
=== ==== === ===== === ====
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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.
Developed Undeveloped
----------------- -------------
Gross Net Gross Net
--------- ------- ------ ------
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
========= ======= ====== ======
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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.
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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:
Year Ended December
31
--------------------
1996 1997 1998
------ ------ ------
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
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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 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.
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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.
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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
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 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 in computing royalties payable for natural gas produced from federal leases and lands owned by Native Americans, Cross Timbers mismeasured the volume of natural gas and incorrectly analyzed its heating content. The suit, which was brought under the qui tam provisions of the U.S. False Claims Act, seeks treble damages for the unpaid royalties, along with interest, civil penalties 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.
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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.
1998
1994 1995 1996 1997 1998 Pro Forma
--------- ---------- ---------- ---------- ----------- --------------
(in thousands except production, per share and per unit data)
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
Operating cash flow
(c).................... $ 37,816 $ 40,439 $ 68,263 $ 89,979 $ 78,480
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
Ratio of earnings to
fixed charges (d)...... 1.5 (0.2)(e) 2.6 2.2 (0.7)(f) (0.7)(f)
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CT-16
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 $341 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
CT-17
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 $33.4 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 the Hugoton Area during 1998, the Ozona Area in 1997 and 1998, the Fontenelle Unit during all three years and Major County, Oklahoma during 1996. 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 7.5 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.
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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
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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 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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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 $6.2 million in 1996 and $3.7 million in 1997. 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
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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
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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 scheduled to be redetermined in June 1999. If borrowings exceed the redetermined borrowing base in June 1999, 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. 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. On an incurred basis, exploration and development costs for 1998 totaled $77.9 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.
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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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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.
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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
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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 2002. 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:
Hypothetical
Carrying Fair Change in
Amount Value Fair Value
--------- --------- ------------
(in thousands)
December 31, 1997
Long-term debt.......................... $(539,000) $(538,288) $(19,688)
December 31, 1998
Long-term debt.......................... (921,000) (894,750) (16,300)
Interest rate swaps..................... -- (2,722) (8,655)
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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.
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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:
Term as
Director
Name Age Position Expires
---- --- -------- --------
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
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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
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
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
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)
------------------ ---- ------- ------- ------- ---------- ---------- ----------
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
|
CT-30
(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 $10.61 per share, the closing price of the common
stock on the November 20, 1996 grant date.
(f) Mr. Seeds became an employee of Cross Timbers in May 1997.
The following table shows certain information concerning grants of stock options and stock appreciation rights ("SARs") during 1998 for officers named in the Summary Compensation Table.
Option/SAR Grants in 1998 Individual Grants
Potential Realized
Value
Percentage at Assumed
Number of of Total Annual Rates of
Securities Options/ Stock Price
Underlying SARs Appreciation
Options/ Granted to Exercise For Option Term (a)
SARs Employees Price Expiration -------------------
Name Granted in 1998 ($/Share) Date 5% ($) 10% ($)
---- ---------- ---------- --------- ---------- --------- ---------
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
|
CT-31
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
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
---- ------------ ------------ ----------- ------------- ----------- -------------
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 -- --
|
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
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
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.
Margin Debt Promissory Notes
------------------------- -------------------------
Largest Amount Largest Amount
Executive Amount Outstanding Amount Outstanding
Officers Outstanding March 1, 1999 Outstanding March 1, 1999
--------- ----------- ------------- ----------- -------------
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
|
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
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.
Common Stock
Beneficially Owned (a)
-------------------------
Number of
Name Shares Percent
---- -------------- ----------
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
|
(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
(f) Includes 80,513 common shares owned by the Scott Sherman Family Limited
Partnership. See also (d) above.
(g) As reported on Schedule 13G by Baron Capital Group, Inc. at December 31,
1997 and updated through December 31, 1998 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
INDEX TO FINANCIAL STATEMENTS
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 |
CTF-1
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, its comprehensive income 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
CROSS TIMBERS OIL COMPANY
CONSOLIDATED BALANCE SHEETS
December 31
---------------------
1997 1998
--------- ----------
(in thousands)
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
========= ==========
|
See accompanying notes to consolidated financial statements.
CTF-3
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31
-----------------------------
1996 1997 1998
-------- -------- ---------
(in thousands, except
per share data)
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
======== ======== =========
|
See accompanying notes to consolidated financial statements.
CTF-4
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31
--------------------------
1996 1997 1998
------- ------- --------
(in thousands)
NET INCOME (LOSS).................................. $20,304 $25,684 $(69,719)
------- ------- --------
OTHER COMPREHENSIVE INCOME
Unrealized gains on securities:
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 --
------- ------- --------
Total Other Comprehensive Income (Loss)............ 638 (638) --
------- ------- --------
TOTAL COMPREHENSIVE INCOME (LOSS).................. $20,942 $25,046 $(69,719)
======= ======= ========
|
See accompanying notes to consolidated financial statements.
CTF-5
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Note 10)
Year Ended December 31
-----------------------------
1996 1997 1998
-------- -------- ---------
(in thousands)
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)
======== ======== =========
|
See accompanying notes to consolidated financial statements.
CTF-6
CROSS TIMBERS OIL COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Note 7)
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)
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)
===== ====== ====== ======= ==== ======== ========= ========
|
See accompanying notes to consolidated financial statements.
CTF-7
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
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 statements 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
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
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
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):
1996 1997 1998
----- ------ --------
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)
===== ====== ========
|
(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
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):
December 31
------------------
1997 1998
-------- --------
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
======== ========
|
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
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 30 days 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 6.9% during 1998 and 1997 and 6.7% during 1996. 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
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.
See also Note 7 "--Registration Statement."
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.
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):
1996 1997 1998
------- ------- --------
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)
======= ======= ========
|
Components of income tax expense (benefit) are as follows (in thousands):
1996 1997 1998
------- ------- --------
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)
======= ======= ========
|
CTF-15
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):
December 31
-----------------
1997 1998
-------- -------
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
======== =======
|
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):
1999................................................................. $ 7,528
2000................................................................. 7,177
2001................................................................. 6,968
2002................................................................. 6,886
2003................................................................. 6,858
Remaining............................................................ 6,548
-------
$41,965
=======
|
CTF-16
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 borrowings under the loan agreement.
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 $.25 per Mcf for 30,000 Mcf per day for April and May 1999 and 20,000 Mcf per day from
CTF-17
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
June through December 1999, and $.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 $.27 per Mcf for 15,000 Mcf per day for April 1999 and 10,000 Mcf 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.
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
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
plaintiffs are seeking an accounting 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 in computing royalties payable for gas produced from federal leases and lands owned by Native Americans, the Company and its subsidiaries have mismeasured the volume of gas and incorrectly analyzed 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 and certain of its subsidiaries are 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 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
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 4,330,443 shares in 1998 at an average cost of $15.14 per share. Additionally, the Company received 457,994 shares in 1996, 421,212 shares in 1997 and 24,506 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
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 are valued at $5,725,000 and are 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
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. The Company did not have significant commodity hedging activity during 1996 or 1997. 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 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 March 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):
Asset (Liability)
------------------------------------------
December 31, 1997 December 31, 1998
-------------------- --------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
--------- --------- --------- ---------
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)
|
The above fair values were estimated based on: investment in equity securities--current market quote; short and long-term debt--short-term borrowings and bank borrowings approximate the carrying value because of short- term interest rate maturities, while the fair value of subordinated notes is estimated to be $299.3 million and at December 31, 1997 and $273.7 million at December 31, 1998 based on a current market quote; futures contracts, basis swap agreements, call options and interest rate swap agreements--current market quote.
CTF-22
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
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):
Earnings
Earnings Shares per Share
-------- ------ ---------
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)
======== ====== ======
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CTF-24
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 10,393 shares (valued at $205,000) 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 $544,000.
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
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 (the "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 360,000 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 above $25, and of the remainder when the common stock price first closes 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 10,125 performance shares in each of 1996, 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
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:
1994, 1997
Weighted and
Average 1991 Plan 1998 Plans
Exercise Incentive Stock
Price Units Options
-------- --------- ----------
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
======== ==========
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CTF-27
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following summarizes information about Units/Options at December 31, 1998:
Units/Options Outstanding Units/Options Exercisable
---------------------------- ----------------------------
Weighted Weighted Weighted
Average Average Average
Range of Remaining Exercise Exercise
Exercise Prices Number Term Price Number Price
--------------- --------- --------- -------- -------------- -------------
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.......... 1,459,500 4.3 years 6.25 851,250 10.72
$12.84-18.22.......... 661,500 9.4 years 17.73 -- --
--------- --------------
2,638,986 1,369,236
========= ==============
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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.
1996 1997 1998
------- ------- -------
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%
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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):
1996 1997 1998
------- ------- --------
(in thousands, except
per share data)
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)
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CTF-28
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
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.
Pro Forma (Unaudited)
---------------------
1997 1998
---------- ----------
(in thousands, except
per share data)
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)
========== ==========
|
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
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):
Quarter
-----------------------------------
1st 2nd 3rd 4th
------- ------- -------- --------
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
|
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):
1996 1997 1998
-------- -------- --------
Acquisitions:
Producing properties............................ $105,252 $251,663 $339,889
Undeveloped properties.......................... 563 3,964 880
Development (a)................................... 44,758 86,555 69,836
Exploration (b)................................... 280 2,088 8,034
-------- -------- --------
Total......................................... $150,853 $344,270 $418,639
======== ======== ========
|
CTF-31
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
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Oil Gas Natural Gas
(Bbls) (Mcf) Liquids (Bbls) (a)
------ --------- ------------------
(in thousands)
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
====== ========= ======
|
(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
CROSS TIMBERS OIL COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
December 31
----------------------------------
1996 1997 1998
---------- ---------- ----------
(in thousands)
Future cash inflows........................ $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
========== ========== ==========
|
(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
1996 1997 1998
-------- -------- --------
(in thousands)
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
======== ======== ========
|
CTF-34
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
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
CROSS TIMBERS OIL COMPANY
PRO FORMA CONSOLIDATED BALANCE SHEET (Unaudited)
December 31, 1998
Pro Forma
Adjustments
(Note 4)
------------------
Historical Trust Offering (a) Pro Forma
---------- ------------------ ----------
(in thousands)
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
========== ========= ==========
|
See Accompanying Notes to Pro Forma Consolidated Financial Statements.
CTF-37
CROSS TIMBERS OIL COMPANY
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
For the Year Ended December 31, 1998
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)
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...... (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
========= ======== =========
|
See Accompanying Notes to Pro Forma Consolidated Financial Statements.
CTF-38
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
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
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
Natural Gas
Oil (Bbls) Gas (Mcf) Liquids (Bbls)
---------- --------- --------------
(in thousands)
Proved reserves.......................... 53,301 1,054,702 17,174
====== ========= ======
Proved developed reserves................ 41,865 837,896 14,000
====== ========= ======
|
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
(in thousands)
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
===========
|
CTF-41
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
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)
January 1
Year Ended December 31, through
----------------------- April 24,
1995 1996 1997 1998
------- ------- ------- -----------
(Unaudited) ---
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
======= ======= ======= =======
|
See Accompanying Notes to Statements of Revenues and Direct Operating Expenses.
CTF-43
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
Oil Gas
(Bbls) (Mcf)
------ -------
(in thousands)
Proved reserves............................................... 1,599 232,229
===== =======
Proved developed reserves..................................... 1,365 191,293
===== =======
|
CTF-44
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
(in thousands)
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
=========
|
CTF-45
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
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)
January 1
Year Ended through
December 31, December 1,
1996 1997
------------ -----------
(Unaudited)
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
======= =======
|
See Accompanying Notes to Statements of Revenues and Direct Operating Expenses.
CTF-47
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
Natural Gas
Liquid
Oil (Bbls) Gas (Mcf) (Bbls)
---------- -------- -----------
(in thousands)
Proved reserves............................. 1,356 226,946 14,423
===== ======= ======
Proved developed reserves................... 1,147 195,243 12,409
===== ======= ======
|
CTF-48
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
(in thousands)
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
=========
|
CTF-49
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:
-----------------------------------------------------------------------------------------------------------
Net Reserves as of 1/1/99 Future Net Revenue
-----------------------------------------------------------------------
Oil and
Condensate, Gas, Undiscounted, Discounted at
Reserves Category MBbls. MMcf M$ 10% Per Year, M$
-----------------------------------------------------------------------------------------------------------
Kansas
-----------------------------------------------------------------------------------------------------------
Proved Developed Producing 50.6 46,123.6 45,306.6 24,767.3
-----------------------------------------------------------------------------------------------------------
Proved Nonproducing 0.0 499.1 344.5 176.3
-----------------------------------------------------------------------------------------------------------
Proved Undeveloped 0.0 3,996.2 1,698.7 510.6
-----------------------------------------------------------------------------------------------------------
Subtotal 50.6 50,618.9 47,349.7 25,454.1
-----------------------------------------------------------------------------------------------------------
Oklahoma
-----------------------------------------------------------------------------------------------------------
Proved Developed Producing 2,901.2 235,076.2 328,413.8 192,126.8
-----------------------------------------------------------------------------------------------------------
Proved Nonproducing 206.9 14,281.9 20,685.8 12,219.8
-----------------------------------------------------------------------------------------------------------
Proved Undeveloped 601.3 36,125.9 35,171.7 13,182.5
-----------------------------------------------------------------------------------------------------------
Subtotal 3,709.3 285,484.0 384,271.3 217,529.1
-----------------------------------------------------------------------------------------------------------
Wyoming
-----------------------------------------------------------------------------------------------------------
Proved Developed Producing 189.2 132,662.1 186,849.2 88,540.8
-----------------------------------------------------------------------------------------------------------
Proved Nonproducing 20.6 6,685.6 10,812.6 5,173.7
-----------------------------------------------------------------------------------------------------------
Proved Undeveloped 60.3 39,622.6 45,235.3 10,479.0
-----------------------------------------------------------------------------------------------------------
Subtotal 270.1 178,970.3 242,897.1 104,193.5
-----------------------------------------------------------------------------------------------------------
Total Underlying Properties (100%)
-----------------------------------------------------------------------------------------------------------
Proved Developed Producing 3,140.9 413,861.8 560,569.6 305,434.9
-----------------------------------------------------------------------------------------------------------
Proved Nonproducing 227.5 21,466.6 31,842.8 17,569.7
-----------------------------------------------------------------------------------------------------------
Proved Undeveloped 661.5 79,744.7 82,105.7 24,172.1
-----------------------------------------------------------------------------------------------------------
TOTAL 4,029.9 515,073.1 674,518.1 347,176.7
-----------------------------------------------------------------------------------------------------------
|
MILLER AND LENTS, LTD.
Cross Timbers Oil Company January 20, 1999
We performed evaluations, which are designated as the SEC Pricing Case, using price, expense, and gas production curtailment premises specified by you and described in detail on Attachment 1.
Proved reserves and future net revenue were estimated in accordance with the provisions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10. The Securities and Exchange Commission definition of proved reserves is shown on Attachment 2. Estimates of future net revenue and discounted future net revenue are not intended and should not be interpreted to represent fair market values for the estimated reserves. Future costs of abandoning facilities and wells and of the restoration of producing properties to satisfy environmental standards were not deducted from total revenues as such estimates are beyond the scope of this assignment.
Following Attachment 2 is a list of exhibits which include annual projections of future production and net revenue for each state and reserve category. Also included in the exhibits are one-line summaries for the total royalty trust and for each state showing the proved reserves and future net revenue for the individual properties. Projections of individual property future production and net revenue are included in separate volumes to this report. These exhibits and volumes should not be relied upon independently of this narrative.
The proved developed producing reserves and production forecasts were estimated by production decline extrapolations, water-oil ratio trends, P/Z declines, or in a few cases, by volumetric calculations. For some properties with insufficient performance history to establish trends, we estimated future production by analogy with other properties with similar characteristics. The past performance trends of many properties were influenced by production curtailments, workovers, waterfloods, and/or infill drilling. Actual future production may require that our estimated trends be significantly altered.
The estimated proved undeveloped reserves require significant capital expenditures such as drilling and completion costs. The proved undeveloped reserve estimates for infill wells are based on analogies to similar infill wells in the same field and/or the production histories of offset wells in the same field.
Reserve estimates from volumetric calculations and from analogies are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserves was produced.
With the exception of a few properties, the data employed in our determinations of proved reserves and future net income were provided by Cross Timbers Oil Company. We obtained pressure and production information from independent sources for some properties that had insufficient data from Cross Timbers Oil Company to employ as bases for reserve estimates. The current expenses for each lease were obtained from operating statements provided by Cross Timbers Oil Company except for certain leases where Cross Timbers Oil Company deducted items considered by Cross Timbers Oil Company to be nonrecurring expenditures. No overhead was included for those properties operated by Cross Timbers Oil Company. For some properties, such as large waterfloods, Cross Timbers Oil Company assumed a decline in variable operating costs due to depleting production which was derived by forecasting a decrease in the property well count. None of the data provided to us by Cross Timbers Oil Company,
MILLER AND LENTS, LTD.
Cross Timbers Oil Company January 20, 1999
including, but not limited to, graphical representations and tabulations of past production performance, well tests and pressures, ownership interests, prices, and operating costs, were verified by us as such was not within the scope of our assignment.
The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report.
Our workpapers and data are in our files and available for review upon request. If you have any questions regarding the above, or if we can be of further assistance, please call.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ Karen F. Loving ------------------------------- Karen F. Loving Vice President |
KFL/hsd
Attachment 1
1-1-99
Underlying Properties (100%)
Relating to the
Hugoton Royalty Trust
SEC PRICING CASE
A. Oil Price All oil/condensate prices held constant at $9.50 per
barrel through the life of the property. (Adjust for
gravity, transportation charges, and crude marketing
arrangements.)
B. Gas Price Estimated 1/1/99 price held constant through the life
of the property.
C. Operating Costs Current expenses held constant through the life of the
property.
D. Curtailment For curtailed gas wells, curtailed rates were based on
the first six months of 1998 rate as a percent of 1998
capacity, then relieved over a two-year period, i.e.,
100% at 1/1/01.
E. Discount Rate 10% per year.
|
Attachment 2
|
PROVED RESERVES DEFINITIONS
IN ACCORDANCE WITH
SECURITIES AND EXCHANGE COMMISSION REGULATION S-X
Proved oil and gas reserves 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 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 are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
EXHIBIT B
[LETTERHEAD OF MILLER & LENTS, LTD. APPEARS HERE]
January 20, 1999
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, TX 76102
Re: Hugoton Royalty Trust
80% Net Profits Interests
As of January 1, 1999
SEC Pricing Case
Gentlemen:
At your request, we estimated the proved reserves and future net revenue as of January 1, 1999, attributable to the Hugoton Royalty Trust interest in certain oil and gas properties that consist of approximately 1,405 active wells located primarily in Kansas, Oklahoma, and Wyoming. The aggregate results of our evaluations are as follows:
Net Reserves as of 1/1/99 Future Net Revenue
------------------------------------------------------------------------
Oil and
Condensate, Gas, Undiscounted, Discounted at
Reserves Category MBbls. MMcf M$ 10% Per Year, M$
-------------------------------------------------------------------------------------------------------
Kansas
-------------------------------------------------------------------------------------------------------
Proved Developed Producing 28.4 25,987.1 36,245.2 19,813.8
-------------------------------------------------------------------------------------------------------
Proved Nonproducing 0.0 240.4 275.6 141.0
-------------------------------------------------------------------------------------------------------
Proved Undeveloped 0.0 1,141.6 1,359.0 408.5
-------------------------------------------------------------------------------------------------------
Subtotal 28.4 27,369.1 37,879.8 20,363.3
-------------------------------------------------------------------------------------------------------
Oklahoma
-------------------------------------------------------------------------------------------------------
Proved Developed Producing 1,667.2 135,345.9 262,731.0 153,701.5
-------------------------------------------------------------------------------------------------------
Proved Nonproducing 117.9 8,140.8 16,548.6 9,775.8
-------------------------------------------------------------------------------------------------------
Proved Undeveloped 231.7 13,898.2 28,137.4 10,546.0
-------------------------------------------------------------------------------------------------------
Subtotal 2,016.8 157,384.9 307,417.0 174,023.3
-------------------------------------------------------------------------------------------------------
Wyoming
-------------------------------------------------------------------------------------------------------
Proved Developed Producing 107.4 75,219.7 149,479.4 70,832.7
-------------------------------------------------------------------------------------------------------
Proved Nonproducing 13.2 4,280.7 8,650.1 4,139.0
-------------------------------------------------------------------------------------------------------
Proved Undeveloped 27.5 18,042.9 36,188.2 8,383.2
-------------------------------------------------------------------------------------------------------
Subtotal 148.1 97,543.3 194,317.7 83,354.9
-------------------------------------------------------------------------------------------------------
Total Hugoton Royalty Trust
-------------------------------------------------------------------------------------------------------
Proved Developed Producing 1,803.0 236,552.7 448,455.6 244,348.0
-------------------------------------------------------------------------------------------------------
Proved Nonproducing 131.1 12,661.9 25,474.3 14,055.8
-------------------------------------------------------------------------------------------------------
Proved Undeveloped 259.2 33,082.7 65,684.6 19,337.7
-------------------------------------------------------------------------------------------------------
TOTAL 2,193.3 282,297.3 539,614.5 277,741.5
-------------------------------------------------------------------------------------------------------
|
MILLER AND LENTS, LTD.
Cross Timbers Oil Company January 20, 1999
We performed evaluations, which are designated as the SEC Pricing Case, using price, expense, and gas production curtailment premises specified by you and described in detail on Attachment 1.
The Hugoton Royalty Trust interests evaluated herein are comprised of an 80 percent net overriding royalty interest of certain Cross Timbers Oil Company properties. At your instruction, the net oil and condensate reserves and the net natural gas reserves attributable to the Hugoton Royalty Trust interests were computed from 80 percent of the Cross Timbers Oil Company interests in those properties after adjustment for the estimated reserves attributable to the future operating expenses and capital costs. As a result of this procedure, a change in the future costs, or prices, or capital expenditures different from those projected herein may result in a change in the computed reserves to the net interests even if there are no revisions or additions to the gross reserves attributed to the property.
Proved reserves and future net revenue were estimated in accordance with the provisions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10. The Securities and Exchange Commission definition of proved reserves is shown on Attachment 2. Estimates of future net revenue and discounted future net revenue are not intended and should not be interpreted to represent fair market values for the estimated reserves. Future costs of abandoning facilities and wells and of the restoration of producing properties to satisfy environmental standards were not deducted from total revenues as such estimates are beyond the scope of this assignment.
Following Attachment 2 is a list of exhibits which include annual projections of future production and net revenue for each state and reserve category. Also included in the exhibits are one-line summaries for the total royalty trust and for each state showing the proved reserves and future net revenue for the individual properties. Projections of individual property future production and net revenue are included in separate volumes to this report. These exhibits and volumes should not be relied upon independently of this narrative.
The proved developed producing reserves and production forecasts were estimated by production decline extrapolations, water-oil ratio trends, P/Z declines, or in a few cases, by volumetric calculations. For some properties with insufficient performance history to establish trends, we estimated future production by analogy with other properties with similar characteristics. The past performance trends of many properties were influenced by production curtailments, workovers, waterfloods, and/or infill drilling. Actual future production may require that our estimated trends be significantly altered.
The estimated proved undeveloped reserves require significant capital expenditures such as drilling and completion costs. The proved undeveloped reserve estimates for infill wells are based on analogies to similar infill wells in the same field and/or the production histories of offset wells in the same field.
Reserve estimates from volumetric calculations and from analogies are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserves was produced.
MILLER AND LENTS, LTD.
Cross Timbers Oil Company January 20, 1999
With the exception of a few properties, the data employed in our determinations of proved reserves and future net income were provided by Cross Timbers Oil Company. We obtained pressure and production information from independent sources for some properties that had insufficient data from Cross Timbers Oil Company to employ as bases for reserve estimates. The current expenses for each lease were obtained from operating statements provided by Cross Timbers Oil Company except for certain leases where Cross Timbers Oil Company deducted items considered by Cross Timbers Oil Company to be nonrecurring expenditures. No overhead was included for those properties operated by Cross Timbers Oil Company. For some properties, such as large waterfloods, Cross Timbers Oil Company assumed a decline in variable operating costs due to depleting production which was derived by forecasting a decrease in the property well count. None of the data provided to us by Cross Timbers Oil Company, including, but not limited to, graphical representations and tabulations of past production performance, well tests and pressures, ownership interests, prices, and operating costs, were verified by us as such was not within the scope of our assignment.
The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report.
Our workpapers and data are in our files and available for review upon request. If you have any questions regarding the above, or if we can be of further assistance, please call.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ Karen F. Loving ---------------------------- Karen F. Loving Vice President |
KFL/hsd
Attachment 1
1-1-99
Hugoton Royalty Trust
80% Net Profits Interests
SEC PRICING CASE
A. Oil Price All oil/condensate prices held constant at $9.50 per
barrel through the life of the property. (Adjust for
gravity, transportation charges, and crude marketing
arrangements.)
B. Gas Price Estimated 1/1/99 price held constant through the life
of the property.
C. Operating Costs Current expenses held constant through the life of the
property.
D. Curtailment For curtailed gas wells, curtailed rates were based on
the first six months of 1998 rate as a percent of 1998
capacity, then relieved over a two-year period, i.e.,
100% at 1/1/01.
E. Discount Rate 10% per year.
|
Attachment 2
|
PROVED RESERVES DEFINITIONS
IN ACCORDANCE WITH
SECURITIES AND EXCHANGE COMMISSION REGULATION S-X
Proved oil and gas reserves 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 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 are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information or representations. This prospectus is an offer to sell the Trust Units offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.
TABLE OF CONTENTS
Page
----
Prospectus Summary........................................................ 3
Risk Factors.............................................................. 11
Forward Looking Statements................................................ 15
Use of Proceeds........................................................... 15
Cross Timbers............................................................. 15
The Trust................................................................. 16
Projected Cash Distributions.............................................. 16
The Underlying Properties................................................. 21
Computation of Net Proceeds............................................... 33
Federal Income Tax Consequences........................................... 36
State Tax Considerations.................................................. 41
ERISA Considerations...................................................... 42
Description of the Trust Indenture........................................ 43
Description of the Trust Units............................................ 46
Selling Trust Unitholder.................................................. 48
Legal Matters............................................................. 49
Experts................................................................... 49
Available Information..................................................... 49
Glossary of Certain Oil and Natural Gas Terms............................. 51
Index to Financial Statements............................................. F-1
Underwriting.............................................................. U-1
Information about Cross Timbers Oil Company............................... CT-1
Summary Reserve Reports........................................Exhibits A and B
|
Through and including , 1999 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer's obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.
15,000,000 Trust Units
Hugoton Royalty Trust
PROSPECTUS
Goldman, Sachs & Co.
Lehman Brothers
Bear, Stearns & Co. Inc.
Dain Rauscher Wessels
a division of Dain Rauscher Incorporated
Donaldson, Lufkin & Jenrette
A.G. Edwards & Sons, Inc.
Representatives of the Underwriters
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
All capitalized terms used and not defined in Part II of this Registration Statement shall have the meanings assigned to them in the Prospectus forming a part of this Registration Statement.
Item 14. Other Expenses of Issuance and Distribution.
Except for the Registration Fee and the NASD Filing Fee, the following itemized table sets forth estimates of those expenses payable by the Company in connection with the offer and sale of the securities offered hereby:
Registration Fee................................................... $ 47,955
NASD Filing Fee.................................................... 19,820
Printing and Engraving Expenses.................................... 200,000
Legal Fees and Expenses............................................ 175,000
Accountants' Fees and Expenses..................................... 60,000
Miscellaneous Fees and Expenses.................................... 147,225
--------
Total.............................................................. $650,000
========
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Item 15. Indemnification of Directors and Officers.
Section 6.02 of the Trust Indenture provides that the trustee will be indemnified by the trust estate or, if Trust assets are insufficient, by Cross Timbers Oil Company, a Delaware corporation (the "Company"), against any and all liability and expenses incurred by it individually or as Trustee in the administration of the trust and the trust estate, except for any liability or expense resulting from fraud or gross negligence or acts or omissions in bad faith.
The Company is incorporated in Delaware. Under Section 145 of the Delaware General Corporation Law (the "DGCL"), a Delaware corporation has the power, under specified circumstances, to indemnify its directors, officers, employees and agents in connection with actions, suits or proceedings brought against them by a third party or in the right of the corporation, by reason that they were or are such directors, officers, employees or agents, against expenses and liabilities incurred in any such action, suit or proceeding so long as they acted in good faith and in a manner that they reasonably believed to be in, or not opposed to, the best interests of such corporation, and with respect to any criminal action, that they had no reasonable cause to believe their conduct was unlawful. With respect to suits by or in the right of such corporation, however, indemnification is generally limited to attorneys' fees and other expenses and is not available if such person is adjudged to be liable to such corporation unless the court determines that indemnification is appropriate. A Delaware corporation also has the power to purchase and maintain insurance for such persons. Article Nine of the Certificate of Incorporation of the Company permits indemnification of directors and officers to the fullest extent permitted by Section 145 of the DGCL. Reference is made to the Certificate of Incorporation of the Company.
Section 102(b)(7) of the DGCL provides that a certificate of incorporation may contain a provision eliminating or limiting the personal liability of a director to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, provided that such provisions may not eliminate or limit the liability of a director (i) for any breach of the director's duty of loyalty to the corporation or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 (relating to liability for unauthorized acquisitions or redemptions of, or dividends on, capital stock) of the DGCL or (iv) for any transaction from which the director derived an improper personal benefit. Article Ten of the Company's Certificate of Incorporation contains such a provision.
II-1
The above discussion of the Company's Certificate of Incorporation and of Sections 102(b)(7) and 145 of the DGCL is not intended to be exhaustive and is qualified in its entirety by such Certificate of Incorporation and statutes.
Additionally, the Company has acquired directors' and officers' insurance in the amount of $10 million.
Item 16. Exhibits.
Exhibit
Number Description
------- -----------
1.1* --Form of Underwriting Agreement.
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* --Hugoton Royalty Trust Indenture.
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* --Form of 80% Net Overriding Royalty Conveyance--Kansas.
10.1.1 --Form of 80% Net Overriding Royalty Conveyance--Kansas as amended and
restated.
10.2* --Form of 80% Net Overriding Royalty Conveyance--Oklahoma.
10.2.1 --Form of 80% Net Overriding Royalty Conveyance--Oklahoma as amended
and restated.
10.3* --Form of 80% Net Overriding Royalty Conveyance--Wyoming.
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).
|
II-2
Exhibit
Number Description
------- -----------
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).
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).
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.
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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
(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
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 March 16, 1999.
CROSS TIMBERS OIL COMPANY,
By /s/ J. Richard Seeds ----------------------------------- J. Richard Seeds Executive Vice President |
HUGOTON ROYALTY TRUST
By CROSS TIMBERS OIL COMPANY, as
sponsor
By /s/ J. Richard Seeds ------------------------------- J. Richard Seeds Executive Vice President |
Pursuant to the requirements of the Securities Act of 1933, this Amendment to Registration Statement has been signed by the following persons in the capacities and on the dates indicated.
/s/ Bob R. Simpson* Director, Chairman of the March 16, 1999
______________________________________ Board and Chief Executive
Bob R. Simpson Officer (Principal
Executive Officer)
/s/ Steffen E. Palko* Director, Vice Chairman of March 16, 1999
______________________________________ the Board and President
Steffen E. Palko
/s/ J. Richard Seeds Director, Executive Vice March 16, 1999
______________________________________ President
J. Richard Seeds
/s/ J. Luther King, Jr.* Director March 16, 1999
______________________________________
J. Luther King, Jr.
/s/ Jack P. Randall* Director March 16, 1999
______________________________________
Jack P. Randall
/s/ Scott G. Sherman* Director March 16, 1999
______________________________________
Scott G. Sherman
/s/ Louis G. Baldwin Senior Vice President and March 16, 1999
______________________________________ Chief Financial Officer
Louis G. Baldwin (Principal Financial
Officer)
/s/ Bennie G. Kniffen Senior Vice President and March 16, 1999
______________________________________ Controller (Principal
Bennie G. Kniffen Accounting Officer)
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*By: /s/ J. Richard Seeds
------------------------------
J. Richard Seeds
Attorney-in-Fact
|
II-5
EXHIBIT INDEX
Exhibit
Number Description
------- -----------
3.1 --Certificate of Incorporation of Cross Timbers Oil Company, as
amended through and restated on April 21, 1998.
--Opinion of Kelly, Hart & Hallman, P.C. as to legality of the
5.1 securities registered hereby.
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.
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.
23.5 --Consent of Miller & Lents.
27.2 --Financial Data Schedule relating to Cross Timbers Oil Company.
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EXHIBIT 3.1
CROSS TIMBERS OIL COMPANY
RESTATED CERTIFICATE OF INCORPORATION
Cross Timbers Oil Company, a corporation organized and existing under the laws of the State of Delaware (the "Corporation"), hereby certifies as follows:
1. The name of the Corporation is Cross Timbers Oil Company. Cross Timbers Oil Company was originally incorporated under the same name, and the original Certificate of Incorporation of the Corporation was filed with the Secretary of State of the State of Delaware on October 9, 1990.
2. Pursuant to Section 245 of the General Corporation Law of the State of Delaware, this Restated Certificate of Incorporation only restates and integrates and does not further amend the provisions of the Certificate of Incorporation of this Corporation, as theretofore amended or supplemented, and there is no discrepancy between those provisions and the provisions of this Restated Certificate of Incorporation. This Restated Certificate of Incorporation has been duly adopted in accordance with Section 245 of the General Corporation Law of the State of Delaware.
3. The text of the Certificate of Incorporation as heretofore amended or supplemented is hereby restated and integrated to read in its entirety as follows:
ARTICLE ONE
The name of the Corporation is Cross Timbers Oil Company.
ARTICLE TWO
The address of the Corporation's registered office in the State of Delaware is 1013 Centre Road, Wilmington, New Castle County, Delaware 19805, and the name of its registered agent at such address is Corporation Service Company.
ARTICLE THREE
The nature of the business or purposes to be conducted or promoted is to engage in any lawful act or activity for which corporations may be organized under the General Corporation Law of Delaware ("Act").
ARTICLE FOUR
The Corporation shall have authority to issue two classes of stock, and the total number authorized shall be one hundred million (100,000,000) shares of Common Stock of the par value of one cent ($.01) each, and twenty-five million (25,000,000) shares of Preferred Stock of the par value of one cent ($.01) each. A description of the different classes of stock of the Corporation and a statement of the designations and the powers, preferences and rights, and the qualifications,
limitations or restrictions thereof, in respect of each class of such stock are as follows:
1. Issuance in Class or Series. The Common Stock or Preferred Stock may be issued from time to time in one or more series, or either or both of the Common or Preferred Stock may be divided into additional classes and such classes into one or more series. The terms of a class or series, including all rights and preferences, shall be as specified in the resolution or resolutions adopted by the Board of Directors designating such class or series which resolution or resolutions the Board of Directors is hereby expressly authorized to adopt. Such resolution or resolutions with respect to a class or series shall specify all or such of the rights or preferences of such class or series as the Board of Directors shall determine, including, without limitation, any or all of the following, if applicable: (a) the number of shares to constitute such class or series and the distinctive designation thereof; (b) the dividend or manner for determining the dividend payable with respect to the shares of such class or series and the date or dates from which dividends shall accrue, whether such dividends shall be cumulative, and, if cumulative, the date or dates from which dividends shall accumulate and whether the shares in such class or series shall be entitled to preference or priority over any other class or series of stock of the Corporation with respect to payment of dividends; (c) the terms and conditions, including price or a manner for determining the price, of redemption, if any, of the shares of such class or series; (d) the terms and conditions of a retirement or sinking fund, if any, for the purchase or redemption of the shares of such class or series; (e) the amount which the shares of such class or series shall be entitled to receive, if any, in the event of any liquidation, dissolution or winding up of the Corporation and whether such shares shall be entitled to a preference or priority over shares of another class or series with respect to amounts received in connection with any liquidation, dissolution or winding up of the Corporation; (f) whether the shares of such class or series shall be convertible into, or exchangeable for, shares of stock of any other class or classes, or any other series of the same or any other class or classes of stock, of the Corporation and the terms and conditions of any such conversion or exchange; (g) the voting rights, if any, of shares of stock of such class or series in addition to those granted herein, if any; (h) the status as to reissuance or sale of shares of such class or series redeemed, purchased or otherwise reacquired or surrendered to the Corporation on conversion; (i) the conditions and restrictions, if any, on the payment of dividends or on the making of other distributions on, or the purchase, redemption or other acquisition by the Corporation or any subsidiary, of any other class or series of stock of the Corporation ranking junior to such shares as to dividends or upon liquidation; (j) the conditions, if any, on the creation of indebtedness of the Corporation, or any subsidiary; and (k) such other preferences, rights, restrictions and qualifications as the Board of Directors may determine.
All shares of the Common Stock shall rank equally and all shares of the Preferred Stock shall rank equally, and be identical within their classes in all respects regardless of series, except as to terms which may be specified by the Board of Directors pursuant to the above provisions. All shares of any one series of a class of Common or Preferred Stock shall be of equal rank and identical in all respects, except that shares of any one series issued at different times may differ as to the dates which dividends thereon shall accrue and be cumulative.
2. Other Provisions. Shares of Common Stock or Preferred Stock of any class or series may be issued with such voting powers, full or limited, or no voting powers, and such designations, preferences and relative participating, option or special rights, and qualifications, limitations or
restrictions thereof, as shall be stated and expressed in the resolution or resolutions providing for the issuance of such stock adopted by the Board of Directors. Any of the voting powers, designations, preferences, rights and qualifications, limitations or restrictions of any such class or series of stock may be made dependent upon facts ascertainable outside the resolution or resolutions of the Board of Directors providing for the issue of such stock by the Board of Directors, provided the manner in which such facts shall operate upon the voting powers, designations, preferences, rights and qualifications, limitations or restrictions or such class or series is clearly set forth in the resolution or resolutions providing for the issue of such stock adopted by the Board of Directors.
3. Common Stock. Except as otherwise provided in any resolution or resolutions adopted by the Board of Directors providing for the issuance of a class or series of Common Stock or Preferred Stock, the Common Stock shall (a) have the exclusive voting power of the Corporation; (b) entitle the holders thereof to one vote per share at all meetings of the stockholders of the Corporation; (c) entitle the holders to share ratably, without preference over any other shares of the Corporation in all assets of the Corporation in the event of any dissolution, liquidation or winding up of the Corporation; and (d) entitle the record holders thereof on such record dates as are determined, from time to time, by the Board of Directors to receive such dividends, if any, if, as and when declared by the Board of Directors.
4. Series A Convertible Preferred Stock. The voting and other powers, preferences and relative, participating, optional or other rights, and the qualifications, limitations and restrictions thereof, of the Corporation's Series A Convertible Preferred Stock are set forth in Appendix A hereto and are incorporated herein by reference.
ARTICLE FIVE
The Corporation is to have perpetual existence.
ARTICLE SIX
1. Number, Election and Term of Directors. The business and affairs of the Corporation shall be managed by a Board of Directors, which, subject to the rights of holders of shares of any class or series of Preferred Stock of the Corporation then outstanding to elect additional directors under specified circumstances, shall consist of not less than three nor more than twenty-one persons. The exact number of directors within the minimum and maximum limitations specified in the preceding sentence shall be fixed from time to time by either (i) the Board of Directors pursuant to a resolution adopted by a majority of the entire Board of Directors, or (ii) the affirmative vote of the holders of 80% or more of the voting power of all of the shares of the Corporation entitled to vote generally in the election of directors voting together as a single class. No decrease in the number of directors constituting the Board of Directors shall shorten the term of any incumbent director. Each director shall hold office until his successor is elected and qualified.
2. Stockholder Nomination of Director Candidates. Advance notice of stockholder nominations for the election of directors shall be submitted to the Board of Directors at least 120 days in advance of the scheduled date for the next annual meeting of stockholders.
3. Newly-Created Directorships and Vacancies. Subject to the rights of the holders of any series of any Preferred Stock then outstanding, newly-created directorships resulting from any increase in the authorized number of directors and any vacancies in the Board of Directors resulting from the death, resignation, retirement, disqualification, removal from office or other cause may be filled by a majority vote of the directors then in office even though less than a quorum, or by a sole remaining director.
4. Amendment, Repeal, etc. Notwithstanding anything contained in this Certificate of Incorporation to the contrary, the affirmative vote of the holders of 80% or more of the voting power of all of the shares of the Corporation entitled to vote generally in the election of directors, voting together as a single class, shall be required to alter, amend or adopt any provision inconsistent with or repeal this Article Six, or to alter, amend, adopt any provision inconsistent with or repeal comparable sections of the Bylaws of the Corporation provided, however, that the maximum number of directors that the Corporation may have may be increased to more than twenty-one by the vote of the holders of a majority or more of the shares of the Corporation entitled to vote thereon.
5. Amendment of Bylaws. In furtherance and not in limitation of the powers conferred by statute, the Board of Directors is expressly authorized to make, alter or repeal the Bylaws of the Corporation.
ARTICLE SEVEN
Subject to the rights of the holders of any series of Preferred Shares then outstanding, any action required or permitted to be taken by the stockholders of the Corporation must be effected at a duly called annual or special meeting of stockholders of the Corporation and may not be effected by any consent in writing by such stockholders unless all of the stockholders entitled to vote thereon consent thereto in writing. Notwithstanding anything contained in this Certificate of Incorporation to the contrary, the affirmative vote of the holders of 80% or more of the voting power of all the shares of the Corporation entitled to vote generally in the election of directors, voting together as a single class, shall be required to call a special meeting of stockholders or to alter, amend, adopt any provision inconsistent with or repeal this Article Seven, or to alter, amend, adopt any provision inconsistent with comparable sections of the Bylaws.
ARTICLE EIGHT
The Board of Directors is hereby authorized to create and issue, whether or not in connection with the issuance and sale of any of its stock or other securities, rights (the "Rights") entitling the holders thereof to purchase from the Corporation shares of capital stock or other securities. The times at which and the terms upon which the Rights are to be issued will be determined by the Board of Directors and set forth in the contracts or instruments that evidence the Rights. The authority of the Board of Directors with respect to the Rights shall include, but not be limited to, determination of the following:
(a) The initial purchase price per share of the capital stock or other securities of the Corporation to be purchased upon exercise of the Rights.
(b) Provisions relating to the times at which and the circumstances under which the Rights may be exercised or sold or otherwise transferred, either together with or separately from, any other securities of the Corporation.
(c) Provisions that adjust the number or exercise price of the Rights or amount or nature of the securities or other property receivable upon exercise of the Rights in the event of a combination, split or recapitalization of any capital stock of the Corporation, a change in ownership of the Corporation's securities or a reorganization, merger, consolidation, sale of assets or other occurrence relating to the Corporation or any capital stock of the Corporation, and provisions restricting the ability of the Corporation to enter into any such transaction absent an assumption by the other party or parties thereto of the obligations of the Corporation under such Rights.
(d) Provisions that deny the holder of a specified percentage of the outstanding securities of the Corporation the right to exercise the Rights and/or cause the Rights held by such holder to become void.
(e) Provisions that permit the Corporation to redeem the Rights.
(f) The appointment of a Rights Agent with respect to the Rights.
ARTICLE NINE
The Corporation shall have the power to indemnify its present or former directors, officers, employees and agents or any person who served or is serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise to the full extent permitted by the General Corporation Law of Delaware. Such indemnification shall not be deemed exclusive of any other rights to which such person may be entitled, under any bylaws, agreements, vote of stockholders or disinterested directors, or otherwise.
ARTICLE TEN
A director of the Corporation shall not be personally liable to the Corporation or its stockholders for monetary damages or breach of fiduciary duty as a director, except for liability (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 involved intentional misconduct or a knowing violation of law, (iii) under Section 174 of the Act, or, (iv) for any transaction from which the director derived an improper personal benefit.
IN WITNESS WHEREOF, this Restated Certificate of Incorporation has been signed under the seal of the Corporation this 21st day of April, 1998.
CROSS TIMBERS OIL COMPANY
[Seal]
Attest:
Appendix A
CERTIFICATE OF DESIGNATIONS
of
SERIES A CONVERTIBLE PREFERRED STOCK
of
CROSS TIMBERS OIL COMPANY
Pursuant to Section 151 of the
General Corporation Law of the State of Delaware
CROSS TIMBERS OIL COMPANY, a corporation organized and existing under the laws of the State of Delaware (the "Corporation"), does hereby certify that, pursuant to the authority conferred on the Board of Directors of the Corporation by the Certificate of Incorporation, as amended, of the Corporation and in accordance with Section 151 of the General Corporation Law of the State of Delaware, the Board of Directors of the Corporation (and, as to certain matters allowed by law, a duly authorized committee thereof) adopted the following resolution establishing a series of 1,138,735 shares of Preferred Stock of the Corporation designated as "Series A Convertible Preferred Stock":
RESOLVED, that pursuant to the authority conferred on the Board of Directors of this Corporation by the Restated Certificate of Incorporation, a series of Preferred Stock, par value $.01 per share, of the Corporation be and hereby is established and created, and that the designation and number of shares thereof and the voting and other powers, preferences and relative, participating, optional or other rights of the shares of such series and the qualifications, limitations and restrictions thereof are as follows:
Series A Convertible Preferred Stock
1. Designation and Amount. There shall be a series of Preferred Stock designated as "Series A Convertible Preferred Stock" and the number of shares constituting such series shall be 1,138,735. Such series is referred to herein as the "Series A Preferred Stock".
2. Par Value. The par value of each share of Series A Preferred Stock shall be $.01.
3. Rank. All shares of Series A Preferred Stock shall rank prior, both as to payment of dividends and as to distributions of assets upon liquidation, dissolution or winding up of the Corporation, whether voluntary or involuntary, to all of the Corporation's now or hereafter issued Common Stock, par value $.01 per share (the "Common Stock").
4. Dividends. The holders of Series A Preferred Stock shall be entitled to receive, when, as and if declared by the Board of Directors out of funds at the time legally available therefor, dividends at the rate of $1.5625 per annum per share, and no more, which shall be fully cumulative, shall accrue without interest from the date of first issuance of any shares of Series A Preferred Stock and shall be payable in cash quarterly in arrears on January 15, April 15, July 15 and October 15 of each year commencing January 15, 1997 (except that if any such date is a Saturday, Sunday or legal holiday, then such dividend shall be payable on the next day that is not a Saturday, Sunday or legal holiday) to holders of record as they appear on the stock transfer books of the Corporation on such record dates, not more than 60 days nor less than 10 days preceding the payment dates for such dividends, as are fixed by the Board of Directors (or, to the extent permitted by applicable law, a duly authorized committee thereof). For purposes hereof, the term "legal holiday" shall mean any day on which banking institutions are authorized to close in New York City, New York or in Dallas, Texas. Subject to the next paragraph of this Section 4, dividends on account of arrears for any past dividend period may be declared and paid at any time, without reference to any regular dividend payment date. The amount of dividends payable per share of Series A Preferred Stock for each quarterly dividend period shall be computed by dividing the annual dividend amount by four. The amount of dividends payable for the initial dividend period and any period shorter than a full quarterly dividend period shall be computed on the basis of a 360-day year of twelve 30-day months.
No dividends or other distributions, other than dividends payable solely in shares of Common Stock or other capital stock of the Corporation ranking junior as to dividends and as to liquidation rights to the Series A Preferred Stock, shall be declared, paid or set apart for payment on and no purchase, redemption or other acquisition shall be made by the Corporation of any shares of Common Stock or other capital stock of the Corporation ranking junior as to dividends to the Series A Preferred Stock (the Junior Dividend Stock) unless and until all accrued and unpaid dividends on the Series A Preferred Stock, including the full dividend for the then-current quarterly dividend period, shall have been paid or declared and set apart for payment.
If at any time any dividend on any capital stock of the Corporation ranking senior as to dividends to the Series A Preferred Stock (the "Senior Dividend Stock") shall be in default, in whole or in part, then (except to the extent allowed by the terms of such Senior Dividend Stock) no dividend shall be paid or declared and set apart for payment on the Series A Preferred Stock unless and until all accrued and unpaid dividends with respect to the Senior Dividend Stock, including the full dividends for the then-current dividend period, shall have been paid or declared and set apart for payment, without interest. No full dividends shall be paid or declared and set apart for payment on any class or series of the Corporation's capital stock ranking, as to dividends, on a parity with the Series A Preferred Stock (the "Parity Dividend Stock") for any period unless full cumulative dividends have been, or contemporaneously are, paid or declared and set apart for such payment on the Series A Preferred Stock for all dividend payment periods terminating on or prior to the date of payment of such full cumulative dividends. No full dividends shall be paid or declared and set apart for payment on the Series A Preferred Stock for any period unless full cumulative dividends have been, or contemporaneously are, paid or declared and set apart for payment on the Parity Dividend Stock for all dividend periods terminating on or prior to the date of payment of such full cumulative dividends. When dividends are not paid in full upon
the Series A Preferred Stock and the Parity Dividend Stock, all dividends paid or declared and set aside for payment upon shares of Series A Preferred Stock and the Parity Dividend Stock shall be paid or declared and set aside for payment pro rata so that the amount of dividends paid or declared and set aside for payment per share on the Series A Preferred Stock and the Parity Dividend Stock shall in all cases bear to each other the same ratio that accrued and unpaid dividends per share on the shares of Series A Preferred Stock and the Parity Dividend Stock bear to each other.
Any reference to "distribution" contained in this Section 4 shall not be deemed to include any distribution made in connection with any liquidation, dissolution or winding up of the Corporation, whether voluntary or involuntary.
5. Liquidation Preference. In the event of a liquidation, dissolution or winding up of the Corporation, whether voluntary or involuntary, the holders of Series A Preferred Stock shall be entitled to receive out of the assets of the Corporation, whether such assets are stated capital or surplus of any nature, an amount equal to the dividends accrued and unpaid thereon to the date of final distribution to such holders, whether or not declared, without interest, and a sum equal to $25.00 per share, and no more, before any payment shall be made or any assets distributed to the holders of Common Stock or any other class or series of the Corporation's capital stock ranking junior as to liquidation rights to the Series A Preferred Stock (the "Junior Liquidation Stock"); provided, however, that such rights shall accrue to the holders of Series A Preferred Stock only in the event that the Corporation's payments with respect to the liquidation preferences of the holders of capital stock of the Corporation ranking senior as to liquidation rights to the Series A Preferred Stock (the "Senior Liquidation Stock") are fully met. The entire assets of the Corporation available for distribution after the liquidation preferences of the Senior Liquidation Stock are fully met shall be distributed ratably among the holders of the Series A Preferred Stock and any other class or series of the Corporation's capital stock which may hereafter be created having parity as to liquidation rights with the Series A Preferred Stock in proportion to the respective preferential amounts to which each is entitled (but only to the extent of such preferential amounts). Neither a consolidation or merger of the Corporation with another corporation nor a sale or transfer of all or part of the Corporation's assets for cash, securities or other property will be considered a liquidation, dissolution or winding up of the Corporation.
6. Redemption at Option of the Corporation. The Corporation may not redeem the Series A Preferred Stock through October 15, 1999. The Corporation, at its option, may at any time during the 12-month period ending October 15, 2000 (but only if at the date on which notice of redemption shall be given during such period the closing price per share of Common Stock, determined as provided in Section 7(c)(iv) hereof, for any 20 trading days during any period of 30 successive trading days ending within three days of the date of such notice shall have equalled or exceeded 150% of the then prevailing conversion price (for all purposes an amount equal to $25.00 divided by the conversion rate applicable to one share of Series A Preferred Stock as in effect at such time) of the Series A Preferred Stock) and at any time during any succeeding 12-month period, redeem in whole at any time, or from time to time in part, the Series A Preferred Stock on any date set by the Board of Directors, at the following cash redemption prices per share: if redeemed during the 12-month period ending October 15 of the years indicated,
Price Price
Year Per Share Year Per Share
---- --------- ----- ---------
2000........ $26.09 2004........ $25.47
2001........ $25.94 2005........ $25.31
2002........ $25.78 2006........ $25.16
2003........ $25.63
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and thereafter at $25.00 per share, plus, in each case, an amount in cash equal to all dividends on the Series A Preferred Stock accrued and unpaid thereon, whether or not declared, pro rata to the date fixed for redemption, such sum being hereinafter referred to as the "Redemption Price".
In case of the redemption of less than all of the then outstanding Series A Preferred Stock, the Corporation shall designate by lot, or in such other manner as the Board of Directors may determine, the shares to be redeemed, or shall effect such redemption pro rata. Notwithstanding the foregoing, the Corporation shall not redeem less than all of the Series A Preferred Stock at any time outstanding until all dividends accrued and in arrears upon all Series A Preferred Stock then outstanding shall have been paid for all past dividend periods.
Not more than 60 nor less than 20 days prior to the redemption date, notice by first class mail, postage prepaid, shall be given to the holders of record of the Series A Preferred Stock to be redeemed, addressed to such stockholders at their last addresses as shown on the stock transfer books of the Corporation. Each such notice of redemption shall specify the date fixed for redemption, the Redemption Price, the place or places of payment, that payment will be made upon presentation and surrender of the shares of Series A Preferred Stock, that on and after the redemption date, dividends will cease to accumulate on such shares, the then-effective conversion rate pursuant to Section 7 and that the right of holders to convert shall terminate at the close of business on the date fixed for redemption with respect to any redemption occurring on or before the third business day after October 15, 1999, and, with respect to any redemption occurring thereafter, on the third business day prior to the redemption date (unless the Company defaults in the payment of the Redemption Price).
Any notice which is mailed as herein provided shall be conclusively presumed to have been duly given, whether or not the holder of the Series A Preferred Stock receives such notice; and failure to give such notice by mail, or any defect in such notice, to the holders of any shares designated for redemption shall not affect the validity of the proceedings for the redemption of any other shares of Series A Preferred Stock. On or after the date fixed for redemption as stated in such notice, each holder of the shares called for redemption shall surrender the certificate evidencing such shares to the Corporation at the place designated in such notice and shall thereupon be entitled to receive payment of the Redemption Price. If less than all the shares evidenced by any such surrendered certificate are redeemed, a new certificate shall be issued evidencing the unredeemed shares. If, on the date fixed for redemption, funds necessary for the redemption shall be available therefor and shall have been irrecoverably deposited or set aside, then, notwithstanding that the certificates evidencing any shares so called for redemption shall not have been surrendered, the dividends with respect to the shares so called shall cease to accrue after the date fixed for redemption, the shares shall no longer be deemed outstanding, the holders
thereof shall cease to be stockholders and all rights whatsoever with respect to the shares so called for redemption (except the right of the holders to receive the Redemption Price without interest upon surrender of their certificates therefor) shall terminate. If funds legally available for such purpose are not sufficient for redemption of the shares of Series A Preferred Stock which were to be redeemed, or if the Corporation is then or would be in default under any of its loan agreements after such redemption, then the certificates evidencing such shares shall be deemed not to be surrendered, such shares shall remain outstanding and the right of holders of shares of Series A Preferred Stock thereafter shall continue to be only those of a holder of shares of a series of Preferred Stock of the Corporation referred to herein as Series A Preferred Stock.
The shares of Series A Preferred Stock shall not be subject to the operation of any purchase, retirement or sinking fund.
7. Conversion Privilege.
(a) Right of Conversion. Each share of Series A Preferred Stock shall be convertible at the option of the holder thereof, at any time prior to the close of business on the third business day prior to the date fixed for redemption of such share as herein provided, into fully paid and nonassessable shares of Common Stock and such other securities and property as hereinafter provided, initially at the rate of .961538 of one share of Common Stock for each full share of Series A Preferred Stock.
For the purpose of this Section 7, the term "Common Stock" shall initially mean the class designated as Common Stock, par value $.01 per share, of the Corporation, subject to adjustment as hereinafter provided.
(b) Conversion Procedures. Any holder of shares of Series A Preferred Stock desiring to convert such shares into Common Stock shall surrender the certificate or certificates evidencing such shares of Series A Preferred Stock at the office of the transfer agent for the Series A Preferred Stock, which certificate or certificates, if the Corporation shall so require, shall be duly endorsed to the Corporation or in blank or accompanied by proper instruments of transfer to the Corporation or in blank, accompanied by irrevocable written notice to the Corporation that the holder elects so to convert such shares of Series A Preferred Stock and specifying the name or names (with address) in which a certificate or certificates evidencing shares of Common Stock are to be issued.
No adjustments in respect of dividends on shares surrendered for conversion or any dividend on the Common Stock issued upon conversion shall be made upon the conversion of any shares of Series A Preferred Stock.
The Corporation shall, as soon as practicable after such deposit of certificates evidencing shares of Series A Preferred Stock accompanied by the written notice and compliance with any other conditions herein contained, deliver at such office of such transfer agent to the person for whose account such shares of Series A Preferred Stock were so surrendered, or to the nominee or nominees of such person, certificates evidencing the number of full shares of Common Stock
to which such person shall be entitled as aforesaid, together with a cash adjustment of any fraction of a share as hereinafter provided. Subject to the following provisions of this paragraph, such conversion shall be deemed to have been made as of the date of such surrender of the shares of Series A Preferred Stock to be converted, and the person or persons entitled to receive the Common Stock deliverable upon conversion of such Series A Preferred Stock shall be treated for all purposes as the record holder or holders of such Common Stock on such date; provided, however, that the Corporation shall not be required to convert any shares of Series A Preferred Stock while the stock transfer books of the Corporation are closed for any purpose, but the surrender of Series A Preferred Stock for conversion during any period while such books are so closed shall become effective for conversion immediately upon the reopening of such books as if the surrender had been made on the date of such reopening, and the conversion shall be at the conversion rate in effect on such date.
(c) Adjustment of Conversion Rate. The number of shares of Common Stock and number or amount of any other securities and property as hereinafter provided into which a share of Series A Preferred Stock is convertible (the "conversion rate") shall be subject to adjustment from time to time as follows:
(i) In case the Corporation shall (1) pay a dividend or make a distribution on its Common Stock that is paid or made (A) in other shares of stock of the Corporation or (B) in rights to purchase stock or other securities if such rights are not separable from the Common Stock except upon the occurrence of a contingency, (2) subdivide its outstanding shares of Common Stock into a greater number of shares or (3) combine its outstanding shares of Common Stock into a smaller number of shares, then in each such case the conversion rate in effect immediately prior thereto shall be adjusted retroactively so that the holder of any shares of Series A Preferred Stock thereafter surrendered for conversion shall be entitled to receive the number of shares of Common Stock and other shares and rights to purchase stock or other securities (or, in the event of the redemption of any such shares or rights, any cash, property or securities paid in respect of such redemption) which such holder would have owned or have been entitled to receive after the happening of any event described above had such shares of Series A Preferred Stock been converted immediately prior to the happening of such event. An adjustment made pursuant to this subparagraph (i) shall become effective immediately after the record date in the case of a dividend or distribution and shall become effective immediately after the effective date in the case of a subdivision or combination.
(ii) In case the Corporation shall issue rights or warrants to all holders of its Common Stock entitling them (for a period expiring within 45 days after the date fixed for determination mentioned below) to subscribe for or purchase shares of Common Stock at a price per share less than the current market price per share (determined as provided below) of the Common Stock on the date fixed for the determination of stockholders entitled to receive such rights or warrants, then the conversion rate in effect at the opening of business on the day following the date fixed for such determination shall be increased by multiplying such conversion rate by a fraction of which the numerator shall be the number of shares of Common Stock outstanding at the close of business on the date fixed
for such determination plus the number of shares of Common Stock so offered for subscription or purchase and the denominator shall be the number of shares of Common Stock outstanding at the close of business on the date fixed for such determination plus the number of shares of Common Stock which the aggregate of the offering price of the total number of shares of Common Stock so offered for subscription or purchase would purchase at such current market price, such increase to become effective immediately after the opening of business on the day following the date fixed for such determination; provided, however, that in the event that all the shares of Common Stock offered for subscription or purchase are not delivered upon the exercise of such rights or warrants, upon the expiration of such rights or warrants the conversion rate shall be readjusted to the conversion rate which would have been in effect had the numerator and the denominator of the foregoing fraction and the resulting adjustment been made based upon the number of shares of Common Stock actually delivered upon the exercise of such rights or warrants, rather than upon the number of shares of Common Stock offered for subscription or purchase. For the purposes of this subparagraph (ii), the number of shares of Common Stock at any time outstanding shall not include shares held in the treasury of the Corporation.
(iii) In case the Corporation shall by dividend or otherwise, distribute to all holders of its Common Stock evidences of its indebtedness, cash (excluding ordinary cash dividends paid out of retained earnings of the Corporation), other assets or rights or warrants to subscribe for or purchase any security (excluding those referred to in subparagraphs (i) and (ii) above), then in each such case the conversion rate shall be adjusted retroactively so that the same shall equal the rate determined by multiplying the conversion rate in effect immediately prior to the close of business on the date fixed for the determination of stockholders entitled to receive such distribution by a fraction of which the numerator shall be the current market price per share (determined as provided below) of the Common Stock on the date fixed for such determination and the denominator shall be such current market price per share of the Common Stock less the amount of cash and the then fair market value (as determined by the Board of Directors, whose determination shall be conclusive and described in a resolution of the Board of Directors) of the portion of the assets, rights or evidences of indebtedness so distributed applicable to one share of Common Stock, such adjustment to become effective immediately prior to the opening of business on the day following the date fixed for the determination of stockholders entitled to receive such distribution.
(iv) For the purpose of any computation under subparagraphs (ii) and
(iii), the current market price per share of Common Stock on any date shall
be deemed to be the average of the daily closing prices for the 20
consecutive trading days commencing with the 30th trading day before the
day in question. The closing price for each day shall be the reported last
sales price regular way or, in case no such reported sale takes place on
such day, the average of the reported closing bid and asked prices regular
way, in either case on the New York Stock Exchange or, if the Common Stock
is not listed or admitted to trading on such Exchange, on the principal
national securities exchange on which the Common Stock is listed or
admitted to trading (based on the aggregate dollar value of all
securities listed or admitted to trading) or, if not listed or admitted to trading on any national securities exchange, on the NASDAQ National Market System or, if the Common Stock is not listed or admitted to trading on any national securities exchange or quoted on the NASDAQ National Market System, the average of the closing bid and asked prices in the over-the- counter market as furnished by any New York Stock Exchange member firm selected from time to time by the Corporation for that purpose, or, if such prices are not available, the fair market value set by, or in a manner established by, the Board of Directors of the Corporation in good faith. "Trading day" shall mean a day on which the national securities exchange or the NASDAQ National Market System used to determine the closing price is open for the transaction of business or the reporting of trades or, if the closing price is not so determined, a day on which the New York Stock Exchange is open for the transaction of business.
(v) No adjustment in the conversion rate shall be required unless such adjustment would require an increase or decrease of at least 1% in such rate; provided, however, that the Corporation may make any such adjustment at its election; and provided, further, that any adjustments which by reason of this subparagraph (v) are not required to be made shall be carried forward and taken into account in any subsequent adjustment. All calculations under this Section 7 shall be made to the nearest cent or to the nearest one-hundredth of a share, as the case may be.
(vi) Whenever the conversion rate is adjusted as provided in any provision of this Section 7:
(1) the Corporation shall compute the adjusted conversion rate in accordance with this Section 7 and shall prepare a certificate signed by the principal financial officer of the Corporation setting forth the adjusted conversion rate and showing in reasonable detail the facts upon which such adjustment is based, and such certificate shall forthwith be filed with the transfer agent of the Series A Preferred Stock; and
(2) a notice stating that the conversion rate has been adjusted and setting forth the adjusted conversion rate shall forthwith be required, and as soon as practicable after it is required, such notice shall be mailed by the Corporation to all record holders of Series A Preferred Stock at their last addresses as they shall appear in the stock transfer books of the Corporation.
(vii) In the event that at any time, as a result of any adjustment made pursuant to this Section 7, the holder of any shares of Series A Preferred Stock thereafter surrendered for conversion shall become entitled to receive any shares of the Corporation other than shares of Common Stock or to receive any other securities, the number of such other shares or securities so receivable upon conversion of any share of Series A Preferred Stock shall be subject to adjustment from time to time in a manner and on terms as nearly equivalent as practicable to the provisions contained in this Section 7 with respect to the Common Stock.
(d) No Fractional Shares. No fractional shares or scrip representing fractional shares of Common Stock shall be issued upon conversion of Series A Preferred Stock. If more than one certificate evidencing shares of Series A Preferred Stock shall be surrendered for conversion at one time by the same holder, the number of full shares issuable upon conversion thereof shall be computed on the basis of the aggregate number of shares of Series A Preferred Stock so surrendered. Instead of any fractional share of Common Stock which would otherwise be issuable upon conversion of any shares of Series A Preferred Stock, the Corporation shall pay a cash adjustment in respect of such fractional interest in an amount equal to the same fraction of the market price per share of Common Stock (as determined by the Board of Directors or in any manner prescribed by the Board of Directors, which, so long as the Common Stock is listed on the New York Stock Exchange, shall be the reported last sale price regular way on the New York Stock Exchange) at the close of business on the day of conversion.
(e) Reclassification, Consolidation, Merger or Sale of Assets. In case of any reclassification of the Common Stock, any consolidation of the Corporation with, or merger of the Corporation into, any other person, any merger of another person into the Corporation (other than a merger which does not result in any reclassification, conversion, exchange or cancellation of outstanding shares of Common Stock of the Corporation), any sale or transfer of all or substantially all of the assets of the Corporation or any compulsory share exchange, pursuant to which share exchange the Common Stock is converted into other securities, cash or other property, then lawful provision shall be made as part of the terms of such transaction whereby the holder of each share of Series A Preferred Stock then outstanding shall have the right thereafter, during the period such share shall be convertible, to convert such share only into the kind and amount of securities, cash and other property receivable upon such reclassification, consolidation, merger, sale, transfer or share exchange by a holder of the number of shares of Common Stock of the Corporation into which such share of Series A Preferred Stock might have been converted immediately prior to such reclassification, consolidation, merger, sale, transfer or share exchange. The Corporation, the person formed by such consolidation or resulting from such merger or which acquires such assets or which acquires the Corporation's shares, as the case may be, shall make provisions in its certificate or articles of incorporation or other constituent document to establish such right. Such certificate or articles of incorporation or other constituent document shall provide for adjustments which, for events subsequent to the effective date of such certificate or articles of incorporation or other constituent document, shall be as nearly equivalent as may be practicable to the adjustments provided for in this Section 7. The above provisions shall similarly apply to successive reclassifications, consolidations, mergers, sales, transfers or share exchanges.
(f) Reservation of Shares; Transfer Taxes; Etc. The Corporation shall at all times reserve and keep available, out of its authorized and unissued stock, solely for the purpose of effecting the conversion of the Series A Preferred Stock, such number of shares of its Common Stock free of preemptive rights as shall from time to time be sufficient to effect the conversion of all shares of Series A Preferred Stock from time to time outstanding. The Corporation shall from time to time, in accordance with the laws of the State of Delaware, increase the authorized number of shares of Common Stock if at any time the number of shares of Common Stock not outstanding shall not be sufficient to permit the conversion of all the then-outstanding shares of Series A Preferred Stock.
If any shares of Common Stock required to be reserved for purposes of conversion of the Series A Preferred Stock hereunder require registration with or approval of any governmental authority under any Federal or State law before such shares may be issued upon conversion, the Corporation will in good faith and as expeditiously as possible endeavor to cause such shares to be duly registered or approved, as the case may be. If the Common Stock is listed on the New York Stock Exchange or any other national securities exchange, the Corporation will if permitted by the rules of such exchange, list and keep listed on such exchange, upon official notice of issuance, all shares of Common Stock issuable upon conversion of the Series A Preferred Stock.
The Corporation shall pay any and all issue or other taxes that may be payable in respect of any issue or delivery of shares of Common Stock on conversion of the Series A Preferred Stock. The Corporation shall not, however, be required to pay any tax which may be payable in respect of any transfer involved in the issue or delivery of Common Stock (or other securities or assets) in a name other than that in which the shares of Series A Preferred Stock so converted were registered, and no such issue or delivery shall be made unless and until the person requesting such issue has paid to the Corporation the amount of such tax or has established, to the satisfaction of the Corporation, that such tax has been paid.
Before taking any action which would cause an adjustment reducing the conversion rate, such that the effective conversion price (for all purposes an amount equal to $25.00 divided by the conversion rate applicable to one share of Series A Preferred Stock as in effect at such time) would be below the then par value of the Common Stock, the Corporation shall take any corporate action which may, in the opinion of its counsel, be necessary in order that the Corporation may validly and legally issue fully paid and nonassessable shares of Common Stock at the conversion rate as so adjusted.
(g) Prior Notice of Certain Events. In case:
(i) the Corporation shall (1) declare any dividend (or any other distribution) on its Common Stock, other than (A) a dividend payable in shares of Common Stock or (B) a dividend payable in cash out of its retained earnings other than any special or nonrecurring or other extraordinary dividend or (2) declare or authorize a redemption or repurchase of in excess of 10% of the then-outstanding shares of Common Stock; or
(ii) the Corporation shall authorize the granting to the holders of Common Stock of rights or warrants to subscribe for or purchase any shares of stock of any class or of any other rights or warrants (other than any rights specified in paragraph (c)(i)(1)(B) of this Section 7); or
(iii) of any reclassification of Common Stock (other than a subdivision or combination of the outstanding Common Stock, or a change in par value, or from par value to no par value, or from no par value to par value), or of any consolidation or merger to which the Corporation is a party and for which approval of any stockholders of the Corporation shall be required, or of the sale or transfer of all or substantially all of the
assets of the Corporation or of any compulsory share exchange whereby the Common Stock is converted into other securities, cash or other property; or
(iv) of the voluntary or involuntary dissolution, liquidation or winding up of the Corporation;
then the Corporation shall cause to be filed with the transfer agent for the Series A Preferred Stock, and shall cause to be mailed to the holders of record of the Series A Preferred Stock, at their last address as they shall appear upon the stock transfer books of the Corporation, at least 15 days prior to the applicable record date hereinafter specified, a notice stating (x) the date on which a record (if any) is to be taken for the purpose of such dividend, distribution, redemption, repurchase or granting of rights or warrants or, if a record is not to be taken, the date as of which the holders of Common Stock of record to be entitled to such dividend, distribution, redemption, rights or warrants are to be determined or (y) the date on which such reclassification, consolidation, merger, sale, transfer, share exchange, dissolution, liquidation or winding up is expected to become effective, and the date as of which it is expected that holders of Common Stock of record shall be entitled to exchange their shares of Common Stock for securities or other property deliverable upon such reclassification, consolidation, merger, sale, transfer, share exchange, dissolution, liquidation or winding up (but no failure to mail such notice or any defect therein or in the mailing thereof shall affect the validity of the corporate action required to be specified in such notice).
(h) Other Changes in Conversion Rate. The Corporation from time to time may increase the conversion rate by any amount for any period of time if the period is at least 20 days and if the increase is irrevocable during the period. Whenever the conversion rate is so increased, the Corporation shall mail to holders of record of the Series A Preferred Stock a notice of the increase at least 15 days before the date the increased conversion rate takes effect and such notice shall state the increased conversion rate and the period it will be in effect.
The Corporation may make such increases in the conversion rate, in addition to those required or allowed by this Section 7, as shall be determined by it, as evidenced by a resolution of the Board of Directors, to be advisable in order to avoid or diminish any income tax to holders of Common Stock resulting from any dividend or distribution of stock or issuance of rights or warrants to purchase or subscribe for stock or from any event treated as such for income tax purposes.
8. Voting Rights.
(a) General. Except as set forth in Section 7(b) or as otherwise required by law, the holder of each share of Series A Preferred Stock shall be entitled to the number of votes equal to the number of shares of Common Stock into which such share of Series A Preferred Stock could be converted at the record date for determination of the stockholders entitled to vote on such matters, such votes to be counted together with all other shares of capital stock of the Company having general voting power and not separately as a class or series. Holders of Series A Preferred Stock shall be entitled to receive the same notice of any stockholders' meeting as is provided to
holders of Common Stock. Fractional votes by the holders of Series A Preferred Stock shall not, however, be permitted, and any fractional voting rights shall (after aggregating all shares into which shares of Series A Preferred Stock held by each holder could be converted) be rounded to the nearest whole number. The Company will, or will cause its transfer agent or registrar to, transmit to the registered holders of the Series A Preferred Stock all reports and communications from the Company that are generally mailed to holders of its Common Stock.
(b) Default Voting Rights. Whenever dividends on the Series A Preferred Stock or any other class or series of Preferred Stock ranking as to dividends on a parity with the Series A Preferred Stock shall be in arrears in an amount equal to at least six quarterly dividends (whether or not consecutive), (i) the number of members of the Board of Directors of the Corporation shall be increased by two, effective as of the time of election of such directors as hereinafter provided and (ii) the holders of the Series A Preferred Stock (voting separately as a class with all other holders of shares of any one or more other series of Preferred Stock ranking as to dividends on a parity with the Series A Preferred Stock upon which like voting rights have been conferred and are exercisable) will have the exclusive right to vote for and elect such two additional directors of the Corporation at any meeting of stockholders of the Corporation at which directors are to be elected held during the period such dividends remain in arrears. The right of the holders of the Series A Preferred Stock to vote for such two additional directors shall terminate when all accrued and unpaid dividends on the Series A Preferred Stock have been declared and paid or set apart for payment. The term of office of all directors so elected shall terminate immediately upon the termination of the right of the holders of the Series A Preferred Stock and such other series of Preferred Stock ranking as to dividends on a parity with the Series A Preferred Stock to vote for such two additional directors.
The foregoing right of holders of the Series A Preferred Stock with respect to the election of two directors may be exercised at any annual meeting of stockholders or at any special meeting of stockholders held for such purpose. If the right to elect directors shall have accrued to the holders of the Series A Preferred Stock more than 90 days preceding the date established for the next annual meeting of stockholders, the Chairman of the Board of the Corporation shall, within 20 days after the delivery to the Corporation at its principal office of a written request for a special meeting signed by the holders of at least 10% of the Series A Preferred Stock then outstanding, call a special meeting of the holders of the Series A Preferred Stock to be held within 60 days after the delivery of such request for the purpose of electing such additional directors.
The holders of the Series A Preferred Stock and any such other series of Preferred Stock ranking as to dividends on a parity with the Series A Preferred Stock referred to above voting as a class shall have the right to remove without cause at any time and replace any directors such holders shall have elected pursuant to this Section 8(b).
(c) Class Voting Rights. So long as the Series A Preferred Stock is outstanding, the Corporation shall not, without the affirmative vote or consent of the holders of at least 66-2/3% of all outstanding Series A Preferred Stock voting separately as a class, (i) amend, alter or repeal (by merger or otherwise) any provision of the Certificate of Incorporation or the By-Laws of the Corporation as amended, so as adversely to affect the relative rights, preferences, qualifications,
limitations or restrictions of the Series A Preferred Stock, (ii) authorize or issue, or increase the authorized amount of, any additional class or series of stock, or any security convertible into stock of such class or series, ranking prior to the Series A Preferred Stock in respect of the payment of dividends or upon liquidation, dissolution or winding up of the Corporation or (iii) effect any reclassification of the Series A Preferred Stock. A class vote on the part of the Series A Preferred Stock shall, without limitation, specifically not be deemed to be required (except as otherwise required by law or resolution of the Corporation's Board of Directors) in connection with: (a) the authorization, issuance or increase in the authorized amount of any shares of any other class or series of stock which ranks junior to, or on a parity with, the Series A Preferred Stock in respect of the payment of dividends and distributions upon liquidation, dissolution or winding up of the Corporation; or (b) the authorization, issuance or increase in the amount of any bonds, mortgages, debentures or other obligations of the Corporation.
9. Outstanding Shares. For purposes of this Certificate of Designations, all shares of Series A Preferred Stock shall be deemed outstanding except (i) from the date fixed for redemption pursuant to Section 6 hereof, all shares of Series A Preferred Stock that have been so called for redemption under Section 6; (ii) from the date of surrender of certificates evidencing shares of Series A Preferred Stock, all shares of Series A Preferred Stock converted into Common Stock; and (iii) from the date of registration of transfer, all shares of Series A Preferred Stock held of record by the Corporation or any subsidiary of the Corporation.
10. Partial Payments. Upon an optional redemption by the Corporation, if at any time the Corporation does not pay amounts sufficient to redeem all Series A Preferred Stock, then such funds which are paid shall be applied to redeem such Series A Preferred Stock as the Corporation may designate by lot.
11. Status of Acquired Shares. Shares of Series A Preferred Stock redeemed by the Corporation, received upon conversion pursuant to Section 7 or otherwise acquired by the Corporation will be restored to the status of authorized but unissued shares of Preferred Stock, without designation as to class, and may thereafter be issued, but not as shares of Series A Preferred Stock.
12. Preemptive Rights. The Series A Preferred Stock is not entitled to any preemptive or subscription rights in respect of any securities of the Corporation.
13. Severability of Provisions. Whenever possible, each provision hereof shall be interpreted in a manner as to be effective and valid under applicable law, but if any provision hereof is held to be prohibited by or invalid under applicable law, such provision shall be ineffective only to the extent of such prohibition or invalidity, without invalidating or otherwise adversely affecting the remaining provisions hereof. If a court of competent jurisdiction should determine that a provision hereof would be valid or enforceable if a period of time were extended or shortened or a particular percentage were increased or decreased then such court may make such change as shall be necessary to render the provision in question effective and valid under applicable law.
EXHIBIT 5.1
Kelly, Hart & Hallman
(a professional corporation)
201 Main Street, Suite 2500
Fort Worth, Texas 76102
March 16, 1999
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, Texas 76102
Gentlemen:
This firm has acted as counsel to Cross Timbers Oil Company, a Delaware corporation (the "Company"), in connection with the filing by the Hugoton Royalty Trust (the "Trust") and the Company of a registration statement on Form S-1/S-3, No. 333-68441 (the "Registration Statement"), with the Securities and Exchange Commission pursuant to the Securities Act of 1933, as amended, for the registration of the sale of up to 17,250,000 units of beneficial interest in the Trust (the "Trust Units"). The opinion set forth below is given pursuant to Item 601(b)(5) of Regulation S-K for inclusion as Exhibit 5.1 to the Registration Statement and pertains to the offering of such Trust Units.
In connection with this opinion, we have made the following assumptions:
(i) all documents submitted to or reviewed by us, including all amendments and
supplements thereto, are accurate and complete and if not originals are true and
correct copies of the originals; (ii) the signatures on each of such documents
by the parties thereto are genuine; (iii) each individual who signed such
documents had the legal capacity to do so; and (iv) all persons who signed such
documents on behalf of a corporation were duly authorized to do so. We have
assumed that there are no amendments, modifications or supplements to such
documents other than those amendments, modifications and supplements that are
known to us.
Based on the foregoing, and subject to the limitations and qualifications set forth herein, we are of the opinion that:
1. The Trust was formed and is validly existing under the laws of the State of Texas.
2. The Trust Units have been duly authorized and are validly issued under the laws of the State of Texas, fully paid and non- assessable.
Cross Timbers Oil Company
March 16, 1999
For purposes of this opinion, "non-assessable" means that neither the trust nor the trustee can assess a trust unitholder for additional consideration with respect to the purchase or ownership of his trust units.
This opinion is further limited and qualified in all respects as follows:
A. The opinion is specifically limited to matters of the existing laws of the State of Texas. We express no opinion as to the applicability of the laws of any other particular jurisdiction to the transactions described in this opinion.
B. This opinion is limited to the specific opinions stated herein, and no other opinion is implied or may be inferred beyond the specific opinions expressly stated herein.
C. This opinion is based on our knowledge of the law and facts as of the date hereof. We assume no duty to update or supplement this opinion to reflect any facts or circumstances that may hereafter come to our attention or to reflect any changes in any law that may hereafter occur or become effective.
We call your attention to the fact that certain members of the law firm have directly or indirectly invested in the Company's common stock.
This opinion is intended solely for your benefit. It is not to be quoted in whole or in part, disclosed, made available to or relied upon by any other person, firm or entity without our express prior written consent.
We hereby consent to the use of this opinion in the above-referenced Registration Statement. In giving such consent, we do not admit that we come within the category of persons whose consent is required under Section 7 of the Securities Act of 1933, as amended, or the rules and regulations of the Securities and Exchange Commission promulgated thereunder.
Respectfully submitted,
/s/ KELLY, HART & HALLMAN
KELLY, HART & HALLMAN
(a professional corporation)
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EXHIBIT 10.1.1
NET OVERRIDING ROYALTY CONVEYANCE
Hugoton Royalty Trust
STATE OF KANSAS (S)
(S)
COUNTIES OF FINNEY, (S) KNOW ALL MEN BY THESE PRESENTS:
GRANT, HASKELL, KEARNY, (S)
MEADE, MORTON, SEWARD, (S)
AND STEVENS (S)
|
THAT CROSS TIMBERS OIL COMPANY, a corporation formed under the laws of the State of Delaware ("Assignor"), for and in consideration of the sum of Ten Dollars ($10.00) and other good and valuable consideration to Assignor paid by NATIONSBANK, N.A., a bank organized under the laws of the United States, acting not in its individual corporate capacity but solely as trustee under that certain Trust Indenture establishing the Hugoton Royalty Trust dated as of December 1, 1998 ("Assignee"), the receipt and sufficiency of which are hereby acknowledged, has bargained, sold, granted, conveyed, transferred, assigned, set over and delivered, and by these presents does bargain, sell, grant, convey, transfer, assign, set over and deliver unto Assignee a net overriding royalty interest ("the Royalty Interest") in and to the Subject Hydrocarbons in and under, and if, as and when produced, saved and sold from, the Subject Lands during the term of the Subject Interests on and after the Effective Date equal to eighty percent (80%) of the Net Proceeds attributable to the Subject Interests, as each of the above capitalized words is defined in Article I hereof and all as more fully provided herein.
TO HAVE AND TO HOLD the Royalty Interest, together with all and singular the rights and appurtenances thereto in anywise belonging, unto Assignee, its successors and assigns, subject, however, to the terms and provisions of this Conveyance; and Assignor does by these presents bind and obligate itself, its successors and assigns, to WARRANT and FOREVER defend all and singular the Royalty Interest unto the said Assignee, its successors and assigns, against every person whomsoever lawfully claiming or to claim the same or any part thereof by, through or under Assignor, but not otherwise.
ARTICLE I
DEFINITIONS
As used herein, the following words, terms or phrases have the following meanings:
SECTION 1.01. "Affiliate" means, as to the party specified, any Person controlling, controlled by or under common control with such party, with the concept of control in such context meaning the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of another, whether through the ownership of voting securities, by contract or otherwise. The Trust shall not be deemed an Affiliate of Assignor.
SECTION 1.02. "Assignor" means the Assignor named herein while Assignor owns all or any part of or interest in the Subject Interests and any other Person or Persons (excluding Assignee) who hereafter may acquire all or any part of or interest in the Subject Interests.
SECTION 1.03. "Assignee" means the Assignee named herein (and any successor Trustee under the Trust Indenture) while it owns all or any part of or interest in the Royalty Interest and any other Person or Persons who may acquire legal title to all or any part of or interest in the Royalty Interest.
SECTION 1.04. "Computation Period" means (i) initially, the period commencing on the Effective Date and ending on February 28, 1999, and (ii) each calendar month thereafter.
SECTION 1.05. "Conveyance" means this Net Overriding Royalty Conveyance.
SECTION 1.06. "Effective Date" means 7:00 o'clock A.M., local time in effect at the location of each Subject Interest, on December 1, 1998.
SECTION 1.07. "Excess Production Costs" means, for any Computation Period, an amount equal to the excess, if any, of Production Costs for such Computation Period over Gross Proceeds for such Computation Period.
SECTION 1.08. "Existing Sales Contracts" means all contracts and agreements in effect as of the Effective Date between or among Assignor and any Affiliate of Assignor, or between or among any Affiliates of Assignor, for the Sale, Processing, treatment, compression, gathering or transportation of Subject Hydrocarbons.
SECTION 1.09. "Gross Proceeds" means, for any Computation Period other than during the period from the Effective Date through January 31, 2000, and subject to Section 2.01 (i) during the term of the Existing Sales Contracts, the proceeds received by Assignor under the Existing Sales Contracts attributable to the Sale of Subject Hydrocarbons produced after the Effective Date and Sold during such Computation Period by Assignor after the Effective Date, and (ii) as to Subject Hydrocarbons produced after the Effective Date and Sold by Assignor during such Computation Period after the Effective Date other than under the Existing Sales Contracts (A) if Sold under a Sales Contract with a Non-Affiliate of Assignor, the proceeds received by Assignor under such Sales Contract, or (B) if Sold under a Sales Contract with an Affiliate of Assignor, the proceeds received by Assignor under such Sales Contract but in no event less than 98% of the proceeds received by such Affiliate upon the resale of such Subject Hydrocarbons to a Non-Affiliate of Assignor, and (iii) the proceeds received by Assignor in respect of underproduced gas imbalances attributable to the Subject Interests as of the Effective Date. "Gross Proceeds" means, for any Computation Period included in the period from the Effective Date through January 31, 2000, the sum of (i) for all Subject Hydrocarbons other than gas and natural gas liquids, if any, extracted from gas by Processing, the Gross Proceeds thereof, as defined above, and (ii) for that portion of the Subject Hydrocarbons that is gas and natural gas liquids, if any, extracted from gas by Processing, the greater of (A) an imputed amount computed as if all gas for which proceeds are received attributed to the Subject Interests during the period relevant to such Computation Period was sold for a price of $2.00 per thousand cubic feet at the wellhead, and (B) the Gross Proceeds of the Sale thereof computed
on the basis provided for Computation Periods other than during the period from the Effective Date through January 31, 2000; provided, however, that such computation under clause (B) above of this sentence shall be modified as needed to yield the weighted average sales price of all (gas and natural gas liquids, if any, extracted from gas by Processing) Sold that is included within Subject Hydrocarbons under all conveyances from Assignor to the Trust, not limited to this Conveyance. For purposes hereof, the "weighted average sales price of all gas" shall be determined for any Computation Period by dividing (A) the Gross Proceeds of the Sale of gas and natural gas liquids, if any, extracted from gas by Processing for such Computation Period (determined as provided above for all Computation Periods other than during the period from the Effective Date through January 31, 2000) attributable to any Subject Interests in which the Trust has a Royalty Interest ( and including Royalty Interests conveyed to the trust by Assignor under conveyances other than this Conveyance) by (B) the volume of such gas (in thousand cubic feet) attributable to such Subject Interests for such Computation Period. In all instances, the definition of "Gross Proceeds" shall be subject to the following:
(a) There shall be excluded from Gross Proceeds all Property Taxes that are deducted or excluded from proceeds of Sale received by Assignor and, for purposes of the calculation of Gross Proceeds under clause (ii)(A) of the second sentence of this Section 1.09, there shall also be excluded the amount of any additional Property Taxes that would have been paid by Assignor or withheld from Assignor if the imputed Sale price set forth therein had been the actual Sale price.
(b) There shall be excluded any amount for Subject Hydrocarbons attributable to nonconsent operations conducted with respect to the Subject Interests (or any portion thereof) as to which Assignor shall be a nonconsenting party and which is dedicated to the recoupment or reimbursement of costs and expenses of the consenting party or parties by the terms of the relevant operating agreement, unit agreement, contract for development or other instrument providing for such nonconsent operations. Assignor agrees that its election not to participate in such operations shall be made in conformity with the provisions of Section 6.01 of this Conveyance, but third persons shall not be under any duty to determine that such election so conformed.
(c) There shall be excluded any amount which Assignor shall receive as any of the following: consideration for transfer or sale of any of the Subject Interests (subject to the Royalty Interest) or equipment or other personal property or fixtures on the Subject Lands; payments for gas not taken, when such payments are made (but to the extent such payments are allocated to gas taken in the future such payments shall be included without interest in Gross Proceeds when such gas is taken); damages arising from any cause other than drainage or reservoir injury; rental for reservoir use; payments made to Assignor in connection with the drilling of any well on any of the Subject Lands or lands in the vicinity thereof (such exclusion including dry and bottom hole payments, provided that if such well is drilled on the Subject Lands and Assignor incurs Production Costs in connection therewith such payments shall reduce Production Costs) or in connection with any adjustment of any well and leasehold equipment upon unitization of any of the Subject Interests; provided there shall be included in Gross Proceeds advance or prepaid payments for future production received by Assignor to the extent not subject to repayment in the event of insufficient subsequent
production (and to the extent so subject to repayment shall be included without interest in Gross Proceeds when the Subject Hydrocarbons on which such payment was so advanced or prepaid are actually produced) and payments made to Assignor in connection with the deferring of drilling of any well on any of the Subject Lands (including payments from an operator in the vicinity for refraining from drilling an offset well).
(d) There shall be excluded any amount for Subject Hydrocarbons lost in the production or marketing thereof or used by Assignor in conformity with ordinary or prudent practices for drilling, production and plant operations (including gas injection, secondary recovery, pressure maintenance, repressuring, cycling operations, plant fuel or shrinkage) conducted for the purpose of drilling for, producing or Processing Subject Hydrocarbons or for operations on any unit or plant to which the Subject Interests are committed, but only so long as such Subject Hydrocarbons are so used.
(e) Amounts received as a loan by Assignor from a purchaser of Subject Hydrocarbons, whether with or without interest, shall not be considered to be derived from the sale of Subject Hydrocarbons.
(f) If a controversy or possible controversy exists (whether by reason of any statute, order, decree, rule, regulation, contract or otherwise) between Assignor and any purchaser as to the correct sales price of any Subject Hydrocarbons or, for any other reason, as to Assignor's right to receive or collect the proceeds of sale of any Subject Hydrocarbons, then
(i) amounts withheld by the purchaser or deposited by it with an escrow agent shall not be considered to be received by Assignor until actually collected by Assignor, but the amounts received by Assignor shall include any interest, penalty or other amount paid to Assignor in respect thereof;
(ii) amounts received by Assignor and promptly deposited by it with an escrow agent shall not be considered to have been received by Assignor, but all amounts thereafter paid to Assignor by such escrow agent shall be considered to be amounts received from the Sale of Subject Hydrocarbons; and
(iii) amounts received by Assignor and not deposited with an
escrow agent shall be considered to be received for purposes of this
Section 1.09.
SECTION 1.10. "Hydrocarbons" means oil, gas (which term includes coal bed gas, coal seam gas and methane) and all other minerals produced in association with oil or gas (including, but not limited to, helium, sulphur and carbon dioxide), but excluding all other minerals, whether similar or dissimilar.
SECTION 1.11. "Monthly Record Date" for each month means the close of business on the last day of such month which 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, unless Assignee determines that a different date is required to comply with applicable law or the rules of
a securities exchange or quotation system pursuant to the terms of the Trust Indenture, in which event it means such different date.
SECTION 1.12. "Net Proceeds" means, for any Computation Period, the excess of Gross Proceeds for such Computation Period over Production Costs for such Computation Period.
SECTION 1.13. "Non-Affiliate" means, as to the party specified, any Person who is not an Affiliate of such party.
SECTION 1.14. "Person" means any individual, corporation, partnership, limited liability company, trust, estate or other entity, organization or association.
SECTION 1.15. "Prime Interest Rate" means the variable rate of interest most recently announced by NationsBank, N.A. as its "prime rate."
SECTION 1.16. "Process" or "Processing" means to extract or otherwise recover natural gas liquids from natural gas included in the Subject Hydrocarbons through the processes of absorption, condensation, adsorption, cryogenic or other methods in a manner that does not constitute Separation.
SECTION 1.17. "Processing Costs" means the costs to Assignor or any Affiliate of Assignor to Process Subject Hydrocarbons before the Sale thereof, which costs for purposes hereof shall consist of the sum of (a) any such Processing charges paid to Non-Affiliates, (b) the charges by Affiliates of Assignor under Existing Sales Contracts, and (c) the charges by Affiliates of Assignor other than under Existing Sales Contracts so long as such charges do not materially exceed charges prevailing in the area for similar services at the time of contracting for such charges.
If Assignor (or its Affiliates) receives a share of the production of others or of plant products therefrom (or proceeds of sale thereof) for Processing such production of others, such share shall not be included in Subject Hydrocarbons (or Gross Proceeds). If Assignor (or its Affiliates) does not bear any Processing Costs but the owners or operators of a plant receive a share of the Subject Hydrocarbons (or proceeds of sale thereof) for Processing them, such share (or proceeds) shall be excluded from the Subject Hydrocarbons (and Gross Proceeds).
SECTION 1.18. "Production Costs" means, for any Computation Period, to the extent not excluded for purposes of calculating Gross Proceeds, whether capital or non-capital in nature,
(a) the sum of
(i) all amounts paid by Assignor or any Affiliate of Assignor as any of the following: royalty, overriding royalty or other presently existing burden against production or the proceeds of Sale of production attributable to the Subject Interests; delay rental; shut- in gas well royalty or payment; minimum royalty; payments to lessors or others in the area in connection with the drilling or deferring of drilling of any well on any of the Subject Lands or lands in the vicinity thereof (including dry and bottom hole payments and payments made to others for refraining from drilling
an offset well) or in connection with any adjustment of any well and leasehold equipment upon unitization of any of the Subject Interests; and rent and other consideration paid for use of or damage to the surface;
(ii) the Property Tax Accrual;
(iii) the overhead costs paid by Assignor or any Affiliate of Assignor under any joint operating agreement applicable to any of the Subject Interests to which Assignor and one or more Non-Affiliates of Assignor are parties and where Assignor or any Affiliate of Assignor is not the operator of such Subject Interest;
(iv) the overhead rate provided for in any joint operating agreement applicable to any of the Subject Interests where Assignor or any Affiliate of Assignor is the operator of such Subject Interests, less the portion, if any, of the overhead rate due from Non-Affiliates of Assignor;
(v) with respect to any Subject Interests operated by Assignor or any of its Affiliates and not subject to a joint operating agreement, an overhead fee as shown on Schedule B attached hereto and subject to adjustment as provided in Schedule B attached hereto;
(vi) all other costs, expenses and liabilities (including Processing Costs) paid or incurred by Assignor or any Affiliate of Assignor for investigating, exploring, prospecting, drilling and mining for, operating and producing Subject Hydrocarbons and sale and marketing thereof, including without implied limitation: costs for equipping, plugging back, reworking, completing, recompleting and plugging and abandoning of any well on the Subject Lands and of making the Subject Hydrocarbons ready or available for market; costs for construction and operation of gathering lines, tanks, transmission lines, meters and other production and delivery facilities; costs, whether paid in cash or by a share of Subject Hydrocarbons, of transporting, compressing, dehydrating, separating, treating, storing and marketing the Subject Hydrocarbons and disposing of extraneous substances produced in association with Subject Hydrocarbons (provided that such costs, if paid to or incurred by an Affiliate of Assignor other than pursuant to an Existing Sales Contract, shall not materially exceed charges prevailing in the area for similar services at the time of contracting for such charges); costs for secondary recovery, pressure maintenance, repressuring, cycling and other operations conducted for the purpose of enhancing production; costs or expenses (whether paid in cash or by delivery of gas) incurred in resolving overproduced gas imbalances attributable to the Subject Interests as of the Effective Date and thereafter; and costs for litigation concerning title to or operation of the Subject Interests and any other acts or omissions of Assignor consistent herewith or brought by Assignor to protect the Subject Interests; and costs for litigation or regulatory proceedings concerning title to or operation of the Subject Interests and any other acts or omissions of Assignor consistent herewith or brought by Assignor to protect the Subject Interests or to
protect or enforce any rights, contractual or otherwise, of Assignor to produce or market Subject Hydrocarbons therefrom;
(vii) Excess Production Costs for the preceding Computation Period (including any remaining Excess Production Costs carried forward from any preceding Computation Period);
(viii) interest on the amount of Excess Production Costs at the beginning of any Computation Period, calculated from the first day to the last day of the Computation Period, at the Prime Interest Rate in effect at the beginning of such Computation Period;
(ix) any amounts paid by Assignor or any Affiliate of Assignor whether as refund, interest or penalty, to a purchaser or any governmental agency or other Person because the amount initially received by Assignor (or Affiliate of Assignor) as sales price for Sales after the Effective Date was more or allegedly more than permitted by the terms of any applicable contract, statute, regulation, order, decree or other obligation; provided such amounts (in the case of a refund), or the amounts with respect to which the interest or penalty was paid, were previously included in Gross Proceeds;
(x) any other amounts paid by Assignor or any Affiliate of Assignor with respect to ownership or operation of the Subject Interests after the Effective Date or Sales of production therefrom after the Effective Date, whether as refund, fine, interest or penalty, pursuant to litigation or settlement of threatened litigation or order of governmental agency, provided that Assignor has not breached Section 6.01 hereof;
(xi) all consideration hereafter paid and costs and expenses hereafter incurred by Assignor or any Affiliate of Assignor for any renewals or extensions of leases or other rights acquired after the Effective Date which are included in the definition herein of Subject Interests; and
(xii) any accrual or reserve which Assignor or any Affiliate of Assignor shall have the right, at its election, to charge to Production Costs for operations (other than day-to-day operations) budgeted under an operating agreement or approved under an authorization for expenditures ("AFE"), which accrual or reserve may be based on the reasonably expected time of performing such operation or on an estimated percentage of completion of the operation or on any other reasonable method, and which accrual is in lieu of charging the cost of such operation when paid for by Assignor (or Affiliate of Assignor) but which shall be adjusted if and to the extent actual costs differ from such accrual or reserve;
(b) but excluding
(i) costs which would otherwise be treated as Production Costs (but which shall not be so treated for purposes hereof until the following amounts have been fully credited against such costs) equal to amounts reimbursed or credited to Assignor by insurance from damage to property, by sales of property or transfers of property off the leases included in the Subject Interests or by proceeds from unitization or other disposition of property; and
(ii) except for resolution of gas imbalances which are included in Section 1.18(a)(vi) above, any amounts which would otherwise be Production Costs but which are attributable to periods before the Effective Date; and
(iii) costs that otherwise would be treated as Production Costs but which have already been excluded or deducted from Gross Proceeds under Section 1.09; and
(iv) costs incurred by any Affiliate of Assignor for which such Affiliate has received a fee, reimbursement or other payment from Assignor, where such payment by Assignor constitutes a Production Cost.
SECTION 1.19. "Property Taxes" means the sum of all general property (ad valorem), production, severance, sales, gathering and excise taxes and other taxes (whether state, federal or otherwise), except income taxes, assessed or levied on or in connection with the Subject Interests, the Royalty Interest or the production therefrom or equipment on the Subject Lands, or against Assignor as owner of the Subject Interests or Assignee as owner of the Royalty Interest.
SECTION 1.20. "Property Tax Accrual" means, for any Computation Period, an amount that may be set aside by Assignor as an accrual to be applied against Property Taxes other than those that are deducted or excluded from Gross Proceeds pursuant to Section 1.09(a) above, which accruals shall be adjusted to the extent actual Property Taxes differ.
SECTION 1.21. "Sale" and "Sold" mean all forms of dispositions of Subject Hydrocarbons for value, including exchanges and other dispositions for value.
SECTION 1.22. "Sales Contracts" means all contracts and agreements for the sale of Subject Hydrocarbons.
SECTION 1.23. "Separation" means liquid separation operations in the vicinity of the well using a conventional mechanical liquid gas separator but excluding operations involving heat exchange, adiabatic cooling, absorption, adsorption or refrigeration principles.
SECTION 1.24. "Subject Hydrocarbons" means all Hydrocarbons in and under, and which may be produced, saved and sold from, and which shall accrue and be attributable to, the Subject Interests on and after the Effective Date, including plant products attributable thereto from Processing gas or casinghead gas included in the Subject Hydrocarbons before sale thereof (but not including products derived from processing oil).
SECTION 1.25. "Subject Interests" means, subject to the exclusions stated below, each kind and character of right, title, claim or interest which Assignor has on the Effective Date in or under each oil, gas or mineral lease, unitization or pooling agreement (and the units created thereby), royalty interests, overriding royalty interests, fee mineral interests and net profits interests and any other agreements, conveyances, assignments or instruments which are described or referred to in Schedule A, and all the right, title, claim or interest which Assignor has on the Effective Date in and to the Subject Lands, whether such right, title, claim or interest be under and by virtue of a lease, a unitization or pooling agreement or order, an operating agreement, a division order, a transfer order or any other type of agreement, conveyance, assignment or instrument or under any other type of claim or title, legal or equitable, recorded or unrecorded, even though Assignor's interests be incorrectly or incompletely described in, or a description thereof be omitted from, Schedule A, all as the same shall be enlarged by the discharge of any payments out of production or by the removal of any charges or encumbrances to which any of the same are subject and any and all renewals and extensions of any of the same, but subject to all burdens to which Assignor's such right, title, claim or interest is subject (while same remains so subject), limited, however, if Assignor's interest in any Subject Interest should terminate at any time, to the period to which Assignor's interest in such Subject Interest is limited. There shall be excluded from the term "Subject Interests" any interest hereafter acquired by Assignor in and to any of the Subject Lands, except any interest acquired pursuant to existing agreements for no new consideration and renewals or extensions of existing leases and other such agreements. For purposes of this Conveyance "renewals or extensions" of any lease or other such agreement shall be limited to renewals or extensions of an existing lease or other such agreement obtained by the present owner thereof (or such owner's successors in interest) while such lease is in force or within six months after such lease or other such agreement terminates. Assignor shall be under no duty to seek renewals or extensions of any lease or other such agreement.
SECTION 1.26. "Subject Lands" means the lands which are described in and which are subject to the oil, gas or mineral leases, unitization or pooling agreements or orders, operating agreements, division orders, transfer orders or other type of agreement, conveyance, assignment or instrument described in Schedule A attached hereto, provided that, where the description in Schedule A excepts land or refers to an instrument insofar only as it covers certain land or certain depths in certain land, no interest in such excepted land or depths or in land other that to which such reference is limited shall be included in the terms "Subject Lands" or "Subject Interests".
SECTION 1.27. "Trust" means the Hugoton Royalty Trust established by the Trust Indenture.
SECTION 1.28. "Trust Indenture" means the Royalty Trust Indenture by and between Cross Timbers Oil Company and NationsBank, N.A. dated as of December 1, 1998, establishing the Hugoton Royalty Trust, an express Texas Trust under the Texas Trust Code.
ARTICLE II
MARKETING OF SUBJECT HYDROCARBONS
SECTION 2.01. Sales Contracts. Assignor, to the extent it has the right to do so, shall market or cause to be marketed the Subject Hydrocarbons and Assignee shall have no authority to
market the Subject Hydrocarbons or to take in-kind any Subject Hydrocarbons. For such purpose, Sales of Subject Hydrocarbons may continue to be made pursuant to Existing Sales Contracts. Assignor may amend such Existing Sales Contracts and may enter into one or more Sales Contracts in the future at the prices and on the terms Assignor shall deem proper in Assignor's sole and absolute discretion, which may include sales to Affiliates of Assignor. Further, Assignor may commit any of the Subject Interests (including the Royalty Interest attributable thereto) to one or more agreements for Processing pursuant to which, by way of example and not by way of limitation, the plant owner or operator (which may be an Affiliate of Assignor) receives a portion of the Subject Hydrocarbons or plant products derived therefrom or proceeds of the Sale thereof as a fee for Processing. Except as provided otherwise in Section 1.09 for the period from the Effective date through January 31, 2000, Gross Proceeds of Subject Hydrocarbons shall be determined on the basis of amounts actually received by Assignor (and not, except as provided in Section 1.09, proceeds received by any of Assignor's Affiliates) from Sales under Sales Contracts regardless of whether at the time of production or Sale market value should be different from proceeds of Sale. In no event shall Gross Proceeds or Production Costs include any revenues, expenses, gains or losses resulting from option transactions or other futures or hedging transactions (other than forward Sales of the Subject Hydrocarbons) which, if engaged in by Assignor or any of its Affiliates in respect of Subject Hydrocarbons, shall be solely for the account of Assignor or such Affiliate.
SECTION 2.02. Delivery of Subject Hydrocarbons. All Subject Hydrocarbons Sold by Assignor, whether pursuant to Sales Contracts or otherwise, shall be delivered, by Assignor to the purchasers thereof, into the pipelines to which the wells producing such Subject Hydrocarbons may be connected or to such other point of purchase as is reasonably required in the marketing of such Subject Hydrocarbons.
SECTION 2.03. Reliance by Third Party. As to any party, the acts of Assignor shall be binding on Assignee. It shall not be necessary for Assignee to join with Assignor in any division or transfer order, lease extension or Sales Contract, and proceeds of Sale of the Subject Hydrocarbons shall be paid by the purchasers thereof (or others disbursing proceeds) directly to Assignor without necessity of joinder by or consent of Assignee.
ARTICLE III
PAYMENTS
SECTION 3.01. Payment. On or before each Monthly Record Date, beginning with the Monthly Record Date for March, 1999, Assignor shall pay to Assignee as an overriding royalty hereunder an amount equal to eighty percent (80%) of the Net Proceeds for the preceding Computation Period. All payments made to Assignee on account of the Royalty Interest shall be made entirely and exclusively out of sale proceeds attributable to the production of Hydrocarbons from, or attributed to, the Subject Interests after the Effective Time. Accordingly, the amount of any Net Proceeds in respect of a Computation Period which cannot be paid out of the sale proceeds of production of Hydrocarbons from, or attributed to, the Subject Interests shall be carried over and included in Net Proceeds in the next Computation Period; provided, however, such amount shall only be payable from the Hydrocarbons produced from or attributable to the Subject Interests and the sale proceeds thereof, if any.
SECTION 3.02. Interest on Past Due Payments. Except as otherwise provided in Section 9.05 hereof, any amount not paid by Assignor to Assignee when due shall bear, and Assignor will pay, interest determined at the end of each month, from such due date until such amount is paid, at the rate of the lesser of (a) the Prime Interest Rate plus 4% or (b) the maximum lawful contract rate of interest permitted by the applicable usury laws, now or hereafter enacted, which interest rate (the "Maximum Rate") shall change when and as said laws change, effective at the close of business on the day such change in said laws becomes effective; but, if there shall be no Maximum Rate, then the rate shall be as specified in the foregoing clause (a).
SECTION 3.03. Overpayment. If at any time Assignor pays Assignee more than the amount due, Assignee shall not be obligated to return any such overpayment, but the amount or amounts otherwise payable to Assignee for any subsequent period or periods shall be reduced by such overpayment, plus an amount equal to interest during the period of such overpayment at the rate of the lesser of (a) the Prime Interest Rate or (b) the Maximum Rate; but if there shall be no Maximum Rate, then the rate shall be as specified in the foregoing clause (a).
ARTICLE IV
RECORDS AND REPORTS
SECTION 4.01. Books and Records. Assignor shall at all times maintain true and correct books and records sufficient to determine the amounts payable to Assignee hereunder, including, but not limited to, a Net Proceeds account to which Gross Proceeds and Production Costs are credited and charged.
SECTION 4.02. Inspections. The books and records referred to in Section 4.01 shall be open for inspection by Assignee and its agents and representatives at the office of Assignor during normal business hours and after reasonable advance notice.
SECTION 4.03. Quarterly Statements. Within thirty (30) days next following the close of each calendar quarter, Assignor shall deliver to Assignee a statement showing the computation of Net Proceeds attributable to such quarter.
SECTION 4.04. Assignee's Exceptions to Quarterly Statements. If Assignee shall take exception to any item or items included in the quarterly statements rendered by Assignor, Assignee shall notify Assignor in writing within 180 days after the receipt of the report and annual audit furnished pursuant to Section 4.07 hereof, setting forth in such notice the specific charges complained of and to which exception is taken or the specific credits which should have been made and allowed; and, with respect to such complaints and exceptions as are justified, adjustment shall be made. If Assignee shall fail to give Assignor notice of such complaints and exceptions prior to the expiration of such 180 day period, then the statements for such calendar year as originally rendered by Assignor shall be deemed to be correct as rendered.
SECTION 4.05. Geological and Other Data. Upon request by Assignee, Assignor shall, subject to the limitations of confidentiality or nondisclosure obligations to co-owners or other third parties, furnish to Assignee access to all geological, well and production data which Assignor has
on hand relating to operations on the Subject Interests. Assignor will use reasonable efforts to obtain waivers of any such confidentiality or nondisclosure obligations that prevent it from providing to Assignee any requested information, but Assignor shall not be obligated to incur any expense or detriment above a nominal amount to obtain such waiver. Assignor shall also furnish to Assignee, upon request by Assignee, reports showing the status of development, producing and other operations conducted by Assignor on the Subject Interests. Assignor shall, upon request by Assignee, furnish to Assignee all reserve reports or studies in the possession of Assignor from time to time relating to the Subject Interests, whether prepared by Assignor or by third party consulting engineers; provided, it is agreed that Assignor makes no representations or warranties as to the accuracy or completeness of any such reports or studies and shall have no liability to Assignee or any other Person resulting from their use of such reports or studies, and Assignee agrees not to attribute to Assignor or such third-party consulting engineers any such reports or studies or the contents thereof in any securities filings or reports to owners or holders of "Beneficial Interests" in the Trust. All information furnished to Assignee pursuant to this section is confidential and for the sole benefit of Assignee and shall not be shown by Assignee to any other Person, except that this provision shall not prohibit the disclosure by Assignee of any information that (i) at the time of disclosure is generally available to the public (other than as a result of a disclosure by Assignee), (ii) was available to Assignee on a nonconfidential basis from a source other than Assignor, provided that such source is not known by Assignee to be bound by a confidentiality obligation owed to Assignor, or (iii) Assignee is legally required to disclose, provided that Assignee has given to Assignor notice of such requirement and a reasonable opportunity to seek, at Assignor's expense, a protective order and other appropriate relief from such requirement.
SECTION 4.06. Monthly Estimates. On or before ten days (excluding Saturdays, Sundays and other days on which national banking institutions in the City of Fort Worth, Texas, are closed as authorized or required by law) before each Monthly Record Date (beginning with the Monthly Record Date for March, 1999), Assignor shall deliver to Assignee a statement of Assignor's best estimate of the amount payable to Assignee on or before such Monthly Record Date.
SECTION 4.07. Annual Audits and Reports. Within 90 days after the end of the calendar year, Assignor shall deliver to Assignee a statement which has been audited by a nationally recognized firm of independent public accountants selected by Assignor, which shall show the information provided for in Section 4.03 on an annual basis. Assignee shall bear the cost of each such audit.
SECTION 4.08. Reserve Reports. Assignor may, but is not obligated to, provide an annual reserve report for the Royalty Interest prepared by independent consulting reservoir engineers. If such reserve report is provided by Assignor, Assignee will reimburse Assignor for the cost thereof.
ARTICLE V
LIABILITY OF ASSIGNEE
In no event shall Assignee be liable or responsible in any way for any Production Costs (including Excess Production Costs) or other costs or liabilities incurred by Assignor or others attributable to the Subject Interests or to the Hydrocarbons produced therefrom.
ARTICLE VI
OPERATION OF SUBJECT INTERESTS
SECTION 6.01. Prudent Operator Standard. Assignor agrees, to the extent it has the legal right to do so under the terms of any lease, operating agreement, contract for development or similar instrument affecting or pertaining to the Subject Interests (or any portion thereof), that it will conduct and carry on the maintenance and operation of the Subject Interests with reasonable and prudent business judgment and in accordance with good oil and gas field practices, and that it will drill such wells as a reasonably prudent operator would drill from time to time in order to protect the Subject Interests from drainage. Assignor further agrees to produce the Subject Interests without regard to whether any amount is imputed to the Gross Proceeds for any Computation Period during the period from the Effective Date through January 31, 2000, as provided in Section 1.09. However, nothing contained in this Section 6.01 shall be deemed to prevent or restrict Assignor from electing not to participate in any operation which is to be conducted under the terms of any operating agreement, contract for development or similar instrument affecting or pertaining to the Subject Interests (or any portion thereof) and allowing consenting parties to conduct nonconsent operations thereon, if such election is made by Assignor in good faith. Notwithstanding anything elsewhere herein to the contrary, Assignor shall never be liable to Assignee for the manner in which Assignor performs its duties hereunder as long as Assignor has acted in good faith.
SECTION 6.02. Abandonment of Properties. Nothing herein contained shall obligate Assignor to continue to operate any well or to operate or maintain in force or attempt to maintain in force any of the Subject Interests when, in Assignor's opinion, such well or Subject Interest ceases to produce or is not capable of producing Hydrocarbons in paying quantities. The expiration of a Subject Interest in accordance with the terms and conditions applicable thereto shall not be considered to be a voluntary surrender or abandonment thereof.
SECTION 6.03. Insurance. Although Assignor is permitted to carry policies of insurance covering the property upon the Subject Interests and risks incident to the operation thereof and to charge premiums therefor to the Net Proceeds account, Assignor shall not be required to carry insurance on such property or covering any of such risks unless it elects to do so. In no event shall Assignor be liable to Assignee on account of any losses sustained which are not covered by insurance.
SECTION 6.04. Certain Rights to Manage the Subject Interests.
Notwithstanding anything in this Conveyance to the contrary, Assignor shall have
the right and power, acting in good faith and as a reasonably prudent oil and
gas operator, to execute, deliver, and perform operating agreements, oil and gas
leases, farmout agreements, exploration agreements, participation agreements,
drilling agreements, acreage contribution agreements, dry-hole agreements,
bottom-hole agreements, joint venture agreements, partnership agreements, and
other similar instruments and agreements that cover or affect the Subject
Interests and to make all decisions or elections required thereunder, including,
but not limited to, decisions to consent or non-consent to drilling and other operations. The applicable Royalty Interest shall in each case be bound by such instrument or agreement (and decisions or elections thereunder), without the necessity of any execution, consent, joinder, or ratification by Assignee, and the Royalty Interest shall thereafter be calculated and paid with respect to the interests reserved, obtained, or modified by Assignor in such transaction, not by reference to the Subject Interests that existed before such transaction. For example, but not by way of limitation, (a) Assignor may farm out any Subject Interest that is an oil and gas lease, and the Subject Interest therein shall subsequently be the overriding royalty interest, reversionary working interest, and/or other rights and interests reserved by Assignor in the farmout, not the original leasehold interest, or (b) Assignor may execute an oil and gas lease to cover any Subject Interest that is a mineral interest, and the Subject Interest shall subsequently be the royalty and other lease benefits obtained or reserved by Assignor in such lease, not the original mineral interest.
ARTICLE VII
POOLING AND UNITIZATION
SECTION 7.01. Pooled Subject Interests. To the extent any of the Subject Interests have been heretofore pooled and unitized for the production of Hydrocarbons, such Subject Interests are and shall be subject to the terms and provisions of such pooling and unitization agreements, and the Royalty Interest in each such Subject Interest shall apply to and affect only the production from such units which accrues to such Subject Interest under and by virtue of the applicable pooling and unitization agreements.
SECTION 7.02. Right to Pool and Unitize. Assignor shall have the exclusive right and power (as between Assignor and Assignee), exercisable only during the period provided in Section 7.03 hereof, to pool or unitize any of the Subject Interests and to alter, change or amend or terminate any pooling or unitization agreements heretofore or hereafter entered into, as to all or any part of the Subject Lands, as to any one or more of the formations or horizons thereunder, and as to any one or more Hydrocarbons, upon such terms and provisions as Assignor shall in its sole and absolute discretion determine. If and whenever through the exercise of such right and power, or pursuant to any law hereafter enacted or any rule, regulation or order of any governmental body or official hereafter promulgated, any of the Subject Interests are pooled or unitized in any manner, the Royalty Interest insofar as it affects such Subject Interest shall also be pooled and unitized, and in any such event such Royalty Interest in such Subject Interest shall apply to and affect only the production which accrues to such Subject Interest under and by virtue of the pooling and unitization, and it shall not be necessary for Assignee to agree to, consent to, ratify, confirm or adopt any exercise of such right and power by Assignor.
SECTION 7.03. Applicable Period. Assignor's power and rights in Section 7.02 shall be exercisable only during the period of the life of the last survivor of the descendants of the signers of the Declaration of Independence living on the date of execution hereof, plus twenty-one (21) years after the death of such last survivor, or the term of this Conveyance, whichever period shall first expire.
ARTICLE VIII
GOVERNMENT REGULATION
All obligations of Assignor hereunder shall be subject to all present and future valid federal, state and local laws, statutes, codes and orders; and all applicable rules, orders, regulations and decisions of every court, governmental agency, body or authority having jurisdiction over the Hydrocarbons in and under and that may be produced from the Subject Interests. Assignor's obligations are specifically, but not by way of limitation, subject, to the extent in effect, to all applicable provisions of the Emergency Petroleum Allocation Act of 1973, the Department of Energy Organization Act, the Natural Gas Act, the Natural Gas Policy Act of 1978, the Natural Gas Wellhead Decontrol Act of 1989 and each other statute purporting to provide regulation of the Sale of Hydrocarbons or establishing maximum prices at which the same may be Sold and all applicable laws, orders, rules and regulations thereunder of the Federal Energy Regulatory Commission, the Department of Energy and each other legislative or governmental body, agency, board or commission having jurisdiction. If maximum rates permitted under such statutes, rules and regulations for the Subject Hydrocarbons are lower than prices established in Sales Contracts, then the lower regulated prices received by Assignor shall control. Assignor shall be entitled to use its reasonable discretion in making filings, for itself and on behalf of Assignee, with the Federal Energy Regulatory Commission, the Department of Energy or any other governmental body, agency, board or commission having jurisdiction, affecting the price or prices at which Subject Hydrocarbons may be Sold, and with purchasers of production, operators or others with respect to any excise tax.
ARTICLE IX
ASSIGNMENTS
SECTION 9.01. Assignment by Assignor. Assignor shall have the right to assign, sell, transfer, convey, mortgage or pledge the Subject Interests, or any part thereof, subject to the Royalty Interest and the terms and provisions of this Conveyance. From and after the effective date of any such assignment, sale, transfer or conveyance by Assignor, the assignee thereunder shall succeed to all the requirements upon and responsibilities of Assignor hereunder, as to the interests in the Subject Interests so acquired by such assignee, and, from and after the said effective date, Assignor shall be relieved of such requirements and responsibilities, excepting only those accrued or due for performance prior to such effective date.
SECTION 9.02. Partial Assignment. If Assignor assigns its interest under the Subject Interests as to some of such Subject Interests or as to some part thereof, then, effective as of the date of such assignment, in determining the Royalty Interest payable with respect to production from such assigned Subject Interests or parts thereof, the Gross Proceeds, Production Costs and Net Proceeds attributable to such assigned interests will be computed and determined by the assignee of such assigned interests in the aggregate as to the assigned interests owned by such assignee, but separate from and not aggregated with the computation and determination made by Assignor as to Subject Interests that have not been assigned by Assignor.
SECTION 9.03. Assignment by Assignee. Assignee has the right to assign the Royalty Interest in whole or in part only as authorized by the Trust Indenture. However, no such assignment will affect the method of computing Net Proceeds, and if more than one Person becomes entitled to participate in the Royalty Interest, Assignor may withhold from such other Person payments to which such Person would otherwise be entitled hereunder and the furnishing of any data or information which Assignor is required by the terms hereof to furnish Assignee until Assignor is furnished a recordable instrument executed by or binding upon all Persons interested in the Royalty Interest designating one Person who is to receive such payments, data and information. In making conveyances or assignments of any of the Subject Interests (to the extent permitted hereunder), Assignee need not vest in its grantee or assignee all of the rights of Assignee hereunder with respect to the interest in the Subject Interests so conveyed or assigned.
SECTION 9.04. Certain Sales of Subject Interests. Subject to the limitations set forth in Section 3.02(b) of the Trust Indenture, Assignor may cause the sale of certain Subject Interests, including the appurtenant Royalty Interest from time to time and Assignee will join in such sales as provided in the Trust Indenture. The proceeds of any such sale shall be apportioned and paid as provided in the Trust Indenture, but the purchasers of such Subject Interests (inclusive of the appurtenant Royalty Interest) may pay the full amount of the purchase price therefor to Assignor and shall have no responsibility to see to the proper allocation thereof between Assignor and Assignee.
SECTION 9.05. Change in Ownership. No change of ownership or right to receive payment of the Royalty Interest, or of any part thereof, however accomplished, shall be binding upon Assignor until notice thereof shall have been furnished by the Person claiming the benefit thereof, and then only with respect to payments thereafter made. Notice of sale or assignment shall consist of a certified copy of the recorded instrument accomplishing the same; notice of change of ownership or right to receive payment accomplished in any other manner (for example by reason of incapacity, death or dissolution) shall consist of certified copies of recorded documents and complete proceedings legally binding and conclusive of the rights of all parties. Until such notice accompanied by such documentation shall have been furnished Assignor as above provided, the payment or tender of all sums payable on the Royalty Interest may be made in the manner provided herein precisely as if no such change in interest or ownership or right to receive payment had occurred, or (at Assignor's election) Assignor shall have the right to suspend payment of such sums without interest in the event of such change until such documentation is furnished. The kind of notice herein provided shall be exclusive, and no other kind, whether actual or constructive, shall be binding on Assignor.
SECTION 9.06. Rights of Mortgagee or Trustee. If Assignee shall at any time execute a mortgage or deed of trust covering all or part of the Royalty Interest, the mortgagee(s) or trustee(s) therein named or the holder of any obligation secured thereby shall be entitled, to the extent such mortgage or deed of trust so provides, to exercise all the rights, remedies, powers and privileges conferred upon Assignee by the terms of this Conveyance and to give or withhold all consents required to be obtained hereunder by Assignee, but the provisions of this Section 9.06 shall in no way be deemed or construed to impose upon Assignor any obligation or liability undertaken by Assignee under such mortgage or deed of trust or under the obligation secured thereby.
ARTICLE X
MISCELLANEOUS
SECTION 10.01. Proportionate Reduction. In the event of failure or deficiency in title to any of the Subject Interests, the portion of the production from such Subject Interest out of which the Royalty Interest attributable to such Subject Interest shall be payable shall be reduced in the same proportion that such Subject Interest is reduced. Notwithstanding the foregoing, if any Person claims that this Conveyance gives rise to a preferential right of such Person to acquire any portion of the Royalty Interest (or any of the Subject Interests), then Assignor shall indemnify Assignee and the trustee of the Trust against any liability, expense, damage or loss in regard to such claim and the provisions of Section 6.05 of the Trust Indenture shall apply with respect to such indemnity obligation. If such claim results in the acquisition of any portion of the Royalty Interest by the Person claiming the preferential right then, subject to the proviso below, Assignor shall pay to Assignee the amount determined by multiplying (i) the product of 40,000,000 multiplied by the initial public offering price of the Trust's units of beneficial interest by (ii) a fraction, the numerator of which is the value of the portion of the Royalty Interest acquired by the Person claiming the preferential right, as determined by reference to the most recent Reserve Report (as defined in the Trust Indenture) of the Trust and the denominator of which is the value of all the Royalty Interest as determined by reference to such Reserve Report; provided, however, that if the Person claiming such preferential right makes any payment to the Trust in connection with the acquisition of a portion of the Royalty Interest, then the amount of such payment shall be credited against Assignor's payment obligation set forth above, but not to create a negative number.
SECTION 10.02. Term. This Conveyance shall remain in force as long as any of the Subject Interests are in effect.
SECTION 10.03. Further Assurances. Should any additional instruments of assignment and conveyance be required to describe more specifically any interests subject hereto, Assignor agrees to execute and deliver the same. Also, if any other or additional instruments are required in connection with the transfer of State, Federal or Indian lease interests in order to comply with applicable laws, regulations or agreements, Assignor will execute and deliver the same.
SECTION 10.04. Notices. All notices, statements, payments and communications between the parties hereto shall be deemed to have been sufficiently given and delivered if enclosed in a post paid wrapper and deposited in the United States Mails directed, or if personally delivered, to the party to whom the same is directed or to be furnished or made at the respective addresses, as follows:
If to Assignor:
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, Texas 76102
Attention: Corporate Secretary
If to Assignee:
NationsBank, N.A.
17th Floor
901 Main Street
NationsBank Plaza
Dallas, Texas 75202
Attention: Trust Department
Either party or the successors or assignees of the interest or rights or obligations of either party hereunder may change its address or designate a new or different address or addresses for the purposes hereof by a similar notice given or directed to all parties interested hereunder at the time.
SECTION 10.05. Binding Effect. This Conveyance shall bind and inure to the benefit of the successors and assigns of Assignor and Assignee.
SECTION 10.06. Governing Law. The validity, effect and construction of this Conveyance shall be governed by the laws of the State of Texas.
SECTION 10.07. Headings. Article and Section headings used in this Conveyance are for convenience only and shall not affect the construction of this Conveyance.
SECTION 10.08. Substitution of Warranty. This instrument is made with full substitution and subrogation of Assignee in and to all covenants of warranty by others heretofore given or made with respect to the Subject Interests or any part thereof or interest therein.
SECTION 10.09. Counterpart Execution. This Conveyance may be executed in multiple counterparts, each of which shall be an original. Certain counterparts may have descriptions relating to different recording jurisdictions omitted from Schedule A. A counterpart with all such descriptions is being filed for record in Seward County, Kansas. Where a description covers an interest located in more than one county, such description may be included in counterparts recorded in each county but such inclusion of the same description in more than one counterpart does not have any cumulative effect as to the interests covered by such description.
SECTION 10.10. Amended and Restated Conveyance. This Conveyance amends and restates fully a document previously executed by Assignor and Assignee. Such prior document was
not recorded and is fully replaced and superseded by this Conveyance and such previously executed document is to be disregarded for all purposes.
IN WITNESS WHEREOF, each of the parties hereto has caused this Conveyance to be executed in its name and behalf and delivered as of the Effective Date.
ATTEST:
CROSS TIMBERS OIL COMPANY
-------------------------
Virginia Anderson, Secretary
of Cross Timbers Oil Company By:
-------------------------------
Vaughn O. Vennerberg, II
Senior Vice President - Land
|
STATE OF TEXAS (S)
(S)
COUNTY OF TARRANT (S)
This instrument was acknowledged before me on this ____ day of _______, 1999, by Vaughn O. Vennerberg II, Senior Vice President - Land of Cross Timbers Oil Company, on behalf of said corporation.
THE STATE OF TEXAS (S)
(S)
COUNTY OF DALLAS (S)
This instrument was acknowledged before me on this ____ day of _______, 1999, by Ron E. Hooper, Vice President of NationsBank, N.A., Trustee of the Hugoton Royalty Trust, on behalf of said Bank as Trustee of the Hugoton Royalty Trust.
SCHEDULE B
Attached to and made a part of that certain Net Overriding Royalty Conveyance
(Hugoton Royalty Trust) dated effective December 1, 1998 (the "Conveyance")
ACCOUNTING PROCEDURE
I. GENERAL PROVISIONS
1. Definitions
"Joint Property" shall mean the real and personal property subject to the
Conveyance.
"Joint Operations" shall mean all operations necessary or proper for the
development, operation, protection and maintenance of the Joint Property.
"Joint Account" shall mean the account showing the charges paid and credits
received in the conduct of the Joint Operations and which are used in the
calculation of Gross Proceeds, Net Proceeds, Processing Costs and
Production Costs, as said terms are defined in the Conveyance.
"Operator" shall mean Cross Timbers Oil Company or any of its affiliates
that conduct Joint Operations on the Joint Property.
"Parties" shall mean Operator and the Hugoton Royalty Trust (herein
referred to as the "Trust").
"First Level Supervisors" shall mean those employees whose primary function
in Joint Operations is the direct supervision of other employees and/or
contract labor directly employed on the Joint Property in a field operating
capacity.
"Technical Employees" shall mean those employees having special and
specific engineering, geological or other professional skills, and whose
primary function in Joint Operations is the handling of specific operating
conditions and problems for the benefit of the Joint Property.
"Personal Expenses" shall mean travel and other reasonable reimbursable
expenses of Operator's employees.
"Material" shall mean personal property, equipment or supplies acquired or
held for use on the Joint Property.
"Controllable Material" shall mean Material which at the time is so
classified in the Material Classification Manual as most recently
recommended by the Council of Petroleum Accountants Societies.
2. Designation and Responsibilities of Operator
Cross Timbers Oil Company shall be the Operator of the Joint Property, and shall, to the extent it has the legal right to do so, conduct and direct and have full control of all operations on the Joint Property as permitted and required by, and within the limits of the Conveyance.
3. Payments and Accounting
Except as herein otherwise specifically provided, Operator shall promptly pay and discharge expenses incurred in the development and operation of the Joint Property and shall charge the Joint Account with the appropriate proportionate share upon the expense basis provided herein. Operator shall keep an accurate record of the expenses incurred and charges and credits made and received.
4. Application of Agreement
This Accounting Procedure will apply to Joint Properties where Cross Timbers Oil Company is the Operator and the Operator owns all or a portion of the leasehold interest in the Joint Properties. In the event there is an existing Accounting Procedure or related instrument governing the operations of the Joint Properties, this
Accounting Procedure will control except as to the overhead rate stated in the existing Accounting Procedure or related instrument.
5. Conflicts
In the event there exists any conflict between the terms of this Accounting Procedure or any Accounting Procedure that applies to the Joint Properties and the Conveyance to which it is attached, the Conveyance will control.
II. DIRECT CHARGES
Operator shall charge the Joint Account with the following items, which shall be allocated to Processing Costs or Production Costs as appropriate:
1. Ecological and Environmental
Costs incurred for the benefit of the Joint Property as a result of governmental or regulatory requirements to satisfy environmental considerations applicable to the Joint Operations. Such costs may include surveys of an ecological or archaeological nature and pollution control procedures as required by applicable laws and regulations, and costs related to employees of Operator performing any environmental work involving the Joint Property.
2. Rentals and Royalties
Lease rentals and royalties paid by Operator for the Joint Operations.
3. Labor
A. (1) Salaries and wages of Operator's field employees employed on the Joint Property in the conduct of Joint Operations.
(2) Salaries of First Level Supervisors in the field.
(3) Salaries and wages of Technical Employees directly employed on the Joint Property.
(4) Salaries and wages of Technical Employees either temporarily or permanently assigned to and directly employed in the operation of the Joint Property.
(5) Salaries and wages of support employees whose duties are primarily field related in connection with the Joint Operations, regardless of their location (e.g., field superintendents and clerical employees located in the field).
B. Operator's cost of holiday, vacation, sickness and disability benefits
and other customary allowances paid to employees whose salaries and
wages are chargeable to the Joint Account under Paragraph 3A of this
Section II. Such costs under this Paragraph 3B may be charged on a
"when and as paid basis" or by "percentage assessment" on the amount
of salaries and wages chargeable to the Joint Account under Paragraph
3A of this Section II. If percentage assessment is used, the rate
shall be based on the Operator's cost experience.
C. Expenditures or contributions made pursuant to assessments imposed by
governmental authority which are applicable to Operator's costs
chargeable to the Joint Account under Paragraphs 3A and 3B of this
Section II.
D. Personal Expenses of those employees whose salaries and wages are chargeable to the Joint Account under Paragraph 3A of this Section II.
4. Employee Benefits
Operator's current costs of established plans for employees' group life insurance, hospitalization, pension, retirement, stock purchase, thrift, bonus, and other benefit plans of a like nature, applicable to Operator's labor cost chargeable to the Joint Account under Paragraph 3A and 3B of this Section II shall be Operator's actual cost not to exceed the percent most recently recommended by the Council of Petroleum Accountants Societies.
5. Material
Material purchased or furnished by Operator for use on the Joint Property as provided under Section IV. Only such Material shall be purchased for or transferred to the Joint Property as may be required for immediate use and is reasonably practical and consistent with efficient and economical operations. The accumulation of surplus stocks shall be avoided.
6. Transportation
Transportation of employees and Material necessary for the Joint Operations but subject to the following limitations:
A. If Material is moved to the Joint Property from the Operator's warehouse or other properties, no charge shall be made to the Joint Account for a distance greater than the distance from the nearest reliable supply store where like material is normally available or railway receiving point nearest the Joint Property.
B. If surplus Material is moved to Operator's warehouse or other storage point, no charge shall be made to the Joint Account for a distance greater than the distance to the nearest reliable supply store where like material is normally available, or railway receiving point nearest the Joint Property. No charge shall be made to the Joint Account for moving Material to other properties belonging to Operator.
C. In the application of subparagraphs A and B above, the option to equalize or charge actual trucking cost is available when the actual charge is $400 or less excluding accessorial charges. The $400 will be adjusted to the amount most recently recommended by the Council of Petroleum Accountants Societies.
7. Services
The cost of contract services, equipment and utilities provided by outside sources, except services excluded by Paragraph 10 of Section II and Paragraph i, ii, and iii, of Section III. The cost of professional consultant services and contract services of technical personnel directly engaged on the Joint Property if such charges are excluded from the overhead rates.
8. Equipment and Facilities Furnished By Operator
A. Operator shall charge the Joint Account for use of equipment and facilities owned by Operator or any of its affiliates at rates commensurate with costs of ownership and operation. Such rates shall include costs of maintenance, repairs, other operating expense, insurance, taxes, depreciation, and interest on gross investment less accumulated depreciation not to exceed twelve percent (12%) per annum. Such rates shall not exceed average commercial rates currently prevailing in the immediate area of the Joint Property.
B. In lieu of charges in paragraph 8A above, Operator may elect to use average commercial rates prevailing in the immediate area of the Joint Property less 20%. For automotive equipment, Operator may elect to use rates published by the Petroleum Motor Transport Association.
C. This Paragraph 8 shall not affect any current charges made by Operator to the Joint Account related to transportation, gathering, treating, compression or processing or related charges by an affiliate of Operator.
9. Damages and Losses to Joint Property
All costs or expenses necessary for the repair or replacement of Joint Property made necessary because of damages or losses incurred by fire, flood, storm, theft, accident, or other cause, except those resulting from Operator's gross negligence or willful misconduct.
10. Legal Expense
Expense of handling, investigating and settling litigation or claims, discharging of liens, payment of judgments and amounts paid for settlement of claims incurred in or resulting from operations under the Conveyance or necessary to protect or recover the Joint Property, and the costs and expenses incurred in connection with hearings and other matters before governmental bodies and agencies and costs and expenses incurred in curing title to the Joint Property. Costs incurred by Operator in procuring abstracts and fees paid outside attorneys for title examination (including preliminary, supplemental, shut-in gas royalty opinions and division order title opinions) shall be borne by the Joint Account. Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of the above functions. All other legal expense is considered to be covered by the overhead provisions of Section III.
11. Taxes
All taxes of every kind and nature assessed or levied upon or in connection with the Joint Property, the operation thereof, or the production therefrom, and which taxes have been paid by the Operator for the benefit of the Parties. If the ad valorem taxes are based in whole or in part upon separate valuations of each party's interest, then notwithstanding anything to the contrary herein, charges to the Joint Account shall be made and paid by the Parties hereto in accordance with the tax value generated by each party's interest.
12. Insurance
Net premiums paid for insurance required to be carried for the Joint Operations for the protection of the Parties. In the event Joint Operations are conducted in a state in which Operator may act as self- insurer for Worker's Compensation and/or Employers Liability under the respective state's laws, Operator may, at its election, include the risk under its self-insurance program and in that event, Operator shall include a charge at Operator's cost not to exceed manual rates.
13. Abandonment and Reclamation
Costs incurred for abandonment of the Joint Property, including costs required by governmental or other regulatory authority.
14. Communications
Cost of acquiring, leasing, installing, operating, repairing and maintaining communication systems, including radio and microwave facilities or any form of telephonic equipment or service used in serving the Joint Property. In the event communication facilities/systems serving the Joint Property are Operator owned, charges to the Joint Account shall be made as provided in Paragraph 8 of this Section II.
15. Other Expenditures
Any other expenditure not covered or dealt with in the foregoing provisions of this Section II, or in Section III and which is of direct benefit to the Joint Property and is incurred by the Operator in the necessary and proper conduct of the Joint Operations.
III. OVERHEAD
1. Overhead - Drilling and Producing Operations
i. As compensation for administrative, supervision, office services and warehousing costs, Operator shall charge drilling and producing operations on a Fixed Rate Basis, Paragraph 1A. Such charge shall be in lieu of costs and expenses of all offices and salaries or wages plus applicable burdens and expenses of all personnel, except those directly chargeable under Paragraph 3A, Section II. The cost and expense of services from outside sources in connection with matters of taxation, traffic, accounting or matters before or involving governmental agencies shall not be considered as included in the overhead rates.
ii. The salaries, wages and Personal Expenses of Technical Employees and/or the cost of professional consultant services and contract services of technical personnel directly employed on the Joint Property shall not be covered by the overhead rates.
iii. The salaries, wages and Personal Expenses of Technical Employees and/or costs of professional consultant services and contract services of technical personnel either temporarily or permanently assigned to and directly employed in the operation of the Joint Property shall not be covered by the overhead rates.
A. Overhead - Fixed Rate Basis
(1) Operator shall charge the Joint Account at the following rates per well per month:
For wells located in the Hugoton Field Drilling Well Rate $2,350.00
(Prorated for less than a full month)
Producing Well Rate $235.00
For wells located in all other areas
Drilling Well Rate $4,760.00
(Prorated for less than a full month)
Producing Well Rate $476.00
(2) Application of Overhead - Fixed Rate Basis shall be as follows:
(a) Drilling Well Rate
(1) Charges for drilling wells shall begin on the date the well is spudded and terminate on the date the drilling rig, completion rig, or other units used in completion of the well is released, whichever is later, except that no charge shall be made during suspension of drilling or completion operations for fifteen (15) or more consecutive calendar days.
(2) Charges for wells undergoing any type of workover or recompletion or swabbing shall be made at the drilling well rate. Such charges shall be
applied for the period from date such operations, with rig or other units used, commence through date of rig or other unit release, except that no charge shall be made during suspension of operations for fifteen (15) or more consecutive calendar days.
(b) Producing Well Rates
(1) An active well either produced or injected into for any portion of the month shall be considered as a one-well charge for the entire month.
(2) Each active completion in a multi-completed well in which production is not commingled down hole shall be considered as a one-well charge providing each completion is considered a separate well by the governing regulatory authority.
(3) An inactive gas well shut in because of overproduction or failure of purchaser to take the production shall be considered as a one-well charge providing the gas well is directly connected to a permanent sales outlet.
(4) A one-well charge shall be made for the month in which plugging and abandonment operations are completed on any well. This one-well charge shall be made whether or not the well has produced except when drilling well rate applies.
(5) All other inactive wells (including but not limited to inactive wells covered by unit allowable, lease allowable, transferred allowable, etc.) shall not qualify for an overhead charge.
(3) The well rates shall be adjusted as of the first day of April each year beginning in 1999. The adjustment shall be computed by multiplying the rate currently in use 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 rates shall be the rates currently in use, plus or minus the computed adjustment.
2. Overhead - Major Construction
To compensate Operator for overhead costs incurred in the construction and installation of fixed assets, the expansion of fixed assets, and any other project clearly discernable as a fixed asset required for the development and operation of the Joint Property, Operator shall charge the Joint Account for overhead based on the following rates for any Major Construction project in excess of $25,000.00:
A. 5% of first $100,000 or total cost if less, plus
B. 3% of costs in excess of $100,000 but less than $1,000,000, plus
C. 2% of costs in excess of $1,000,000.
Total cost shall mean the gross cost of any one project. For the purpose of this paragraph, the component parts of a single project shall not be treated separately and the cost of drilling and workover wells and artificial lift equipment shall be excluded.
3. Catastrophe Overhead
To compensate Operator for overhead costs incurred in the event of expenditures resulting from a single occurrence due to oil spill, blowout, explosion, fire, storm, hurricane, or other catastrophes as agreed to by the Parties, which are necessary to restore the Joint Property to the equivalent condition that existed prior to the event causing the expenditures, Operator shall charge the Joint Account for overhead based on the following rates:
A. 5% of total costs through $100,000; plus
B. 3% of total costs in excess of $100,000 but less than $1,000,000; plus
C. 2% of total costs in excess of $1,000,000.
Expenditures subject to the overheads in this Section 3 above will not be
reduced by insurance recoveries, and no other overhead provisions of this
Section III shall apply.
IV. PRICING OF JOINT ACCOUNT MATERIAL PURCHASES, TRANSFERS AND DISPOSITIONS
Operator is responsible for Joint Account Materials and shall make proper and timely charges and credits for all Material movements affecting the Joint Property. Operator shall provide all Material for use on the Joint Property. Operator shall make timely disposition of idle and/or surplus Material, such disposal being made either through sale to Operator, or sale to outsiders. Operator may purchase, but shall be under no obligation to purchase, interest of the Trust in surplus condition A or B Material at the prices defined below.
1. Purchases
Material purchased shall be charged at the price paid by Operator after deduction of all discounts, adjustments or rebates received. In case of Material found to be defective or returned to vendor for any other reasons, credit shall be passed to the Joint Account when adjustment has been received by the Operator.
2. Transfers and Dispositions
Material furnished to the Joint Property and Material transferred from the Joint Property or disposed of by the Operator shall be priced on the following basis exclusive of cash discounts:
A. New Material (Condition A)
(1) Tubular Goods Other than Line Pipe
(a) Tubular goods, sized 2-3/8 inches OD and larger, except line pipe, shall be priced at Eastern mill published carload prices effective as of date of movement plus transportation cost using the 80,000 pound carload weight basis to the railway receiving point nearest the Joint Property for which published rail rates for tubular good exist. If the 80,000 pound rail rate is not offered, the 70,000 pound or 90,000 pound rail rate may be used. Freight charges for tubing will be calculated from Lorain, Ohio and casing from Youngstown, Ohio.
(b) For grades which are special to one mill only, prices shall be computed at the mill base of that mill plus transportation cost from that mill to the railway receiving point nearest the Joint Property as provided above in Paragraph 2.a.(1)(a). For transportation cost from points other than Eastern mills, the 30,000 pound Oil Field Haulers Association interstate truck rate shall be used.
(c) Special end finish tubular goods shall be priced at the lowest published out-of-stock price, f.o.b. Houston, Texas, plus transportation cost, using Oil Field Haulers Association interstate 30,000 pound truck rate, to the railway receiving point nearest the Joint Property.
(d) Macaroni tubing (size less than 2-3/8 inch OD) shall be priced at the lowest published out-of-stock prices f.o.b. the supplier plus transportation costs, using the Oil Field Haulers Association interstate truck rate per weight of tubing transferred, to the railway receiving point nearest the Joint Property.
(2) Line Pipe
(a) Line pipe movements (except size 24 inch OD and larger with walls 3/4 inch and over) 30,000 pounds or more shall be priced under provisions of tubular goods pricing in Paragraph A.(1)(a) as provided above. Freight charges shall be calculated from Lorain, Ohio.
(b) Line pipe movements (except size 24 inch OD and larger with
walls 3/4 inch and over) less than 30,000 pounds shall be
priced at Eastern mill published carload base prices
effective as of date of shipment, plus 20 percent, plus
transportation costs based on freight rates as set forth
under provisions of tubular goods pricing in Paragraph
A.(1)(a) as provided above. Freight charges shall be
calculated from Lorain, Ohio.
(c) Line pipe 24 inch OD and over and 3/4 inch wall and larger shall be priced f.o.b. the point of manufacture at current new published prices plus transportation cost to the railway receiving point nearest the Joint Property.
(d) Line pipe, including fabricated line pipe, drive pipe and conduit not listed on published price lists shall be priced at quoted prices plus freight to the railway receiving point nearest the Joint Property or at prices agreed to by the Parties.
(3) Other Material shall be priced at the current new price, in effect at date of movement, as listed by a reliable supply store nearest the Joint Property, or point of manufacture, plus transportation costs, if applicable, to the railway receiving point nearest the Joint Property.
(4) Unused new Material, except tubular goods, moved from the Joint Property shall be priced at the current new price, in effect on date of movement, as listed by a reliable supply store nearest the Joint Property, or point of manufacture, plus transportation costs, if applicable, to the railway receiving point nearest the Joint Property. Unused new tubulars will be priced as provided above in Paragraph 2 A (1) and (2).
B. Good Used Material (Condition B)
Material in sound and serviceable condition and suitable for reuse without reconditioning:
(1) Material moved to the Joint Property
At seventy-five percent (75%) of current new price, as determined by Paragraph A.
(2) Material used on and moved from the Joint Property
(a) At seventy-five percent (75%) of current new price, as determined by Paragraph A, if Material was originally charged to the Joint Account as new Material.
(b) At sixty-five percent (65%) of current new price, as determined by Paragraph A, if Material was originally charged to the Joint Account as used Material.
(3) Material not used on and moved from the Joint Property
At seventy-five percent (75%) of current new price as determined by Paragraph A.
The cost of reconditioning, if any, shall be absorbed by the transferring property.
C. Other Used Material
(1) Condition C
Material which is not in sound and serviceable condition and suitable for its original function until after reconditioning shall be priced at fifty percent (50%) of current new price as determined by Paragraph A. The cost of reconditioning shall be charged to the receiving property, provided Condition C value plus cost of reconditioning does not exceed Condition B value.
(2) Condition D
Material, excluding junk, no longer suitable for its original purpose, but usable for some other purpose shall be priced on a basis commensurate with its use. Operator may dispose of Condition D Material under procedures normally used by Operator without prior approval of the Assignee.
(a) Casing, tubing or drill pipe used as line pipe shall be priced as Grade A and B seamless line pipe of comparable size and weight. Used casing, tubing or drill pipe utilized as line pipe shall be priced at used line pipe prices.
(b) Casing, tubing or drill pipe used as higher pressure service lines than standard line pipe, e.g. power oil lines, shall be priced under normal pricing procedures for casing, tubing, or drill pipe. Upset tubular goods shall be priced on a non upset basis.
(3) Condition E
Junk shall be priced at prevailing prices. Operator may dispose of Condition E Material under procedures normally utilized by Operator without prior approval of Non-Operators.
D. Obsolete Material
Material which is serviceable and usable for its original function but condition and/or value of such Material is not equivalent to that which would justify a price as provided above may be specially priced as reasonably determined by Operator. Such price should result in the Joint Account being charged with the value of the service rendered by such Material.
E. Pricing Conditions
(1) Loading and unloading costs related to the movement of the Material to the Joint Property shall be charged in accordance with the methods specified in COPAS Bulletin 21.
(2) Material involving erection costs shall be charged at applicable percentage of the current knocked-down price of new Material.
3. Premium Prices
Whenever Material is not readily obtainable at published or listed prices because of national emergencies, strikes or other unusual causes over which the Operator has no control, the Operator may charge the Joint Account for the required Material at the Operator's actual cost incurred in providing such Material, in making it suitable for use, and in moving it to the Joint Property.
4. Warranty of Material Furnished by Operator
Operator does not warrant the Material furnished. In case of defective Material, credit shall not be passed to the Joint Account until adjustment has been received by Operator from the manufacturers or their agents.
V. INVENTORIES
The Operator shall maintain detailed records of Controllable Material.
1. Periodic Inventories, Notice and Representation
At reasonable intervals, inventories shall be taken by Operator of the Joint Account Controllable Material.
2. Reconciliation and Adjustment of Inventories
Adjustments to the Joint Account resulting from the reconciliation of a physical inventory shall be made within six months following the taking of the inventory. Inventory adjustments shall be made by Operator to the Joint Account for overages and shortages, but Operator shall be held accountable only for shortages due to lack of reasonable diligence.
3. Special Inventories
Special inventories may be taken whenever there is any sale, change of interest, or change of Operator in the Joint Property. It shall be the duty of the party selling to notify all other Parties as quickly as possible after the transfer of interest takes place. In such cases, both the seller and the purchaser shall be governed by such inventory. In cases involving a change of Operator, all Parties shall be governed by such inventory.
4. Expense of Conducting Inventories
A. The expense of conducting periodic inventories shall not be charged to the Joint Account.
B. The expense of conducting special inventories shall be charged to the Parties requesting such inventories, except inventories required due to change of Operator shall be charged to the Joint Account.
EXHIBIT 10.2.1
NET OVERRIDING ROYALTY CONVEYANCE
Hugoton Royalty Trust
STATE OF OKLAHOMA (S)
(S)
COUNTIES OF BEAVER, (S)
BECKHAM, CIMARRON, (S) KNOW ALL MEN BY THESE PRESENTS:
ELLIS, HARPER, MAJOR, (S)
TEXAS, WASHITA, WOODS (S)
AND WOODWARD (S)
|
THAT CROSS TIMBERS OIL COMPANY, a corporation formed under the laws of the State of Delaware ("Assignor"), for and in consideration of the sum of Ten Dollars ($10.00) and other good and valuable consideration to Assignor paid by NATIONSBANK, N.A., a bank organized under the laws of the United States, acting not in its individual corporate capacity but solely as trustee under that certain Trust Indenture establishing the Hugoton Royalty Trust dated as of December 1, 1998 ("Assignee"), the receipt and sufficiency of which are hereby acknowledged, has bargained, sold, granted, conveyed, transferred, assigned, set over and delivered, and by these presents does bargain, sell, grant, convey, transfer, assign, set over and deliver unto Assignee a net overriding royalty interest ("the Royalty Interest") in and to the Subject Hydrocarbons in and under, and if, as and when produced, saved and sold from, the Subject Lands during the term of the Subject Interests on and after the Effective Date equal to eighty percent (80%) of the Net Proceeds attributable to the Subject Interests, as each of the above capitalized words is defined in Article I hereof and all as more fully provided herein.
TO HAVE AND TO HOLD the Royalty Interest, together with all and singular the rights and appurtenances thereto in anywise belonging, unto Assignee, its successors and assigns, subject, however, to the terms and provisions of this Conveyance; and Assignor does by these presents bind and obligate itself, its successors and assigns, to WARRANT and FOREVER defend all and singular the Royalty Interest unto the said Assignee, its successors and assigns, against every person whomsoever lawfully claiming or to claim the same or any part thereof by, through or under Assignor, but not otherwise.
ARTICLE I
DEFINITIONS
As used herein, the following words, terms or phrases have the following meanings:
SECTION 1.01. "Affiliate" means, as to the party specified, any Person controlling, controlled by or under common control with such party, with the concept of control in such context meaning the possession, directly or indirectly, of the power to direct or cause the direction of the
management and policies of another, whether through the ownership of voting securities, by contract or otherwise. The Trust shall not be deemed an Affiliate of Assignor.
SECTION 1.02. "Assignor" means the Assignor named herein while Assignor owns all or any part of or interest in the Subject Interests and any other Person or Persons (excluding Assignee) who hereafter may acquire all or any part of or interest in the Subject Interests.
SECTION 1.03. "Assignee" means the Assignee named herein (and any successor Trustee under the Trust Indenture) while it owns all or any part of or interest in the Royalty Interest and any other Person or Persons who may acquire legal title to all or any part of or interest in the Royalty Interest.
SECTION 1.04. "Computation Period" means (i) initially, the period commencing on the Effective Date and ending on February 28, 1999, and (ii) each calendar month thereafter.
SECTION 1.05. "Conveyance" means this Net Overriding Royalty Conveyance.
SECTION 1.06. "Effective Date" means 7:00 o'clock A.M., local time in effect at the location of each Subject Interest, on December 1, 1998.
SECTION 1.07. "Excess Production Costs" means, for any Computation Period, an amount equal to the excess, if any, of Production Costs for such Computation Period over Gross Proceeds for such Computation Period.
SECTION 1.08. "Existing Sales Contracts" means all contracts and agreements in effect as of the Effective Date between or among Assignor and any Affiliate of Assignor, or between or among any Affiliates of Assignor, for the Sale, Processing, treatment, compression, gathering or transportation of Subject Hydrocarbons.
SECTION 1.09. "Gross Proceeds" means, for any Computation Period other than during the period from the Effective Date through January 31, 2000, and subject to Section 2.01 (i) during the term of the Existing Sales Contracts, the proceeds received by Assignor under the Existing Sales Contracts attributable to the Sale of Subject Hydrocarbons produced after the Effective Date and Sold during such Computation Period by Assignor after the Effective Date, and (ii) as to Subject Hydrocarbons produced after the Effective Date and Sold by Assignor during such Computation Period after the Effective Date other than under the Existing Sales Contracts (A) if Sold under a Sales Contract with a Non-Affiliate of Assignor, the proceeds received by Assignor under such Sales Contract, or (B) if Sold under a Sales Contract with an Affiliate of Assignor, the proceeds received by Assignor under such Sales Contract but in no event less than 98% of the proceeds received by such Affiliate upon the resale of such Subject Hydrocarbons to a Non-Affiliate of Assignor, and (iii) the proceeds received by Assignor in respect of underproduced gas imbalances attributable to the Subject Interests as of the Effective Date. "Gross Proceeds" means, for any Computation Period included in the period from the Effective Date through January 31, 2000, the sum of (i) for all Subject Hydrocarbons other than gas and natural gas liquids, if any, extracted from gas by Processing, the Gross Proceeds thereof, as defined above, and (ii) for that portion of the Subject Hydrocarbons that is gas and natural gas liquids, if any, extracted from gas by Processing, the greater
of (A) an imputed amount computed as if all gas for which proceeds are received attributed to the Subject Interests during the period relevant to such Computation Period was sold for a price of $2.00 per thousand cubic feet at the wellhead, and (B) the Gross Proceeds of the Sale thereof computed on the basis provided for Computation Periods other than during the period from the Effective Date through January 31, 2000; provided, however, that such computation under clause (B) above of this sentence shall be modified as needed to yield the weighted average sales price of all (gas and natural gas liquids, if any, extracted from gas by Processing) Sold that is included within Subject Hydrocarbons under all conveyances from Assignor to the Trust, not limited to this Conveyance. For purposes hereof, the "weighted average sales price of all gas" shall be determined for any Computation Period by dividing (A) the Gross Proceeds of the Sale of gas and natural gas liquids, if any, extracted from gas by Processing for such Computation Period (determined as provided above for all Computation Periods other than during the period from the Effective Date through January 31, 2000) attributable to any Subject Interests in which the Trust has a Royalty Interest ( and including Royalty Interests conveyed to the trust by Assignor under conveyances other than this Conveyance) by (B) the volume of such gas (in thousand cubic feet) attributable to such Subject Interests for such Computation Period. In all instances, the definition of "Gross Proceeds" shall be subject to the following:
(a) There shall be excluded from Gross Proceeds all Property Taxes that are deducted or excluded from proceeds of Sale received by Assignor and, for purposes of the calculation of Gross Proceeds under clause (ii)(A) of the second sentence of this Section 1.09, there shall also be excluded the amount of any additional Property Taxes that would have been paid by Assignor or withheld from Assignor if the imputed Sale price set forth therein had been the actual Sale price.
(b) There shall be excluded any amount for Subject Hydrocarbons attributable to nonconsent operations conducted with respect to the Subject Interests (or any portion thereof) as to which Assignor shall be a nonconsenting party and which is dedicated to the recoupment or reimbursement of costs and expenses of the consenting party or parties by the terms of the relevant operating agreement, unit agreement, contract for development or other instrument providing for such nonconsent operations. Assignor agrees that its election not to participate in such operations shall be made in conformity with the provisions of Section 6.01 of this Conveyance, but third persons shall not be under any duty to determine that such election so conformed.
(c) There shall be excluded any amount which Assignor shall receive as any of the following: consideration for transfer or sale of any of the Subject Interests (subject to the Royalty Interest) or equipment or other personal property or fixtures on the Subject Lands; payments for gas not taken, when such payments are made (but to the extent such payments are allocated to gas taken in the future such payments shall be included without interest in Gross Proceeds when such gas is taken); damages arising from any cause other than drainage or reservoir injury; rental for reservoir use; payments made to Assignor in connection with the drilling of any well on any of the Subject Lands or lands in the vicinity thereof (such exclusion including dry and bottom hole payments, provided that if such well is drilled on the Subject Lands and Assignor incurs Production Costs in connection therewith such payments shall reduce Production Costs) or in connection with any adjustment of any well
and leasehold equipment upon unitization of any of the Subject Interests; provided there shall be included in Gross Proceeds advance or prepaid payments for future production received by Assignor to the extent not subject to repayment in the event of insufficient subsequent production (and to the extent so subject to repayment shall be included without interest in Gross Proceeds when the Subject Hydrocarbons on which such payment was so advanced or prepaid are actually produced) and payments made to Assignor in connection with the deferring of drilling of any well on any of the Subject Lands (including payments from an operator in the vicinity for refraining from drilling an offset well).
(d) There shall be excluded any amount for Subject Hydrocarbons lost in the production or marketing thereof or used by Assignor in conformity with ordinary or prudent practices for drilling, production and plant operations (including gas injection, secondary recovery, pressure maintenance, repressuring, cycling operations, plant fuel or shrinkage) conducted for the purpose of drilling for, producing or Processing Subject Hydrocarbons or for operations on any unit or plant to which the Subject Interests are committed, but only so long as such Subject Hydrocarbons are so used.
(e) Amounts received as a loan by Assignor from a purchaser of Subject Hydrocarbons, whether with or without interest, shall not be considered to be derived from the sale of Subject Hydrocarbons.
(f) If a controversy or possible controversy exists (whether by reason of any statute, order, decree, rule, regulation, contract or otherwise) between Assignor and any purchaser as to the correct sales price of any Subject Hydrocarbons or, for any other reason, as to Assignor's right to receive or collect the proceeds of sale of any Subject Hydrocarbons, then
(i) amounts withheld by the purchaser or deposited by it with an escrow agent shall not be considered to be received by Assignor until actually collected by Assignor, but the amounts received by Assignor shall include any interest, penalty or other amount paid to Assignor in respect thereof;
(ii) amounts received by Assignor and promptly deposited by it with an escrow agent shall not be considered to have been received by Assignor, but all amounts thereafter paid to Assignor by such escrow agent shall be considered to be amounts received from the Sale of Subject Hydrocarbons; and
(iii) amounts received by Assignor and not deposited with an
escrow agent shall be considered to be received for purposes of this
Section 1.09.
SECTION 1.10. "Hydrocarbons" means oil, gas (which term includes coal bed gas, coal seam gas and methane) and all other minerals produced in association with oil or gas (including, but not limited to, helium, sulphur and carbon dioxide), but excluding all other minerals, whether similar or dissimilar.
SECTION 1.11. "Monthly Record Date" for each month means the close of business on the last day of such month which 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, unless Assignee determines that a different date is required to comply with applicable law or the rules of a securities exchange or quotation system pursuant to the terms of the Trust Indenture, in which event it means such different date.
SECTION 1.12. "Net Proceeds" means, for any Computation Period, the excess of Gross Proceeds for such Computation Period over Production Costs for such Computation Period.
SECTION 1.13. "Non-Affiliate" means, as to the party specified, any Person who is not an Affiliate of such party.
SECTION 1.14. "Person" means any individual, corporation, partnership, limited liability company, trust, estate or other entity, organization or association.
SECTION 1.15. "Prime Interest Rate" means the variable rate of interest most recently announced by NationsBank, N.A. as its "prime rate."
SECTION 1.16. "Process" or "Processing" means to extract or otherwise recover natural gas liquids from natural gas included in the Subject Hydrocarbons through the processes of absorption, condensation, adsorption, cryogenic or other methods in a manner that does not constitute Separation.
SECTION 1.17. "Processing Costs" means the costs to Assignor or any Affiliate of Assignor to Process Subject Hydrocarbons before the Sale thereof, which costs for purposes hereof shall consist of the sum of (a) any such Processing charges paid to Non-Affiliates, (b) the charges by Affiliates of Assignor under Existing Sales Contracts, and (c) the charges by Affiliates of Assignor other than under Existing Sales Contracts so long as such charges do not materially exceed charges prevailing in the area for similar services at the time of contracting for such charges.
If Assignor (or its Affiliates) receives a share of the production of others or of plant products therefrom (or proceeds of sale thereof) for Processing such production of others, such share shall not be included in Subject Hydrocarbons (or Gross Proceeds). If Assignor (or its Affiliates) does not bear any Processing Costs but the owners or operators of a plant receive a share of the Subject Hydrocarbons (or proceeds of sale thereof) for Processing them, such share (or proceeds) shall be excluded from the Subject Hydrocarbons (and Gross Proceeds).
SECTION 1.18. "Production Costs" means, for any Computation Period, to the extent not excluded for purposes of calculating Gross Proceeds, whether capital or non-capital in nature,
(a) the sum of
(i) all amounts paid by Assignor or any Affiliate of Assignor as any of the following: royalty, overriding royalty or other presently existing burden against production or the proceeds of Sale of production attributable to the Subject Interests;
delay rental; shut-in gas well royalty or payment; minimum royalty; payments to lessors or others in the area in connection with the drilling or deferring of drilling of any well on any of the Subject Lands or lands in the vicinity thereof (including dry and bottom hole payments and payments made to others for refraining from drilling an offset well) or in connection with any adjustment of any well and leasehold equipment upon unitization of any of the Subject Interests; and rent and other consideration paid for use of or damage to the surface;
(ii) the Property Tax Accrual;
(iii) the overhead costs paid by Assignor or any Affiliate of Assignor under any joint operating agreement applicable to any of the Subject Interests to which Assignor and one or more Non-Affiliates of Assignor are parties and where Assignor or any Affiliate of Assignor is not the operator of such Subject Interest;
(iv) the overhead rate provided for in any joint operating agreement applicable to any of the Subject Interests where Assignor or any Affiliate of Assignor is the operator of such Subject Interests, less the portion, if any, of the overhead rate due from Non-Affiliates of Assignor;
(v) with respect to any Subject Interests operated by Assignor or any of its Affiliates and not subject to a joint operating agreement, an overhead fee as shown on Schedule B attached hereto and subject to adjustment as provided in Schedule B attached hereto;
(vi) all other costs, expenses and liabilities (including Processing Costs) paid or incurred by Assignor or any Affiliate of Assignor for investigating, exploring, prospecting, drilling and mining for, operating and producing Subject Hydrocarbons and sale and marketing thereof, including without implied limitation: costs for equipping, plugging back, reworking, completing, recompleting and plugging and abandoning of any well on the Subject Lands and of making the Subject Hydrocarbons ready or available for market; costs for construction and operation of gathering lines, tanks, transmission lines, meters and other production and delivery facilities; costs, whether paid in cash or by a share of Subject Hydrocarbons, of transporting, compressing, dehydrating, separating, treating, storing and marketing the Subject Hydrocarbons and disposing of extraneous substances produced in association with Subject Hydrocarbons (provided that such costs, if paid to or incurred by an Affiliate of Assignor other than pursuant to an Existing Sales Contract, shall not materially exceed charges prevailing in the area for similar services at the time of contracting for such charges); costs for secondary recovery, pressure maintenance, repressuring, cycling and other operations conducted for the purpose of enhancing production; costs or expenses (whether paid in cash or by delivery of gas) incurred in resolving overproduced gas imbalances attributable to the Subject Interests as of the Effective Date and thereafter; and costs for litigation concerning title to or operation of the Subject Interests and any other acts or omissions of Assignor consistent herewith or brought by Assignor to protect the
Subject Interests; and costs for litigation or regulatory proceedings concerning title to or operation of the Subject Interests and any other acts or omissions of Assignor consistent herewith or brought by Assignor to protect the Subject Interests or to protect or enforce any rights, contractual or otherwise, of Assignor to produce or market Subject Hydrocarbons therefrom;
(vii) Excess Production Costs for the preceding Computation Period (including any remaining Excess Production Costs carried forward from any preceding Computation Period);
(viii) interest on the amount of Excess Production Costs at the beginning of any Computation Period, calculated from the first day to the last day of the Computation Period, at the Prime Interest Rate in effect at the beginning of such Computation Period;
(ix) any amounts paid by Assignor or any Affiliate of Assignor whether as refund, interest or penalty, to a purchaser or any governmental agency or other Person because the amount initially received by Assignor (or Affiliate of Assignor) as sales price for Sales after the Effective Date was more or allegedly more than permitted by the terms of any applicable contract, statute, regulation, order, decree or other obligation; provided such amounts (in the case of a refund), or the amounts with respect to which the interest or penalty was paid, were previously included in Gross Proceeds;
(x) any other amounts paid by Assignor or any Affiliate of Assignor with respect to ownership or operation of the Subject Interests after the Effective Date or Sales of production therefrom after the Effective Date, whether as refund, fine, interest or penalty, pursuant to litigation or settlement of threatened litigation or order of governmental agency, provided that Assignor has not breached Section 6.01 hereof;
(xi) all consideration hereafter paid and costs and expenses hereafter incurred by Assignor or any Affiliate of Assignor for any renewals or extensions of leases or other rights acquired after the Effective Date which are included in the definition herein of Subject Interests; and
(xii) any accrual or reserve which Assignor or any Affiliate of Assignor shall have the right, at its election, to charge to Production Costs for operations (other than day-to-day operations) budgeted under an operating agreement or approved under an authorization for expenditures ("AFE"), which accrual or reserve may be based on the reasonably expected time of performing such operation or on an estimated percentage of completion of the operation or on any other reasonable method, and which accrual is in lieu of charging the cost of such operation when paid for by Assignor (or Affiliate of Assignor) but which shall be adjusted if and to the extent actual costs differ from such accrual or reserve;
(b) but excluding
(i) costs which would otherwise be treated as Production Costs (but which shall not be so treated for purposes hereof until the following amounts have been fully credited against such costs) equal to amounts reimbursed or credited to Assignor by insurance from damage to property, by sales of property or transfers of property off the leases included in the Subject Interests or by proceeds from unitization or other disposition of property; and
(ii) except for resolution of gas imbalances which are included in Section 1.18(a)(vi) above, any amounts which would otherwise be Production Costs but which are attributable to periods before the Effective Date; and
(iii) costs that otherwise would be treated as Production Costs but which have already been excluded or deducted from Gross Proceeds under Section 1.09; and
(iv) costs incurred by any Affiliate of Assignor for which such Affiliate has received a fee, reimbursement or other payment from Assignor, where such payment by Assignor constitutes a Production Cost.
SECTION 1.19. "Property Taxes" means the sum of all general property (ad valorem), production, severance, sales, gathering and excise taxes and other taxes (whether state, federal or otherwise), except income taxes, assessed or levied on or in connection with the Subject Interests, the Royalty Interest or the production therefrom or equipment on the Subject Lands, or against Assignor as owner of the Subject Interests or Assignee as owner of the Royalty Interest.
SECTION 1.20. "Property Tax Accrual" means, for any Computation Period, an amount that may be set aside by Assignor as an accrual to be applied against Property Taxes other than those that are deducted or excluded from Gross Proceeds pursuant to Section 1.09(a) above, which accruals shall be adjusted to the extent actual Property Taxes differ.
SECTION 1.21. "Sale" and "Sold" mean all forms of dispositions of Subject Hydrocarbons for value, including exchanges and other dispositions for value.
SECTION 1.22. "Sales Contracts" means all contracts and agreements for the sale of Subject Hydrocarbons.
SECTION 1.23. "Separation" means liquid separation operations in the vicinity of the well using a conventional mechanical liquid gas separator but excluding operations involving heat exchange, adiabatic cooling, absorption, adsorption or refrigeration principles.
SECTION 1.24. "Subject Hydrocarbons" means all Hydrocarbons in and under, and which may be produced, saved and sold from, and which shall accrue and be attributable to, the Subject Interests on and after the Effective Date, including plant products attributable thereto from
Processing gas or casinghead gas included in the Subject Hydrocarbons before sale thereof (but not including products derived from processing oil).
SECTION 1.25. "Subject Interests" means, subject to the exclusions stated below, each kind and character of right, title, claim or interest which Assignor has on the Effective Date in or under each oil, gas or mineral lease, unitization or pooling agreement (and the units created thereby), royalty interests, overriding royalty interests, fee mineral interests and net profits interests and any other agreements, conveyances, assignments or instruments which are described or referred to in Schedule A, and all the right, title, claim or interest which Assignor has on the Effective Date in and to the Subject Lands, whether such right, title, claim or interest be under and by virtue of a lease, a unitization or pooling agreement or order, an operating agreement, a division order, a transfer order or any other type of agreement, conveyance, assignment or instrument or under any other type of claim or title, legal or equitable, recorded or unrecorded, even though Assignor's interests be incorrectly or incompletely described in, or a description thereof be omitted from, Schedule A, all as the same shall be enlarged by the discharge of any payments out of production or by the removal of any charges or encumbrances to which any of the same are subject and any and all renewals and extensions of any of the same, but subject to all burdens to which Assignor's such right, title, claim or interest is subject (while same remains so subject), limited, however, if Assignor's interest in any Subject Interest should terminate at any time, to the period to which Assignor's interest in such Subject Interest is limited. There shall be excluded from the term "Subject Interests" any interest hereafter acquired by Assignor in and to any of the Subject Lands, except any interest acquired pursuant to existing agreements for no new consideration and renewals or extensions of existing leases and other such agreements. For purposes of this Conveyance "renewals or extensions" of any lease or other such agreement shall be limited to renewals or extensions of an existing lease or other such agreement obtained by the present owner thereof (or such owner's successors in interest) while such lease is in force or within six months after such lease or other such agreement terminates. Assignor shall be under no duty to seek renewals or extensions of any lease or other such agreement.
SECTION 1.26. "Subject Lands" means the lands which are described in and which are subject to the oil, gas or mineral leases, unitization or pooling agreements or orders, operating agreements, division orders, transfer orders or other type of agreement, conveyance, assignment or instrument described in Schedule A attached hereto, provided that, where the description in Schedule A excepts land or refers to an instrument insofar only as it covers certain land or certain depths in certain land, no interest in such excepted land or depths or in land other that to which such reference is limited shall be included in the terms "Subject Lands" or "Subject Interests".
SECTION 1.27. "Trust" means the Hugoton Royalty Trust established by the Trust Indenture.
SECTION 1.28. "Trust Indenture" means the Royalty Trust Indenture by and between Cross Timbers Oil Company and NationsBank, N.A. dated as of December 1, 1998, establishing the Hugoton Royalty Trust, an express Texas Trust under the Texas Trust Code.
ARTICLE II
MARKETING OF SUBJECT HYDROCARBONS
SECTION 2.01. Sales Contracts. Assignor, to the extent it has the right to do so, shall market or cause to be marketed the Subject Hydrocarbons and Assignee shall have no authority to market the Subject Hydrocarbons or to take in-kind any Subject Hydrocarbons. For such purpose, Sales of Subject Hydrocarbons may continue to be made pursuant to Existing Sales Contracts. Assignor may amend such Existing Sales Contracts and may enter into one or more Sales Contracts in the future at the prices and on the terms Assignor shall deem proper in Assignor's sole and absolute discretion, which may include sales to Affiliates of Assignor. Further, Assignor may commit any of the Subject Interests (including the Royalty Interest attributable thereto) to one or more agreements for Processing pursuant to which, by way of example and not by way of limitation, the plant owner or operator (which may be an Affiliate of Assignor) receives a portion of the Subject Hydrocarbons or plant products derived therefrom or proceeds of the Sale thereof as a fee for Processing. Except as provided otherwise in Section 1.09 for the period from the Effective date through January 31, 2000, Gross Proceeds of Subject Hydrocarbons shall be determined on the basis of amounts actually received by Assignor (and not, except as provided in Section 1.09, proceeds received by any of Assignor's Affiliates) from Sales under Sales Contracts regardless of whether at the time of production or Sale market value should be different from proceeds of Sale. In no event shall Gross Proceeds or Production Costs include any revenues, expenses, gains or losses resulting from option transactions or other futures or hedging transactions (other than forward Sales of the Subject Hydrocarbons) which, if engaged in by Assignor or any of its Affiliates in respect of Subject Hydrocarbons, shall be solely for the account of Assignor or such Affiliate.
SECTION 2.02. Delivery of Subject Hydrocarbons. All Subject Hydrocarbons Sold by Assignor, whether pursuant to Sales Contracts or otherwise, shall be delivered, by Assignor to the purchasers thereof, into the pipelines to which the wells producing such Subject Hydrocarbons may be connected or to such other point of purchase as is reasonably required in the marketing of such Subject Hydrocarbons.
SECTION 2.03. Reliance by Third Party. As to any party, the acts of Assignor shall be binding on Assignee. It shall not be necessary for Assignee to join with Assignor in any division or transfer order, lease extension or Sales Contract, and proceeds of Sale of the Subject Hydrocarbons shall be paid by the purchasers thereof (or others disbursing proceeds) directly to Assignor without necessity of joinder by or consent of Assignee.
ARTICLE III
PAYMENTS
SECTION 3.01. Payment. On or before each Monthly Record Date, beginning with the Monthly Record Date for March, 1999, Assignor shall pay to Assignee as an overriding royalty hereunder an amount equal to eighty percent (80%) of the Net Proceeds for the preceding Computation Period. All payments made to Assignee on account of the Royalty Interest shall be made entirely and exclusively out of sale proceeds attributable to the production of Hydrocarbons
from, or attributed to, the Subject Interests after the Effective Time. Accordingly, the amount of any Net Proceeds in respect of a Computation Period which cannot be paid out of the sale proceeds of production of Hydrocarbons from, or attributed to, the Subject Interests shall be carried over and included in Net Proceeds in the next Computation Period; provided, however, such amount shall only be payable from the Hydrocarbons produced from or attributable to the Subject Interests and the sale proceeds thereof, if any.
SECTION 3.02. Interest on Past Due Payments. Except as otherwise provided in Section 9.05 hereof, any amount not paid by Assignor to Assignee when due shall bear, and Assignor will pay, interest determined at the end of each month, from such due date until such amount is paid, at the rate of the lesser of (a) the Prime Interest Rate plus 4% or (b) the maximum lawful contract rate of interest permitted by the applicable usury laws, now or hereafter enacted, which interest rate (the "Maximum Rate") shall change when and as said laws change, effective at the close of business on the day such change in said laws becomes effective; but, if there shall be no Maximum Rate, then the rate shall be as specified in the foregoing clause (a).
SECTION 3.03. Overpayment. If at any time Assignor pays Assignee more than the amount due, Assignee shall not be obligated to return any such overpayment, but the amount or amounts otherwise payable to Assignee for any subsequent period or periods shall be reduced by such overpayment, plus an amount equal to interest during the period of such overpayment at the rate of the lesser of (a) the Prime Interest Rate or (b) the Maximum Rate; but if there shall be no Maximum Rate, then the rate shall be as specified in the foregoing clause (a).
ARTICLE IV
RECORDS AND REPORTS
SECTION 4.01. Books and Records. Assignor shall at all times maintain true and correct books and records sufficient to determine the amounts payable to Assignee hereunder, including, but not limited to, a Net Proceeds account to which Gross Proceeds and Production Costs are credited and charged.
SECTION 4.02. Inspections. The books and records referred to in Section 4.01 shall be open for inspection by Assignee and its agents and representatives at the office of Assignor during normal business hours and after reasonable advance notice.
SECTION 4.03. Quarterly Statements. Within thirty (30) days next following the close of each calendar quarter, Assignor shall deliver to Assignee a statement showing the computation of Net Proceeds attributable to such quarter.
SECTION 4.04. Assignee's Exceptions to Quarterly Statements. If Assignee shall take exception to any item or items included in the quarterly statements rendered by Assignor, Assignee shall notify Assignor in writing within 180 days after the receipt of the report and annual audit furnished pursuant to Section 4.07 hereof, setting forth in such notice the specific charges complained of and to which exception is taken or the specific credits which should have been made and allowed; and, with respect to such complaints and exceptions as are justified, adjustment shall
be made. If Assignee shall fail to give Assignor notice of such complaints and exceptions prior to the expiration of such 180 day period, then the statements for such calendar year as originally rendered by Assignor shall be deemed to be correct as rendered.
SECTION 4.05. Geological and Other Data. Upon request by Assignee, Assignor
shall, subject to the limitations of confidentiality or nondisclosure
obligations to co-owners or other third parties, furnish to Assignee access to
all geological, well and production data which Assignor has on hand relating to
operations on the Subject Interests. Assignor will use reasonable efforts to
obtain waivers of any such confidentiality or nondisclosure obligations that
prevent it from providing to Assignee any requested information, but Assignor
shall not be obligated to incur any expense or detriment above a nominal amount
to obtain such waiver. Assignor shall also furnish to Assignee, upon request by
Assignee, reports showing the status of development, producing and other
operations conducted by Assignor on the Subject Interests. Assignor shall, upon
request by Assignee, furnish to Assignee all reserve reports or studies in the
possession of Assignor from time to time relating to the Subject Interests,
whether prepared by Assignor or by third party consulting engineers; provided,
it is agreed that Assignor makes no representations or warranties as to the
accuracy or completeness of any such reports or studies and shall have no
liability to Assignee or any other Person resulting from their use of such
reports or studies, and Assignee agrees not to attribute to Assignor or such
third-party consulting engineers any such reports or studies or the contents
thereof in any securities filings or reports to owners or holders of "Beneficial
Interests" in the Trust. All information furnished to Assignee pursuant to this
section is confidential and for the sole benefit of Assignee and shall not be
shown by Assignee to any other Person, except that this provision shall not
prohibit the disclosure by Assignee of any information that (i) at the time of
disclosure is generally available to the public (other than as a result of a
disclosure by Assignee), (ii) was available to Assignee on a nonconfidential
basis from a source other than Assignor, provided that such source is not known
by Assignee to be bound by a confidentiality obligation owed to Assignor, or
(iii) Assignee is legally required to disclose, provided that Assignee has given
to Assignor notice of such requirement and a reasonable opportunity to seek, at
Assignor's expense, a protective order and other appropriate relief from such
requirement.
SECTION 4.06. Monthly Estimates. On or before ten days (excluding Saturdays, Sundays and other days on which national banking institutions in the City of Fort Worth, Texas, are closed as authorized or required by law) before each Monthly Record Date (beginning with the Monthly Record Date for March, 1999), Assignor shall deliver to Assignee a statement of Assignor's best estimate of the amount payable to Assignee on or before such Monthly Record Date.
SECTION 4.07. Annual Audits and Reports. Within 90 days after the end of the calendar year, Assignor shall deliver to Assignee a statement which has been audited by a nationally recognized firm of independent public accountants selected by Assignor, which shall show the information provided for in Section 4.03 on an annual basis. Assignee shall bear the cost of each such audit.
SECTION 4.08. Reserve Reports. Assignor may, but is not obligated to, provide an annual reserve report for the Royalty Interest prepared by independent consulting reservoir engineers. If such reserve report is provided by Assignor, Assignee will reimburse Assignor for the cost thereof.
ARTICLE V
LIABILITY OF ASSIGNEE
In no event shall Assignee be liable or responsible in any way for any Production Costs (including Excess Production Costs) or other costs or liabilities incurred by Assignor or others attributable to the Subject Interests or to the Hydrocarbons produced therefrom.
ARTICLE VI
OPERATION OF SUBJECT INTERESTS
SECTION 6.01. Prudent Operator Standard. Assignor agrees, to the extent it has the legal right to do so under the terms of any lease, operating agreement, contract for development or similar instrument affecting or pertaining to the Subject Interests (or any portion thereof), that it will conduct and carry on the maintenance and operation of the Subject Interests with reasonable and prudent business judgment and in accordance with good oil and gas field practices, and that it will drill such wells as a reasonably prudent operator would drill from time to time in order to protect the Subject Interests from drainage. Assignor further agrees to produce the Subject Interests without regard to whether any amount is imputed to the Gross Proceeds for any Computation Period during the period from the Effective Date through January 31, 2000, as provided in Section 1.09. However, nothing contained in this Section 6.01 shall be deemed to prevent or restrict Assignor from electing not to participate in any operation which is to be conducted under the terms of any operating agreement, contract for development or similar instrument affecting or pertaining to the Subject Interests (or any portion thereof) and allowing consenting parties to conduct nonconsent operations thereon, if such election is made by Assignor in good faith. Notwithstanding anything elsewhere herein to the contrary, Assignor shall never be liable to Assignee for the manner in which Assignor performs its duties hereunder as long as Assignor has acted in good faith.
SECTION 6.02. Abandonment of Properties. Nothing herein contained shall obligate Assignor to continue to operate any well or to operate or maintain in force or attempt to maintain in force any of the Subject Interests when, in Assignor's opinion, such well or Subject Interest ceases to produce or is not capable of producing Hydrocarbons in paying quantities. The expiration of a Subject Interest in accordance with the terms and conditions applicable thereto shall not be considered to be a voluntary surrender or abandonment thereof.
SECTION 6.03. Insurance. Although Assignor is permitted to carry policies of insurance covering the property upon the Subject Interests and risks incident to the operation thereof and to charge premiums therefor to the Net Proceeds account, Assignor shall not be required to carry insurance on such property or covering any of such risks unless it elects to do so. In no event shall Assignor be liable to Assignee on account of any losses sustained which are not covered by insurance.
SECTION 6.04. Certain Rights to Manage the Subject Interests.
Notwithstanding anything in this Conveyance to the contrary, Assignor shall have
the right and power, acting in good faith and as a reasonably prudent oil and
gas operator, to execute, deliver, and perform operating agreements,
oil and gas leases, farmout agreements, exploration agreements, participation agreements, drilling agreements, acreage contribution agreements, dry-hole agreements, bottom-hole agreements, joint venture agreements, partnership agreements, and other similar instruments and agreements that cover or affect the Subject Interests and to make all decisions or elections required thereunder, including, but not limited to, decisions to consent or non-consent to drilling and other operations. The applicable Royalty Interest shall in each case be bound by such instrument or agreement (and decisions or elections thereunder), without the necessity of any execution, consent, joinder, or ratification by Assignee, and the Royalty Interest shall thereafter be calculated and paid with respect to the interests reserved, obtained, or modified by Assignor in such transaction, not by reference to the Subject Interests that existed before such transaction. For example, but not by way of limitation, (a) Assignor may farm out any Subject Interest that is an oil and gas lease, and the Subject Interest therein shall subsequently be the overriding royalty interest, reversionary working interest, and/or other rights and interests reserved by Assignor in the farmout, not the original leasehold interest, or (b) Assignor may execute an oil and gas lease to cover any Subject Interest that is a mineral interest, and the Subject Interest shall subsequently be the royalty and other lease benefits obtained or reserved by Assignor in such lease, not the original mineral interest.
ARTICLE VII
POOLING AND UNITIZATION
SECTION 7.01. Pooled Subject Interests. To the extent any of the Subject Interests have been heretofore pooled and unitized for the production of Hydrocarbons, such Subject Interests are and shall be subject to the terms and provisions of such pooling and unitization agreements, and the Royalty Interest in each such Subject Interest shall apply to and affect only the production from such units which accrues to such Subject Interest under and by virtue of the applicable pooling and unitization agreements.
SECTION 7.02. Right to Pool and Unitize. Assignor shall have the exclusive right and power (as between Assignor and Assignee), exercisable only during the period provided in Section 7.03 hereof, to pool or unitize any of the Subject Interests and to alter, change or amend or terminate any pooling or unitization agreements heretofore or hereafter entered into, as to all or any part of the Subject Lands, as to any one or more of the formations or horizons thereunder, and as to any one or more Hydrocarbons, upon such terms and provisions as Assignor shall in its sole and absolute discretion determine. If and whenever through the exercise of such right and power, or pursuant to any law hereafter enacted or any rule, regulation or order of any governmental body or official hereafter promulgated, any of the Subject Interests are pooled or unitized in any manner, the Royalty Interest insofar as it affects such Subject Interest shall also be pooled and unitized, and in any such event such Royalty Interest in such Subject Interest shall apply to and affect only the production which accrues to such Subject Interest under and by virtue of the pooling and unitization, and it shall not be necessary for Assignee to agree to, consent to, ratify, confirm or adopt any exercise of such right and power by Assignor.
SECTION 7.03. Applicable Period. Assignor's power and rights in Section 7.02 shall be exercisable only during the period of the life of the last survivor of the descendants of the signers of the Declaration of Independence living on the date of execution hereof, plus twenty-one (21) years
after the death of such last survivor, or the term of this Conveyance, whichever period shall first expire.
ARTICLE VIII
GOVERNMENT REGULATION
All obligations of Assignor hereunder shall be subject to all present and future valid federal, state and local laws, statutes, codes and orders; and all applicable rules, orders, regulations and decisions of every court, governmental agency, body or authority having jurisdiction over the Hydrocarbons in and under and that may be produced from the Subject Interests. Assignor's obligations are specifically, but not by way of limitation, subject, to the extent in effect, to all applicable provisions of the Emergency Petroleum Allocation Act of 1973, the Department of Energy Organization Act, the Natural Gas Act, the Natural Gas Policy Act of 1978, the Natural Gas Wellhead Decontrol Act of 1989 and each other statute purporting to provide regulation of the Sale of Hydrocarbons or establishing maximum prices at which the same may be Sold and all applicable laws, orders, rules and regulations thereunder of the Federal Energy Regulatory Commission, the Department of Energy and each other legislative or governmental body, agency, board or commission having jurisdiction. If maximum rates permitted under such statutes, rules and regulations for the Subject Hydrocarbons are lower than prices established in Sales Contracts, then the lower regulated prices received by Assignor shall control. Assignor shall be entitled to use its reasonable discretion in making filings, for itself and on behalf of Assignee, with the Federal Energy Regulatory Commission, the Department of Energy or any other governmental body, agency, board or commission having jurisdiction, affecting the price or prices at which Subject Hydrocarbons may be Sold, and with purchasers of production, operators or others with respect to any excise tax.
ARTICLE IX
ASSIGNMENTS
SECTION 9.01. Assignment by Assignor. Assignor shall have the right to assign, sell, transfer, convey, mortgage or pledge the Subject Interests, or any part thereof, subject to the Royalty Interest and the terms and provisions of this Conveyance. From and after the effective date of any such assignment, sale, transfer or conveyance by Assignor, the assignee thereunder shall succeed to all the requirements upon and responsibilities of Assignor hereunder, as to the interests in the Subject Interests so acquired by such assignee, and, from and after the said effective date, Assignor shall be relieved of such requirements and responsibilities, excepting only those accrued or due for performance prior to such effective date.
SECTION 9.02. Partial Assignment. If Assignor assigns its interest under the Subject Interests as to some of such Subject Interests or as to some part thereof, then, effective as of the date of such assignment, in determining the Royalty Interest payable with respect to production from such assigned Subject Interests or parts thereof, the Gross Proceeds, Production Costs and Net Proceeds attributable to such assigned interests will be computed and determined by the assignee of such assigned interests in the aggregate as to the assigned interests owned by such assignee, but separate
from and not aggregated with the computation and determination made by Assignor as to Subject Interests that have not been assigned by Assignor.
SECTION 9.03. Assignment by Assignee. Assignee has the right to assign the Royalty Interest in whole or in part only as authorized by the Trust Indenture. However, no such assignment will affect the method of computing Net Proceeds, and if more than one Person becomes entitled to participate in the Royalty Interest, Assignor may withhold from such other Person payments to which such Person would otherwise be entitled hereunder and the furnishing of any data or information which Assignor is required by the terms hereof to furnish Assignee until Assignor is furnished a recordable instrument executed by or binding upon all Persons interested in the Royalty Interest designating one Person who is to receive such payments, data and information. In making conveyances or assignments of any of the Subject Interests (to the extent permitted hereunder), Assignee need not vest in its grantee or assignee all of the rights of Assignee hereunder with respect to the interest in the Subject Interests so conveyed or assigned.
SECTION 9.04. Certain Sales of Subject Interests. Subject to the limitations set forth in Section 3.02(b) of the Trust Indenture, Assignor may cause the sale of certain Subject Interests, including the appurtenant Royalty Interest from time to time and Assignee will join in such sales as provided in the Trust Indenture. The proceeds of any such sale shall be apportioned and paid as provided in the Trust Indenture, but the purchasers of such Subject Interests (inclusive of the appurtenant Royalty Interest) may pay the full amount of the purchase price therefor to Assignor and shall have no responsibility to see to the proper allocation thereof between Assignor and Assignee.
SECTION 9.05. Change in Ownership. No change of ownership or right to receive payment of the Royalty Interest, or of any part thereof, however accomplished, shall be binding upon Assignor until notice thereof shall have been furnished by the Person claiming the benefit thereof, and then only with respect to payments thereafter made. Notice of sale or assignment shall consist of a certified copy of the recorded instrument accomplishing the same; notice of change of ownership or right to receive payment accomplished in any other manner (for example by reason of incapacity, death or dissolution) shall consist of certified copies of recorded documents and complete proceedings legally binding and conclusive of the rights of all parties. Until such notice accompanied by such documentation shall have been furnished Assignor as above provided, the payment or tender of all sums payable on the Royalty Interest may be made in the manner provided herein precisely as if no such change in interest or ownership or right to receive payment had occurred, or (at Assignor's election) Assignor shall have the right to suspend payment of such sums without interest in the event of such change until such documentation is furnished. The kind of notice herein provided shall be exclusive, and no other kind, whether actual or constructive, shall be binding on Assignor.
SECTION 9.06. Rights of Mortgagee or Trustee. If Assignee shall at any time execute a mortgage or deed of trust covering all or part of the Royalty Interest, the mortgagee(s) or trustee(s) therein named or the holder of any obligation secured thereby shall be entitled, to the extent such mortgage or deed of trust so provides, to exercise all the rights, remedies, powers and privileges conferred upon Assignee by the terms of this Conveyance and to give or withhold all consents required to be obtained hereunder by Assignee, but the provisions of this Section 9.06 shall in no
way be deemed or construed to impose upon Assignor any obligation or liability undertaken by Assignee under such mortgage or deed of trust or under the obligation secured thereby.
ARTICLE X
MISCELLANEOUS
SECTION 10.01. Proportionate Reduction. In the event of failure or deficiency in title to any of the Subject Interests, the portion of the production from such Subject Interest out of which the Royalty Interest attributable to such Subject Interest shall be payable shall be reduced in the same proportion that such Subject Interest is reduced. Notwithstanding the foregoing, if any Person claims that this Conveyance gives rise to a preferential right of such Person to acquire any portion of the Royalty Interest (or any of the Subject Interests), then Assignor shall indemnify Assignee and the trustee of the Trust against any liability, expense, damage or loss in regard to such claim and the provisions of Section 6.05 of the Trust Indenture shall apply with respect to such indemnity obligation. If such claim results in the acquisition of any portion of the Royalty Interest by the Person claiming the preferential right then, subject to the proviso below, Assignor shall pay to Assignee the amount determined by multiplying (i) the product of 40,000,000 multiplied by the initial public offering price of the Trust's units of beneficial interest by (ii) a fraction, the numerator of which is the value of the portion of the Royalty Interest acquired by the Person claiming the preferential right, as determined by reference to the most recent Reserve Report (as defined in the Trust Indenture) of the Trust and the denominator of which is the value of all the Royalty Interest as determined by reference to such Reserve Report; provided, however, that if the Person claiming such preferential right makes any payment to the Trust in connection with the acquisition of a portion of the Royalty Interest, then the amount of such payment shall be credited against Assignor's payment obligation set forth above, but not to create a negative number.
SECTION 10.02. Term. This Conveyance shall remain in force as long as any of the Subject Interests are in effect.
SECTION 10.03. Further Assurances. Should any additional instruments of assignment and conveyance be required to describe more specifically any interests subject hereto, Assignor agrees to execute and deliver the same. Also, if any other or additional instruments are required in connection with the transfer of State, Federal or Indian lease interests in order to comply with applicable laws, regulations or agreements, Assignor will execute and deliver the same.
SECTION 10.04. Notices. All notices, statements, payments and communications between the parties hereto shall be deemed to have been sufficiently given and delivered if enclosed in a post paid wrapper and deposited in the United States Mails directed, or if personally delivered, to the party to whom the same is directed or to be furnished or made at the respective addresses, as follows:
If to Assignor:
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, Texas 76102
Attention: Corporate Secretary
If to Assignee:
NationsBank, N.A.
17th Floor
901 Main Street
NationsBank Plaza
Dallas, Texas 75202
Attention: Trust Department
Either party or the successors or assignees of the interest or rights or obligations of either party hereunder may change its address or designate a new or different address or addresses for the purposes hereof by a similar notice given or directed to all parties interested hereunder at the time.
SECTION 10.05. Binding Effect. This Conveyance shall bind and inure to the benefit of the successors and assigns of Assignor and Assignee.
SECTION 10.06. Governing Law. The validity, effect and construction of this Conveyance shall be governed by the laws of the State of Texas.
SECTION 10.07. Headings. Article and Section headings used in this Conveyance are for convenience only and shall not affect the construction of this Conveyance.
SECTION 10.08. Substitution of Warranty. This instrument is made with full substitution and subrogation of Assignee in and to all covenants of warranty by others heretofore given or made with respect to the Subject Interests or any part thereof or interest therein.
SECTION 10.09. Counterpart Execution. This Conveyance may be executed in multiple counterparts, each of which shall be an original. Certain counterparts may have descriptions relating to different recording jurisdictions omitted from Schedule A. A counterpart with all such descriptions is being filed for record in Major County, Oklahoma. Where a description covers an interest located in more than one county, such description may be included in counterparts recorded in each county but such inclusion of the same description in more than one counterpart does not have any cumulative effect as to the interests covered by such description.
SECTION 10.10. Amended and Restated Conveyance. This Conveyance amends and restates fully a document previously executed by Assignor and Assignee. Such prior document was not recorded and is fully replaced and superseded by this Conveyance and such previously executed document is to be disregarded for all purposes.
IN WITNESS WHEREOF, each of the parties hereto has caused this Conveyance to be executed in its name and behalf and delivered as of the Effective Date.
ATTEST:
CROSS TIMBERS OIL COMPANY
----------------------------
Virginia Anderson, Secretary
of Cross Timbers Oil By:
Company ----------------------------
Vaughn O. Vennerberg, II
Senior Vice President - Land
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ATTEST:
NATIONSBANK, N.A., acting not in its
individual capacity but solely as the
Trustee of the Hugoton Royalty Trust
STATE OF TEXAS (S)
(S)
COUNTY OF TARRANT (S)
This instrument was acknowledged before me on this __th day of ________, 1999, by Vaughn O. Vennerberg II, Senior Vice President - Land of Cross Timbers Oil Company, on behalf of said corporation.
THE STATE OF TEXAS (S)
(S)
COUNTY OF DALLAS (S)
This instrument was acknowledged before me on this ___th day of __________, 1999, by Ron E. Hooper, Vice President of NationsBank, N.A., Trustee of the Hugoton Royalty Trust, on behalf of said Bank as Trustee of the Hugoton Royalty Trust.
SCHEDULE B
Attached to and made a part of that certain Net Overriding Royalty Conveyance
(Hugoton Royalty Trust) dated effective December 1, 1998 (the "Conveyance")
ACCOUNTING PROCEDURE
I. GENERAL PROVISIONS
1. Definitions
"Joint Property" shall mean the real and personal property subject to the Conveyance.
"Joint Operations" shall mean all operations necessary or proper for the development, operation, protection and maintenance of the Joint Property.
"Joint Account" shall mean the account showing the charges paid and credits received in the conduct of the Joint Operations and which are used in the calculation of Gross Proceeds, Net Proceeds, Processing Costs and Production Costs, as said terms are defined in the Conveyance.
"Operator" shall mean Cross Timbers Oil Company or any of its affiliates that conduct Joint Operations on the Joint Property.
"Parties" shall mean Operator and the Hugoton Royalty Trust (herein referred to as the "Trust").
"First Level Supervisors" shall mean those employees whose primary function in Joint Operations is the direct supervision of other employees and/or contract labor directly employed on the Joint Property in a field operating capacity.
"Technical Employees" shall mean those employees having special and specific engineering, geological or other professional skills, and whose primary function in Joint Operations is the handling of specific operating conditions and problems for the benefit of the Joint Property.
"Personal Expenses" shall mean travel and other reasonable reimbursable expenses of Operator's employees.
"Material" shall mean personal property, equipment or supplies acquired or held for use on the Joint Property.
"Controllable Material" shall mean Material which at the time is so classified in the Material Classification Manual as most recently recommended by the Council of Petroleum Accountants Societies.
2. Designation and Responsibilities of Operator
Cross Timbers Oil Company shall be the Operator of the Joint Property, and shall, to the extent it has the legal right to do so, conduct and direct and have full control of all operations on the Joint Property as permitted and required by, and within the limits of the Conveyance.
3. Payments and Accounting
Except as herein otherwise specifically provided, Operator shall promptly pay and discharge expenses incurred in the development and operation of the Joint Property and shall charge the Joint Account with the appropriate proportionate share upon the expense basis provided herein. Operator shall keep an accurate record of the expenses incurred and charges and credits made and received.
4. Application of Agreement
This Accounting Procedure will apply to Joint Properties where Cross Timbers Oil Company is the Operator and the Operator owns all or a portion of the leasehold interest in the Joint Properties. In the event there is an existing Accounting Procedure or related instrument governing the operations of the Joint Properties, this
Accounting Procedure will control except as to the overhead rate stated in the existing Accounting Procedure or related instrument.
5. Conflicts
In the event there exists any conflict between the terms of this Accounting Procedure or any Accounting Procedure that applies to the Joint Properties and the Conveyance to which it is attached, the Conveyance will control.
II. DIRECT CHARGES
Operator shall charge the Joint Account with the following items, which shall be allocated to Processing Costs or Production Costs as appropriate:
1. Ecological and Environmental
Costs incurred for the benefit of the Joint Property as a result of governmental or regulatory requirements to satisfy environmental considerations applicable to the Joint Operations. Such costs may include surveys of an ecological or archaeological nature and pollution control procedures as required by applicable laws and regulations, and costs related to employees of Operator performing any environmental work involving the Joint Property.
2. Rentals and Royalties
Lease rentals and royalties paid by Operator for the Joint Operations.
3. Labor
A. (1) Salaries and wages of Operator's field employees employed on the Joint Property in the conduct of Joint Operations.
(2) Salaries of First Level Supervisors in the field.
(3) Salaries and wages of Technical Employees directly employed on the Joint Property.
(4) Salaries and wages of Technical Employees either temporarily or permanently assigned to and directly employed in the operation of the Joint Property.
(5) Salaries and wages of support employees whose duties are primarily field related in connection with the Joint Operations, regardless of their location (e.g., field superintendents and clerical employees located in the field).
B. Operator's cost of holiday, vacation, sickness and disability benefits
and other customary allowances paid to employees whose salaries and
wages are chargeable to the Joint Account under Paragraph 3A of this
Section II. Such costs under this Paragraph 3B may be charged on a
"when and as paid basis" or by "percentage assessment" on the amount
of salaries and wages chargeable to the Joint Account under Paragraph
3A of this Section II. If percentage assessment is used, the rate
shall be based on the Operator's cost experience.
C. Expenditures or contributions made pursuant to assessments imposed by
governmental authority which are applicable to Operator's costs
chargeable to the Joint Account under Paragraphs 3A and 3B of this
Section II.
D. Personal Expenses of those employees whose salaries and wages are chargeable to the Joint Account under Paragraph 3A of this Section II.
4. Employee Benefits
Operator's current costs of established plans for employees' group life insurance, hospitalization, pension, retirement, stock purchase, thrift, bonus, and other benefit plans of a like nature, applicable to Operator's labor cost chargeable to the Joint Account under Paragraph 3A and 3B of this Section II shall be Operator's actual cost not to exceed the percent most recently recommended by the Council of Petroleum Accountants Societies.
5. Material
Material purchased or furnished by Operator for use on the Joint Property as provided under Section IV. Only such Material shall be purchased for or transferred to the Joint Property as may be required for immediate use and is reasonably practical and consistent with efficient and economical operations. The accumulation of surplus stocks shall be avoided.
6. Transportation
Transportation of employees and Material necessary for the Joint Operations but subject to the following limitations:
A. If Material is moved to the Joint Property from the Operator's warehouse or other properties, no charge shall be made to the Joint Account for a distance greater than the distance from the nearest reliable supply store where like material is normally available or railway receiving point nearest the Joint Property.
B. If surplus Material is moved to Operator's warehouse or other storage point, no charge shall be made to the Joint Account for a distance greater than the distance to the nearest reliable supply store where like material is normally available, or railway receiving point nearest the Joint Property. No charge shall be made to the Joint Account for moving Material to other properties belonging to Operator.
C. In the application of subparagraphs A and B above, the option to equalize or charge actual trucking cost is available when the actual charge is $400 or less excluding accessorial charges. The $400 will be adjusted to the amount most recently recommended by the Council of Petroleum Accountants Societies.
7. Services
The cost of contract services, equipment and utilities provided by outside sources, except services excluded by Paragraph 10 of Section II and Paragraph i, ii, and iii, of Section III. The cost of professional consultant services and contract services of technical personnel directly engaged on the Joint Property if such charges are excluded from the overhead rates.
8. Equipment and Facilities Furnished By Operator
A. Operator shall charge the Joint Account for use of equipment and facilities owned by Operator or any of its affiliates at rates commensurate with costs of ownership and operation. Such rates shall include costs of maintenance, repairs, other operating expense, insurance, taxes, depreciation, and interest on gross investment less accumulated depreciation not to exceed twelve percent (12%) per annum. Such rates shall not exceed average commercial rates currently prevailing in the immediate area of the Joint Property.
B. In lieu of charges in paragraph 8A above, Operator may elect to use average commercial rates prevailing in the immediate area of the Joint Property less 20%. For automotive equipment, Operator may elect to use rates published by the Petroleum Motor Transport Association.
C. This Paragraph 8 shall not affect any current charges made by Operator to the Joint Account related to transportation, gathering, treating, compression or processing or related charges by an affiliate of Operator.
9. Damages and Losses to Joint Property
All costs or expenses necessary for the repair or replacement of Joint Property made necessary because of damages or losses incurred by fire, flood, storm, theft, accident, or other cause, except those resulting from Operator's gross negligence or willful misconduct.
10. Legal Expense
Expense of handling, investigating and settling litigation or claims, discharging of liens, payment of judgments and amounts paid for settlement of claims incurred in or resulting from operations under the Conveyance or necessary to protect or recover the Joint Property, and the costs and expenses incurred in connection with hearings and other matters before governmental bodies and agencies and costs and expenses incurred in curing title to the Joint Property. Costs incurred by Operator in procuring abstracts and fees paid outside attorneys for title examination (including preliminary, supplemental, shut-in gas royalty opinions and division order title opinions) shall be borne by the Joint Account. Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of the above functions. All other legal expense is considered to be covered by the overhead provisions of Section III.
11. Taxes
All taxes of every kind and nature assessed or levied upon or in connection with the Joint Property, the operation thereof, or the production therefrom, and which taxes have been paid by the Operator for the benefit of the Parties. If the ad valorem taxes are based in whole or in part upon separate valuations of each party's interest, then notwithstanding anything to the contrary herein, charges to the Joint Account shall be made and paid by the Parties hereto in accordance with the tax value generated by each party's interest.
12. Insurance
Net premiums paid for insurance required to be carried for the Joint Operations for the protection of the Parties. In the event Joint Operations are conducted in a state in which Operator may act as self- insurer for Worker's Compensation and/or Employers Liability under the respective state's laws, Operator may, at its election, include the risk under its self-insurance program and in that event, Operator shall include a charge at Operator's cost not to exceed manual rates.
13. Abandonment and Reclamation
Costs incurred for abandonment of the Joint Property, including costs required by governmental or other regulatory authority.
14. Communications
Cost of acquiring, leasing, installing, operating, repairing and maintaining communication systems, including radio and microwave facilities or any form of telephonic equipment or service used in serving the Joint Property. In the event communication facilities/systems serving the Joint Property are Operator owned, charges to the Joint Account shall be made as provided in Paragraph 8 of this Section II.
15. Other Expenditures
Any other expenditure not covered or dealt with in the foregoing provisions of this Section II, or in Section III and which is of direct benefit to the Joint Property and is incurred by the Operator in the necessary and proper conduct of the Joint Operations.
III. OVERHEAD
1. Overhead - Drilling and Producing Operations
i. As compensation for administrative, supervision, office services and warehousing costs, Operator shall charge drilling and producing operations on a Fixed Rate Basis, Paragraph 1A. Such charge shall be in lieu of costs and expenses of all offices and salaries or wages plus applicable burdens and expenses of all personnel, except those directly chargeable under Paragraph 3A, Section II. The cost and expense of services from outside sources in connection with matters of taxation, traffic, accounting or matters before or involving governmental agencies shall not be considered as included in the overhead rates.
ii. The salaries, wages and Personal Expenses of Technical Employees and/or the cost of professional consultant services and contract services of technical personnel directly employed on the Joint Property shall not be covered by the overhead rates.
iii. The salaries, wages and Personal Expenses of Technical Employees and/or costs of professional consultant services and contract services of technical personnel either temporarily or permanently assigned to and directly employed in the operation of the Joint Property shall not be covered by the overhead rates.
A. Overhead - Fixed Rate Basis
(1) Operator shall charge the Joint Account at the following rates per well per month:
For wells located in the Hugoton Field Drilling Well Rate $2,350.00
(Prorated for less than a full month)
Producing Well Rate $235.00
For wells located in all other areas
Drilling Well Rate $4,760.00
(Prorated for less than a full month)
Producing Well Rate $476.00
(2) Application of Overhead - Fixed Rate Basis shall be as follows:
(a) Drilling Well Rate
(1) Charges for drilling wells shall begin on the date the well is spudded and terminate on the date the drilling rig, completion rig, or other units used in completion of the well is released, whichever is later, except that no charge shall be made during suspension of drilling or completion operations for fifteen (15) or more consecutive calendar days.
(2) Charges for wells undergoing any type of workover or recompletion or swabbing shall be made at the drilling well rate. Such charges shall be
applied for the period from date such operations, with rig or other units used, commence through date of rig or other unit release, except that no charge shall be made during suspension of operations for fifteen (15) or more consecutive calendar days.
(b) Producing Well Rates
(1) An active well either produced or injected into for any portion of the month shall be considered as a one-well charge for the entire month.
(2) Each active completion in a multi-completed well in which production is not commingled down hole shall be considered as a one-well charge providing each completion is considered a separate well by the governing regulatory authority.
(3) An inactive gas well shut in because of overproduction or failure of purchaser to take the production shall be considered as a one-well charge providing the gas well is directly connected to a permanent sales outlet.
(4) A one-well charge shall be made for the month in which plugging and abandonment operations are completed on any well. This one-well charge shall be made whether or not the well has produced except when drilling well rate applies.
(5) All other inactive wells (including but not limited to inactive wells covered by unit allowable, lease allowable, transferred allowable, etc.) shall not qualify for an overhead charge.
(3) The well rates shall be adjusted as of the first day of April each year beginning in 1999. The adjustment shall be computed by multiplying the rate currently in use 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 rates shall be the rates currently in use, plus or minus the computed adjustment.
2. Overhead - Major Construction
To compensate Operator for overhead costs incurred in the construction and installation of fixed assets, the expansion of fixed assets, and any other project clearly discernable as a fixed asset required for the development and operation of the Joint Property, Operator shall charge the Joint Account for overhead based on the following rates for any Major Construction project in excess of $25,000.00:
A. 5% of first $100,000 or total cost if less, plus
B. 3% of costs in excess of $100,000 but less than $1,000,000, plus
C. 2% of costs in excess of $1,000,000.
Total cost shall mean the gross cost of any one project. For the purpose of this paragraph, the component parts of a single project shall not be treated separately and the cost of drilling and workover wells and artificial lift equipment shall be excluded.
3. Catastrophe Overhead
To compensate Operator for overhead costs incurred in the event of expenditures resulting from a single occurrence due to oil spill, blowout, explosion, fire, storm, hurricane, or other catastrophes as agreed to by the Parties, which are necessary to restore the Joint Property to the equivalent condition that existed prior to the event causing the expenditures, Operator shall charge the Joint Account for overhead based on the following rates:
A. 5% of total costs through $100,000; plus
B. 3% of total costs in excess of $100,000 but less than $1,000,000; plus
C. 2% of total costs in excess of $1,000,000.
Expenditures subject to the overheads in this Section 3 above will not be
reduced by insurance recoveries, and no other overhead provisions of this
Section III shall apply.
IV. PRICING OF JOINT ACCOUNT MATERIAL PURCHASES, TRANSFERS AND DISPOSITIONS
Operator is responsible for Joint Account Materials and shall make proper and timely charges and credits for all Material movements affecting the Joint Property. Operator shall provide all Material for use on the Joint Property. Operator shall make timely disposition of idle and/or surplus Material, such disposal being made either through sale to Operator, or sale to outsiders. Operator may purchase, but shall be under no obligation to purchase, interest of the Trust in surplus condition A or B Material at the prices defined below.
1. Purchases
Material purchased shall be charged at the price paid by Operator after deduction of all discounts, adjustments or rebates received. In case of Material found to be defective or returned to vendor for any other reasons, credit shall be passed to the Joint Account when adjustment has been received by the Operator.
2. Transfers and Dispositions
Material furnished to the Joint Property and Material transferred from the Joint Property or disposed of by the Operator shall be priced on the following basis exclusive of cash discounts:
A. New Material (Condition A)
(1) Tubular Goods Other than Line Pipe
(a) Tubular goods, sized 2-3/8 inches OD and larger, except line pipe, shall be priced at Eastern mill published carload prices effective as of date of movement plus transportation cost using the 80,000 pound carload weight basis to the railway receiving point nearest the Joint Property for which published rail rates for tubular good exist. If the 80,000 pound rail rate is not offered, the 70,000 pound or 90,000 pound rail rate may be used. Freight charges for tubing will be calculated from Lorain, Ohio and casing from Youngstown, Ohio.
(b) For grades which are special to one mill only, prices shall be computed at the mill base of that mill plus transportation cost from that mill to the railway receiving point nearest the Joint Property as provided above in Paragraph 2.a.(1)(a). For transportation cost from points other than Eastern mills, the 30,000 pound Oil Field Haulers Association interstate truck rate shall be used.
(c) Special end finish tubular goods shall be priced at the lowest published out-of-stock price, f.o.b. Houston, Texas, plus transportation cost, using Oil Field Haulers Association interstate 30,000 pound truck rate, to the railway receiving point nearest the Joint Property.
(d) Macaroni tubing (size less than 2-3/8 inch OD) shall be priced at the lowest published out-of-stock prices f.o.b. the supplier plus transportation costs, using the Oil Field Haulers Association interstate truck rate per weight of tubing transferred, to the railway receiving point nearest the Joint Property.
(2) Line Pipe
(a) Line pipe movements (except size 24 inch OD and larger with walls 3/4 inch and over) 30,000 pounds or more shall be priced under provisions of tubular goods pricing in Paragraph A.(1)(a) as provided above. Freight charges shall be calculated from Lorain, Ohio.
(b) Line pipe movements (except size 24 inch OD and larger with
walls 3/4 inch and over) less than 30,000 pounds shall be
priced at Eastern mill published carload base prices
effective as of date of shipment, plus 20 percent, plus
transportation costs based on freight rates as set forth
under provisions of tubular goods pricing in Paragraph
A.(1)(a) as provided above. Freight charges shall be
calculated from Lorain, Ohio.
(c) Line pipe 24 inch OD and over and 3/4 inch wall and larger shall be priced f.o.b. the point of manufacture at current new published prices plus transportation cost to the railway receiving point nearest the Joint Property.
(d) Line pipe, including fabricated line pipe, drive pipe and conduit not listed on published price lists shall be priced at quoted prices plus freight to the railway receiving point nearest the Joint Property or at prices agreed to by the Parties.
(3) Other Material shall be priced at the current new price, in effect at date of movement, as listed by a reliable supply store nearest the Joint Property, or point of manufacture, plus transportation costs, if applicable, to the railway receiving point nearest the Joint Property.
(4) Unused new Material, except tubular goods, moved from the Joint Property shall be priced at the current new price, in effect on date of movement, as listed by a reliable supply store nearest the Joint Property, or point of manufacture, plus transportation costs, if applicable, to the railway receiving point nearest the Joint Property. Unused new tubulars will be priced as provided above in Paragraph 2 A (1) and (2).
B. Good Used Material (Condition B)
Material in sound and serviceable condition and suitable for reuse without reconditioning:
(1) Material moved to the Joint Property
At seventy-five percent (75%) of current new price, as determined by Paragraph A.
(2) Material used on and moved from the Joint Property
(a) At seventy-five percent (75%) of current new price, as determined by Paragraph A, if Material was originally charged to the Joint Account as new Material.
(b) At sixty-five percent (65%) of current new price, as determined by Paragraph A, if Material was originally charged to the Joint Account as used Material.
(3) Material not used on and moved from the Joint Property
At seventy-five percent (75%) of current new price as determined by Paragraph A.
The cost of reconditioning, if any, shall be absorbed by the transferring property.
C. Other Used Material
(1) Condition C
Material which is not in sound and serviceable condition and suitable for its original function until after reconditioning shall be priced at fifty percent (50%) of current new price as determined by Paragraph A. The cost of reconditioning shall be charged to the receiving property, provided Condition C value plus cost of reconditioning does not exceed Condition B value.
(2) Condition D
Material, excluding junk, no longer suitable for its original purpose, but usable for some other purpose shall be priced on a basis commensurate with its use. Operator may dispose of Condition D Material under procedures normally used by Operator without prior approval of the Assignee.
(a) Casing, tubing or drill pipe used as line pipe shall be priced as Grade A and B seamless line pipe of comparable size and weight. Used casing, tubing or drill pipe utilized as line pipe shall be priced at used line pipe prices.
(b) Casing, tubing or drill pipe used as higher pressure service lines than standard line pipe, e.g. power oil lines, shall be priced under normal pricing procedures for casing, tubing, or drill pipe. Upset tubular goods shall be priced on a non upset basis.
(3) Condition E
Junk shall be priced at prevailing prices. Operator may dispose of Condition E Material under procedures normally utilized by Operator without prior approval of Non-Operators.
D. Obsolete Material
Material which is serviceable and usable for its original function but condition and/or value of such Material is not equivalent to that which would justify a price as provided above may be specially priced as reasonably determined by Operator. Such price should result in the Joint Account being charged with the value of the service rendered by such Material.
E. Pricing Conditions
(1) Loading and unloading costs related to the movement of the Material to the Joint Property shall be charged in accordance with the methods specified in COPAS Bulletin 21.
(2) Material involving erection costs shall be charged at applicable percentage of the current knocked-down price of new Material.
3. Premium Prices
Whenever Material is not readily obtainable at published or listed prices because of national emergencies, strikes or other unusual causes over which the Operator has no control, the Operator may charge the Joint Account for the required Material at the Operator's actual cost incurred in providing such Material, in making it suitable for use, and in moving it to the Joint Property.
4. Warranty of Material Furnished by Operator
Operator does not warrant the Material furnished. In case of defective Material, credit shall not be passed to the Joint Account until adjustment has been received by Operator from the manufacturers or their agents.
V. INVENTORIES
The Operator shall maintain detailed records of Controllable Material.
1. Periodic Inventories, Notice and Representation
At reasonable intervals, inventories shall be taken by Operator of the Joint Account Controllable Material.
2. Reconciliation and Adjustment of Inventories
Adjustments to the Joint Account resulting from the reconciliation of a physical inventory shall be made within six months following the taking of the inventory. Inventory adjustments shall be made by Operator to the Joint Account for overages and shortages, but Operator shall be held accountable only for shortages due to lack of reasonable diligence.
3. Special Inventories
Special inventories may be taken whenever there is any sale, change of interest, or change of Operator in the Joint Property. It shall be the duty of the party selling to notify all other Parties as quickly as possible after the transfer of interest takes place. In such cases, both the seller and the purchaser shall be governed by such inventory. In cases involving a change of Operator, all Parties shall be governed by such inventory.
4. Expense of Conducting Inventories
A. The expense of conducting periodic inventories shall not be charged to the Joint Account.
B. The expense of conducting special inventories shall be charged to the Parties requesting such inventories, except inventories required due to change of Operator shall be charged to the Joint Account.
EXHIBIT 10.3.1
NET OVERRIDING ROYALTY CONVEYANCE
Hugoton Royalty Trust
STATE OF WYOMING (S)
(S) KNOW ALL MEN BY THESE PRESENTS:
COUNTIES OF LINCOLN, (S)
SUBLETTE AND SWEETWATER (S)
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THAT CROSS TIMBERS OIL COMPANY, a corporation formed under the laws of the State of Delaware ("Assignor"), for and in consideration of the sum of Ten Dollars ($10.00) and other good and valuable consideration to Assignor paid by NATIONSBANK, N.A., a bank organized under the laws of the United States, acting not in its individual corporate capacity but solely as trustee under that certain Trust Indenture establishing the Hugoton Royalty Trust dated as of December 1, 1998 ("Assignee"), the receipt and sufficiency of which are hereby acknowledged, has bargained, sold, granted, conveyed, transferred, assigned, set over and delivered, and by these presents does bargain, sell, grant, convey, transfer, assign, set over and deliver unto Assignee a net overriding royalty interest ("the Royalty Interest") in and to the Subject Hydrocarbons in and under, and if, as and when produced, saved and sold from, the Subject Lands during the term of the Subject Interests on and after the Effective Date equal to eighty percent (80%) of the Net Proceeds attributable to the Subject Interests, as each of the above capitalized words is defined in Article I hereof and all as more fully provided herein.
TO HAVE AND TO HOLD the Royalty Interest, together with all and singular the rights and appurtenances thereto in anywise belonging, unto Assignee, its successors and assigns, subject, however, to the terms and provisions of this Conveyance; and Assignor does by these presents bind and obligate itself, its successors and assigns, to WARRANT and FOREVER defend all and singular the Royalty Interest unto the said Assignee, its successors and assigns, against every person whomsoever lawfully claiming or to claim the same or any part thereof by, through or under Assignor, but not otherwise.
ARTICLE I
DEFINITIONS
As used herein, the following words, terms or phrases have the following meanings:
SECTION 1.01. "Affiliate" means, as to the party specified, any Person controlling, controlled by or under common control with such party, with the concept of control in such context meaning the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of another, whether through the ownership of voting securities, by contract or otherwise. The Trust shall not be deemed an Affiliate of Assignor.
SECTION 1.02. "Assignor" means the Assignor named herein while Assignor owns all or any part of or interest in the Subject Interests and any other Person or Persons (excluding Assignee) who hereafter may acquire all or any part of or interest in the Subject Interests.
SECTION 1.03. "Assignee" means the Assignee named herein (and any successor Trustee under the Trust Indenture) while it owns all or any part of or interest in the Royalty Interest and any other Person or Persons who may acquire legal title to all or any part of or interest in the Royalty Interest.
SECTION 1.04. "Computation Period" means (i) initially, the period commencing on the Effective Date and ending on February 28, 1999, and (ii) each calendar month thereafter.
SECTION 1.05. "Conveyance" means this Net Overriding Royalty Conveyance.
SECTION 1.06. "Effective Date" means 7:00 o'clock A.M., local time in effect at the location of each Subject Interest, on December 1, 1998.
SECTION 1.07. "Excess Production Costs" means, for any Computation Period, an amount equal to the excess, if any, of Production Costs for such Computation Period over Gross Proceeds for such Computation Period.
SECTION 1.08. "Existing Sales Contracts" means all contracts and agreements in effect as of the Effective Date between or among Assignor and any Affiliate of Assignor, or between or among any Affiliates of Assignor, for the Sale, Processing, treatment, compression, gathering or transportation of Subject Hydrocarbons.
SECTION 1.09. "Gross Proceeds" means, for any Computation Period other than during the period from the Effective Date through January 31, 2000, and subject to Section 2.01 (i) during the term of the Existing Sales Contracts, the proceeds received by Assignor under the Existing Sales Contracts attributable to the Sale of Subject Hydrocarbons produced after the Effective Date and Sold during such Computation Period by Assignor after the Effective Date, and (ii) as to Subject Hydrocarbons produced after the Effective Date and Sold by Assignor during such Computation Period after the Effective Date other than under the Existing Sales Contracts (A) if Sold under a Sales Contract with a Non-Affiliate of Assignor, the proceeds received by Assignor under such Sales Contract, or (B) if Sold under a Sales Contract with an Affiliate of Assignor, the proceeds received by Assignor under such Sales Contract but in no event less than 98% of the proceeds received by such Affiliate upon the resale of such Subject Hydrocarbons to a Non-Affiliate of Assignor, and (iii) the proceeds received by Assignor in respect of underproduced gas imbalances attributable to the Subject Interests as of the Effective Date. "Gross Proceeds" means, for any Computation Period included in the period from the Effective Date through January 31, 2000, the sum of (i) for all Subject Hydrocarbons other than gas and natural gas liquids, if any, extracted from gas by Processing, the Gross Proceeds thereof, as defined above, and (ii) for that portion of the Subject Hydrocarbons that is gas and natural gas liquids, if any, extracted from gas by Processing, the greater of (A) an imputed amount computed as if all gas for which proceeds are received attributed to the Subject Interests during the period relevant to such Computation Period was sold for a price of $2.00 per thousand cubic feet at the wellhead, and (B) the Gross Proceeds of the Sale thereof computed
on the basis provided for Computation Periods other than during the period from the Effective Date through January 31, 2000; provided, however, that such computation under clause (B) above of this sentence shall be modified as needed to yield the weighted average sales price of all (gas and natural gas liquids, if any, extracted from gas by Processing) Sold that is included within Subject Hydrocarbons under all conveyances from Assignor to the Trust, not limited to this Conveyance. For purposes hereof, the "weighted average sales price of all gas" shall be determined for any Computation Period by dividing (A) the Gross Proceeds of the Sale of gas and natural gas liquids, if any, extracted from gas by Processing for such Computation Period (determined as provided above for all Computation Periods other than during the period from the Effective Date through January 31, 2000) attributable to any Subject Interests in which the Trust has a Royalty Interest ( and including Royalty Interests conveyed to the trust by Assignor under conveyances other than this Conveyance) by (B) the volume of such gas (in thousand cubic feet) attributable to such Subject Interests for such Computation Period. In all instances, the definition of "Gross Proceeds" shall be subject to the following:
(a) There shall be excluded from Gross Proceeds all Property Taxes that are deducted or excluded from proceeds of Sale received by Assignor and, for purposes of the calculation of Gross Proceeds under clause (ii)(A) of the second sentence of this Section 1.09, there shall also be excluded the amount of any additional Property Taxes that would have been paid by Assignor or withheld from Assignor if the imputed Sale price set forth therein had been the actual Sale price.
(b) There shall be excluded any amount for Subject Hydrocarbons attributable to nonconsent operations conducted with respect to the Subject Interests (or any portion thereof) as to which Assignor shall be a nonconsenting party and which is dedicated to the recoupment or reimbursement of costs and expenses of the consenting party or parties by the terms of the relevant operating agreement, unit agreement, contract for development or other instrument providing for such nonconsent operations. Assignor agrees that its election not to participate in such operations shall be made in conformity with the provisions of Section 6.01 of this Conveyance, but third persons shall not be under any duty to determine that such election so conformed.
(c) There shall be excluded any amount which Assignor shall receive as any of the following: consideration for transfer or sale of any of the Subject Interests (subject to the Royalty Interest) or equipment or other personal property or fixtures on the Subject Lands; payments for gas not taken, when such payments are made (but to the extent such payments are allocated to gas taken in the future such payments shall be included without interest in Gross Proceeds when such gas is taken); damages arising from any cause other than drainage or reservoir injury; rental for reservoir use; payments made to Assignor in connection with the drilling of any well on any of the Subject Lands or lands in the vicinity thereof (such exclusion including dry and bottom hole payments, provided that if such well is drilled on the Subject Lands and Assignor incurs Production Costs in connection therewith such payments shall reduce Production Costs) or in connection with any adjustment of any well and leasehold equipment upon unitization of any of the Subject Interests; provided there shall be included in Gross Proceeds advance or prepaid payments for future production received by Assignor to the extent not subject to repayment in the event of insufficient subsequent
production (and to the extent so subject to repayment shall be included without interest in Gross Proceeds when the Subject Hydrocarbons on which such payment was so advanced or prepaid are actually produced) and payments made to Assignor in connection with the deferring of drilling of any well on any of the Subject Lands (including payments from an operator in the vicinity for refraining from drilling an offset well).
(d) There shall be excluded any amount for Subject Hydrocarbons lost in the production or marketing thereof or used by Assignor in conformity with ordinary or prudent practices for drilling, production and plant operations (including gas injection, secondary recovery, pressure maintenance, repressuring, cycling operations, plant fuel or shrinkage) conducted for the purpose of drilling for, producing or Processing Subject Hydrocarbons or for operations on any unit or plant to which the Subject Interests are committed, but only so long as such Subject Hydrocarbons are so used.
(e) Amounts received as a loan by Assignor from a purchaser of Subject Hydrocarbons, whether with or without interest, shall not be considered to be derived from the sale of Subject Hydrocarbons.
(f) If a controversy or possible controversy exists (whether by reason of any statute, order, decree, rule, regulation, contract or otherwise) between Assignor and any purchaser as to the correct sales price of any Subject Hydrocarbons or, for any other reason, as to Assignor's right to receive or collect the proceeds of sale of any Subject Hydrocarbons, then
(i) amounts withheld by the purchaser or deposited by it with an escrow agent shall not be considered to be received by Assignor until actually collected by Assignor, but the amounts received by Assignor shall include any interest, penalty or other amount paid to Assignor in respect thereof;
(ii) amounts received by Assignor and promptly deposited by it with an escrow agent shall not be considered to have been received by Assignor, but all amounts thereafter paid to Assignor by such escrow agent shall be considered to be amounts received from the Sale of Subject Hydrocarbons; and
(iii) amounts received by Assignor and not deposited with an
escrow agent shall be considered to be received for purposes of this
Section 1.09.
SECTION 1.10. "Hydrocarbons" means oil, gas (which term includes coal bed gas, coal seam gas and methane) and all other minerals produced in association with oil or gas (including, but not limited to, helium, sulphur and carbon dioxide), but excluding all other minerals, whether similar or dissimilar.
SECTION 1.11. "Monthly Record Date" for each month means the close of business on the last day of such month which 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, unless Assignee determines that a different date is required to comply with applicable law or the rules of
a securities exchange or quotation system pursuant to the terms of the Trust Indenture, in which event it means such different date.
SECTION 1.12. "Net Proceeds" means, for any Computation Period, the excess of Gross Proceeds for such Computation Period over Production Costs for such Computation Period.
SECTION 1.13. "Non-Affiliate" means, as to the party specified, any Person who is not an Affiliate of such party.
SECTION 1.14. "Person" means any individual, corporation, partnership, limited liability company, trust, estate or other entity, organization or association.
SECTION 1.15. "Prime Interest Rate" means the variable rate of interest most recently announced by NationsBank, N.A. as its "prime rate."
SECTION 1.16. "Process" or "Processing" means to extract or otherwise recover natural gas liquids from natural gas included in the Subject Hydrocarbons through the processes of absorption, condensation, adsorption, cryogenic or other methods in a manner that does not constitute Separation.
SECTION 1.17. "Processing Costs" means the costs to Assignor or any Affiliate of Assignor to Process Subject Hydrocarbons before the Sale thereof, which costs for purposes hereof shall consist of the sum of (a) any such Processing charges paid to Non-Affiliates, (b) the charges by Affiliates of Assignor under Existing Sales Contracts, and (c) the charges by Affiliates of Assignor other than under Existing Sales Contracts so long as such charges do not materially exceed charges prevailing in the area for similar services at the time of contracting for such charges.
If Assignor (or its Affiliates) receives a share of the production of others or of plant products therefrom (or proceeds of sale thereof) for Processing such production of others, such share shall not be included in Subject Hydrocarbons (or Gross Proceeds). If Assignor (or its Affiliates) does not bear any Processing Costs but the owners or operators of a plant receive a share of the Subject Hydrocarbons (or proceeds of sale thereof) for Processing them, such share (or proceeds) shall be excluded from the Subject Hydrocarbons (and Gross Proceeds).
SECTION 1.18. "Production Costs" means, for any Computation Period, to the extent not excluded for purposes of calculating Gross Proceeds, whether capital or non-capital in nature,
(a) the sum of
(i) all amounts paid by Assignor or any Affiliate of Assignor as any of the following: royalty, overriding royalty or other presently existing burden against production or the proceeds of Sale of production attributable to the Subject Interests; delay rental; shut-in gas well royalty or payment; minimum royalty; payments to lessors or others in the area in connection with the drilling or deferring of drilling of any well on any of the Subject Lands or lands in the vicinity thereof (including dry and bottom hole payments and payments made to others for refraining from drilling
an offset well) or in connection with any adjustment of any well and leasehold equipment upon unitization of any of the Subject Interests; and rent and other consideration paid for use of or damage to the surface;
(ii) the Property Tax Accrual;
(iii) the overhead costs paid by Assignor or any Affiliate of Assignor under any joint operating agreement applicable to any of the Subject Interests to which Assignor and one or more Non-Affiliates of Assignor are parties and where Assignor or any Affiliate of Assignor is not the operator of such Subject Interest;
(iv) the overhead rate provided for in any joint operating agreement applicable to any of the Subject Interests where Assignor or any Affiliate of Assignor is the operator of such Subject Interests, less the portion, if any, of the overhead rate due from Non-Affiliates of Assignor;
(v) with respect to any Subject Interests operated by Assignor or any of its Affiliates and not subject to a joint operating agreement, an overhead fee as shown on Schedule B attached hereto and subject to adjustment as provided in Schedule B attached hereto;
(vi) all other costs, expenses and liabilities (including Processing Costs) paid or incurred by Assignor or any Affiliate of Assignor for investigating, exploring, prospecting, drilling and mining for, operating and producing Subject Hydrocarbons and sale and marketing thereof, including without implied limitation: costs for equipping, plugging back, reworking, completing, recompleting and plugging and abandoning of any well on the Subject Lands and of making the Subject Hydrocarbons ready or available for market; costs for construction and operation of gathering lines, tanks, transmission lines, meters and other production and delivery facilities; costs, whether paid in cash or by a share of Subject Hydrocarbons, of transporting, compressing, dehydrating, separating, treating, storing and marketing the Subject Hydrocarbons and disposing of extraneous substances produced in association with Subject Hydrocarbons (provided that such costs, if paid to or incurred by an Affiliate of Assignor other than pursuant to an Existing Sales Contract, shall not materially exceed charges prevailing in the area for similar services at the time of contracting for such charges); costs for secondary recovery, pressure maintenance, repressuring, cycling and other operations conducted for the purpose of enhancing production; costs or expenses (whether paid in cash or by delivery of gas) incurred in resolving overproduced gas imbalances attributable to the Subject Interests as of the Effective Date and thereafter; and costs for litigation concerning title to or operation of the Subject Interests and any other acts or omissions of Assignor consistent herewith or brought by Assignor to protect the Subject Interests; and costs for litigation or regulatory proceedings concerning title to or operation of the Subject Interests and any other acts or omissions of Assignor consistent herewith or brought by Assignor to protect the Subject Interests or to
protect or enforce any rights, contractual or otherwise, of Assignor to produce or market Subject Hydrocarbons therefrom;
(vii) Excess Production Costs for the preceding Computation Period (including any remaining Excess Production Costs carried forward from any preceding Computation Period);
(viii) interest on the amount of Excess Production Costs at the beginning of any Computation Period, calculated from the first day to the last day of the Computation Period, at the Prime Interest Rate in effect at the beginning of such Computation Period;
(ix) any amounts paid by Assignor or any Affiliate of Assignor whether as refund, interest or penalty, to a purchaser or any governmental agency or other Person because the amount initially received by Assignor (or Affiliate of Assignor) as sales price for Sales after the Effective Date was more or allegedly more than permitted by the terms of any applicable contract, statute, regulation, order, decree or other obligation; provided such amounts (in the case of a refund), or the amounts with respect to which the interest or penalty was paid, were previously included in Gross Proceeds;
(x) any other amounts paid by Assignor or any Affiliate of Assignor with respect to ownership or operation of the Subject Interests after the Effective Date or Sales of production therefrom after the Effective Date, whether as refund, fine, interest or penalty, pursuant to litigation or settlement of threatened litigation or order of governmental agency, provided that Assignor has not breached Section 6.01 hereof;
(xi) all consideration hereafter paid and costs and expenses hereafter incurred by Assignor or any Affiliate of Assignor for any renewals or extensions of leases or other rights acquired after the Effective Date which are included in the definition herein of Subject Interests; and
(xii) any accrual or reserve which Assignor or any Affiliate of Assignor shall have the right, at its election, to charge to Production Costs for operations (other than day-to-day operations) budgeted under an operating agreement or approved under an authorization for expenditures ("AFE"), which accrual or reserve may be based on the reasonably expected time of performing such operation or on an estimated percentage of completion of the operation or on any other reasonable method, and which accrual is in lieu of charging the cost of such operation when paid for by Assignor (or Affiliate of Assignor) but which shall be adjusted if and to the extent actual costs differ from such accrual or reserve;
(b) but excluding
(i) costs which would otherwise be treated as Production Costs (but which shall not be so treated for purposes hereof until the following amounts have been fully credited against such costs) equal to amounts reimbursed or credited to Assignor by insurance from damage to property, by sales of property or transfers of property off the leases included in the Subject Interests or by proceeds from unitization or other disposition of property; and
(ii) except for resolution of gas imbalances which are included in Section 1.18(a)(vi) above, any amounts which would otherwise be Production Costs but which are attributable to periods before the Effective Date; and
(iii) costs that otherwise would be treated as Production Costs but which have already been excluded or deducted from Gross Proceeds under Section 1.09; and
(iv) costs incurred by any Affiliate of Assignor for which such Affiliate has received a fee, reimbursement or other payment from Assignor, where such payment by Assignor constitutes a Production Cost.
SECTION 1.19. "Property Taxes" means the sum of all general property (ad valorem), production, severance, sales, gathering and excise taxes and other taxes (whether state, federal or otherwise), except income taxes, assessed or levied on or in connection with the Subject Interests, the Royalty Interest or the production therefrom or equipment on the Subject Lands, or against Assignor as owner of the Subject Interests or Assignee as owner of the Royalty Interest.
SECTION 1.20. "Property Tax Accrual" means, for any Computation Period, an amount that may be set aside by Assignor as an accrual to be applied against Property Taxes other than those that are deducted or excluded from Gross Proceeds pursuant to Section 1.09(a) above, which accruals shall be adjusted to the extent actual Property Taxes differ.
SECTION 1.21. "Sale" and "Sold" mean all forms of dispositions of Subject Hydrocarbons for value, including exchanges and other dispositions for value.
SECTION 1.22. "Sales Contracts" means all contracts and agreements for the sale of Subject Hydrocarbons.
SECTION 1.23. "Separation" means liquid separation operations in the vicinity of the well using a conventional mechanical liquid gas separator but excluding operations involving heat exchange, adiabatic cooling, absorption, adsorption or refrigeration principles.
SECTION 1.24. "Subject Hydrocarbons" means all Hydrocarbons in and under, and which may be produced, saved and sold from, and which shall accrue and be attributable to, the Subject Interests on and after the Effective Date, including plant products attributable thereto from Processing gas or casinghead gas included in the Subject Hydrocarbons before sale thereof (but not including products derived from processing oil).
SECTION 1.25. "Subject Interests" means, subject to the exclusions stated below, each kind and character of right, title, claim or interest which Assignor has on the Effective Date in or under each oil, gas or mineral lease, unitization or pooling agreement (and the units created thereby), royalty interests, overriding royalty interests, fee mineral interests and net profits interests and any other agreements, conveyances, assignments or instruments which are described or referred to in Schedule A, and all the right, title, claim or interest which Assignor has on the Effective Date in and to the Subject Lands, whether such right, title, claim or interest be under and by virtue of a lease, a unitization or pooling agreement or order, an operating agreement, a division order, a transfer order or any other type of agreement, conveyance, assignment or instrument or under any other type of claim or title, legal or equitable, recorded or unrecorded, even though Assignor's interests be incorrectly or incompletely described in, or a description thereof be omitted from, Schedule A, all as the same shall be enlarged by the discharge of any payments out of production or by the removal of any charges or encumbrances to which any of the same are subject and any and all renewals and extensions of any of the same, but subject to all burdens to which Assignor's such right, title, claim or interest is subject (while same remains so subject), limited, however, if Assignor's interest in any Subject Interest should terminate at any time, to the period to which Assignor's interest in such Subject Interest is limited. There shall be excluded from the term "Subject Interests" any interest hereafter acquired by Assignor in and to any of the Subject Lands, except any interest acquired pursuant to existing agreements for no new consideration and renewals or extensions of existing leases and other such agreements. For purposes of this Conveyance "renewals or extensions" of any lease or other such agreement shall be limited to renewals or extensions of an existing lease or other such agreement obtained by the present owner thereof (or such owner's successors in interest) while such lease is in force or within six months after such lease or other such agreement terminates. Assignor shall be under no duty to seek renewals or extensions of any lease or other such agreement.
SECTION 1.26. "Subject Lands" means the lands which are described in and which are subject to the oil, gas or mineral leases, unitization or pooling agreements or orders, operating agreements, division orders, transfer orders or other type of agreement, conveyance, assignment or instrument described in Schedule A attached hereto, provided that, where the description in Schedule A excepts land or refers to an instrument insofar only as it covers certain land or certain depths in certain land, no interest in such excepted land or depths or in land other that to which such reference is limited shall be included in the terms "Subject Lands" or "Subject Interests".
SECTION 1.27. "Trust" means the Hugoton Royalty Trust established by the Trust Indenture.
SECTION 1.28. "Trust Indenture" means the Royalty Trust Indenture by and between Cross Timbers Oil Company and NationsBank, N.A. dated as of December 1, 1998, establishing the Hugoton Royalty Trust, an express Texas Trust under the Texas Trust Code.
ARTICLE II
MARKETING OF SUBJECT HYDROCARBONS
SECTION 2.01. Sales Contracts. Assignor, to the extent it has the right to do so, shall market or cause to be marketed the Subject Hydrocarbons and Assignee shall have no authority to
market the Subject Hydrocarbons or to take in-kind any Subject Hydrocarbons. For such purpose, Sales of Subject Hydrocarbons may continue to be made pursuant to Existing Sales Contracts. Assignor may amend such Existing Sales Contracts and may enter into one or more Sales Contracts in the future at the prices and on the terms Assignor shall deem proper in Assignor's sole and absolute discretion, which may include sales to Affiliates of Assignor. Further, Assignor may commit any of the Subject Interests (including the Royalty Interest attributable thereto) to one or more agreements for Processing pursuant to which, by way of example and not by way of limitation, the plant owner or operator (which may be an Affiliate of Assignor) receives a portion of the Subject Hydrocarbons or plant products derived therefrom or proceeds of the Sale thereof as a fee for Processing. Except as provided otherwise in Section 1.09 for the period from the Effective date through January 31, 2000, Gross Proceeds of Subject Hydrocarbons shall be determined on the basis of amounts actually received by Assignor (and not, except as provided in Section 1.09, proceeds received by any of Assignor's Affiliates) from Sales under Sales Contracts regardless of whether at the time of production or Sale market value should be different from proceeds of Sale. In no event shall Gross Proceeds or Production Costs include any revenues, expenses, gains or losses resulting from option transactions or other futures or hedging transactions (other than forward Sales of the Subject Hydrocarbons) which, if engaged in by Assignor or any of its Affiliates in respect of Subject Hydrocarbons, shall be solely for the account of Assignor or such Affiliate.
SECTION 2.02. Delivery of Subject Hydrocarbons. All Subject Hydrocarbons Sold by Assignor, whether pursuant to Sales Contracts or otherwise, shall be delivered, by Assignor to the purchasers thereof, into the pipelines to which the wells producing such Subject Hydrocarbons may be connected or to such other point of purchase as is reasonably required in the marketing of such Subject Hydrocarbons.
SECTION 2.03. Reliance by Third Party. As to any party, the acts of Assignor shall be binding on Assignee. It shall not be necessary for Assignee to join with Assignor in any division or transfer order, lease extension or Sales Contract, and proceeds of Sale of the Subject Hydrocarbons shall be paid by the purchasers thereof (or others disbursing proceeds) directly to Assignor without necessity of joinder by or consent of Assignee.
ARTICLE III
PAYMENTS
SECTION 3.01. Payment. On or before each Monthly Record Date, beginning with the Monthly Record Date for March, 1999, Assignor shall pay to Assignee as an overriding royalty hereunder an amount equal to eighty percent (80%) of the Net Proceeds for the preceding Computation Period. All payments made to Assignee on account of the Royalty Interest shall be made entirely and exclusively out of sale proceeds attributable to the production of Hydrocarbons from, or attributed to, the Subject Interests after the Effective Time. Accordingly, the amount of any Net Proceeds in respect of a Computation Period which cannot be paid out of the sale proceeds of production of Hydrocarbons from, or attributed to, the Subject Interests shall be carried over and included in Net Proceeds in the next Computation Period; provided, however, such amount shall only be payable from the Hydrocarbons produced from or attributable to the Subject Interests and the sale proceeds thereof, if any.
SECTION 3.02. Interest on Past Due Payments. Except as otherwise provided in Section 9.05 hereof, any amount not paid by Assignor to Assignee when due shall bear, and Assignor will pay, interest determined at the end of each month, from such due date until such amount is paid, at the rate of the lesser of (a) the Prime Interest Rate plus 4% or (b) the maximum lawful contract rate of interest permitted by the applicable usury laws, now or hereafter enacted, which interest rate (the "Maximum Rate") shall change when and as said laws change, effective at the close of business on the day such change in said laws becomes effective; but, if there shall be no Maximum Rate, then the rate shall be as specified in the foregoing clause (a).
SECTION 3.03. Overpayment. If at any time Assignor pays Assignee more than the amount due, Assignee shall not be obligated to return any such overpayment, but the amount or amounts otherwise payable to Assignee for any subsequent period or periods shall be reduced by such overpayment, plus an amount equal to interest during the period of such overpayment at the rate of the lesser of (a) the Prime Interest Rate or (b) the Maximum Rate; but if there shall be no Maximum Rate, then the rate shall be as specified in the foregoing clause (a).
ARTICLE IV
RECORDS AND REPORTS
SECTION 4.01. Books and Records. Assignor shall at all times maintain true and correct books and records sufficient to determine the amounts payable to Assignee hereunder, including, but not limited to, a Net Proceeds account to which Gross Proceeds and Production Costs are credited and charged.
SECTION 4.02. Inspections. The books and records referred to in Section 4.01 shall be open for inspection by Assignee and its agents and representatives at the office of Assignor during normal business hours and after reasonable advance notice.
SECTION 4.03. Quarterly Statements. Within thirty (30) days next following the close of each calendar quarter, Assignor shall deliver to Assignee a statement showing the computation of Net Proceeds attributable to such quarter.
SECTION 4.04. Assignee's Exceptions to Quarterly Statements. If Assignee shall take exception to any item or items included in the quarterly statements rendered by Assignor, Assignee shall notify Assignor in writing within 180 days after the receipt of the report and annual audit furnished pursuant to Section 4.07 hereof, setting forth in such notice the specific charges complained of and to which exception is taken or the specific credits which should have been made and allowed; and, with respect to such complaints and exceptions as are justified, adjustment shall be made. If Assignee shall fail to give Assignor notice of such complaints and exceptions prior to the expiration of such 180 day period, then the statements for such calendar year as originally rendered by Assignor shall be deemed to be correct as rendered.
SECTION 4.05. Geological and Other Data. Upon request by Assignee, Assignor shall, subject to the limitations of confidentiality or nondisclosure obligations to co-owners or other third parties, furnish to Assignee access to all geological, well and production data which Assignor has
on hand relating to operations on the Subject Interests. Assignor will use reasonable efforts to obtain waivers of any such confidentiality or nondisclosure obligations that prevent it from providing to Assignee any requested information, but Assignor shall not be obligated to incur any expense or detriment above a nominal amount to obtain such waiver. Assignor shall also furnish to Assignee, upon request by Assignee, reports showing the status of development, producing and other operations conducted by Assignor on the Subject Interests. Assignor shall, upon request by Assignee, furnish to Assignee all reserve reports or studies in the possession of Assignor from time to time relating to the Subject Interests, whether prepared by Assignor or by third party consulting engineers; provided, it is agreed that Assignor makes no representations or warranties as to the accuracy or completeness of any such reports or studies and shall have no liability to Assignee or any other Person resulting from their use of such reports or studies, and Assignee agrees not to attribute to Assignor or such third-party consulting engineers any such reports or studies or the contents thereof in any securities filings or reports to owners or holders of "Beneficial Interests" in the Trust. All information furnished to Assignee pursuant to this section is confidential and for the sole benefit of Assignee and shall not be shown by Assignee to any other Person, except that this provision shall not prohibit the disclosure by Assignee of any information that (i) at the time of disclosure is generally available to the public (other than as a result of a disclosure by Assignee), (ii) was available to Assignee on a nonconfidential basis from a source other than Assignor, provided that such source is not known by Assignee to be bound by a confidentiality obligation owed to Assignor, or (iii) Assignee is legally required to disclose, provided that Assignee has given to Assignor notice of such requirement and a reasonable opportunity to seek, at Assignor's expense, a protective order and other appropriate relief from such requirement.
SECTION 4.06. Monthly Estimates. On or before ten days (excluding Saturdays, Sundays and other days on which national banking institutions in the City of Fort Worth, Texas, are closed as authorized or required by law) before each Monthly Record Date (beginning with the Monthly Record Date for March, 1999), Assignor shall deliver to Assignee a statement of Assignor's best estimate of the amount payable to Assignee on or before such Monthly Record Date.
SECTION 4.07. Annual Audits and Reports. Within 90 days after the end of the calendar year, Assignor shall deliver to Assignee a statement which has been audited by a nationally recognized firm of independent public accountants selected by Assignor, which shall show the information provided for in Section 4.03 on an annual basis. Assignee shall bear the cost of each such audit.
SECTION 4.08. Reserve Reports. Assignor may, but is not obligated to, provide an annual reserve report for the Royalty Interest prepared by independent consulting reservoir engineers. If such reserve report is provided by Assignor, Assignee will reimburse Assignor for the cost thereof.
ARTICLE V
LIABILITY OF ASSIGNEE
In no event shall Assignee be liable or responsible in any way for any Production Costs (including Excess Production Costs) or other costs or liabilities incurred by Assignor or others attributable to the Subject Interests or to the Hydrocarbons produced therefrom.
ARTICLE VI
OPERATION OF SUBJECT INTERESTS
SECTION 6.01. Prudent Operator Standard. Assignor agrees, to the extent it has the legal right to do so under the terms of any lease, operating agreement, contract for development or similar instrument affecting or pertaining to the Subject Interests (or any portion thereof), that it will conduct and carry on the maintenance and operation of the Subject Interests with reasonable and prudent business judgment and in accordance with good oil and gas field practices, and that it will drill such wells as a reasonably prudent operator would drill from time to time in order to protect the Subject Interests from drainage. Assignor further agrees to produce the Subject Interests without regard to whether any amount is imputed to the Gross Proceeds for any Computation Period during the period from the Effective Date through January 31, 2000, as provided in Section 1.09. However, nothing contained in this Section 6.01 shall be deemed to prevent or restrict Assignor from electing not to participate in any operation which is to be conducted under the terms of any operating agreement, contract for development or similar instrument affecting or pertaining to the Subject Interests (or any portion thereof) and allowing consenting parties to conduct nonconsent operations thereon, if such election is made by Assignor in good faith. Notwithstanding anything elsewhere herein to the contrary, Assignor shall never be liable to Assignee for the manner in which Assignor performs its duties hereunder as long as Assignor has acted in good faith.
SECTION 6.02. Abandonment of Properties. Nothing herein contained shall obligate Assignor to continue to operate any well or to operate or maintain in force or attempt to maintain in force any of the Subject Interests when, in Assignor's opinion, such well or Subject Interest ceases to produce or is not capable of producing Hydrocarbons in paying quantities. The expiration of a Subject Interest in accordance with the terms and conditions applicable thereto shall not be considered to be a voluntary surrender or abandonment thereof.
SECTION 6.03. Insurance. Although Assignor is permitted to carry policies of insurance covering the property upon the Subject Interests and risks incident to the operation thereof and to charge premiums therefor to the Net Proceeds account, Assignor shall not be required to carry insurance on such property or covering any of such risks unless it elects to do so. In no event shall Assignor be liable to Assignee on account of any losses sustained which are not covered by insurance.
SECTION 6.04. Certain Rights to Manage the Subject Interests.
Notwithstanding anything in this Conveyance to the contrary, Assignor shall have
the right and power, acting in good faith and as a reasonably prudent oil and
gas operator, to execute, deliver, and perform operating agreements, oil and gas
leases, farmout agreements, exploration agreements, participation agreements,
drilling agreements, acreage contribution agreements, dry-hole agreements,
bottom-hole agreements, joint venture agreements, partnership agreements, and
other similar instruments and agreements that cover or affect the Subject
Interests and to make all decisions or elections required thereunder, including,
but not limited to, decisions to consent or non-consent to drilling and other operations. The applicable Royalty Interest shall in each case be bound by such instrument or agreement (and decisions or elections thereunder), without the necessity of any execution, consent, joinder, or ratification by Assignee, and the Royalty Interest shall thereafter be calculated and paid with respect to the interests reserved, obtained, or modified by Assignor in such transaction, not by reference to the Subject Interests that existed before such transaction. For example, but not by way of limitation, (a) Assignor may farm out any Subject Interest that is an oil and gas lease, and the Subject Interest therein shall subsequently be the overriding royalty interest, reversionary working interest, and/or other rights and interests reserved by Assignor in the farmout, not the original leasehold interest, or (b) Assignor may execute an oil and gas lease to cover any Subject Interest that is a mineral interest, and the Subject Interest shall subsequently be the royalty and other lease benefits obtained or reserved by Assignor in such lease, not the original mineral interest.
ARTICLE VII
POOLING AND UNITIZATION
SECTION 7.01. Pooled Subject Interests. To the extent any of the Subject Interests have been heretofore pooled and unitized for the production of Hydrocarbons, such Subject Interests are and shall be subject to the terms and provisions of such pooling and unitization agreements, and the Royalty Interest in each such Subject Interest shall apply to and affect only the production from such units which accrues to such Subject Interest under and by virtue of the applicable pooling and unitization agreements.
SECTION 7.02. Right to Pool and Unitize. Assignor shall have the exclusive right and power (as between Assignor and Assignee), exercisable only during the period provided in Section 7.03 hereof, to pool or unitize any of the Subject Interests and to alter, change or amend or terminate any pooling or unitization agreements heretofore or hereafter entered into, as to all or any part of the Subject Lands, as to any one or more of the formations or horizons thereunder, and as to any one or more Hydrocarbons, upon such terms and provisions as Assignor shall in its sole and absolute discretion determine. If and whenever through the exercise of such right and power, or pursuant to any law hereafter enacted or any rule, regulation or order of any governmental body or official hereafter promulgated, any of the Subject Interests are pooled or unitized in any manner, the Royalty Interest insofar as it affects such Subject Interest shall also be pooled and unitized, and in any such event such Royalty Interest in such Subject Interest shall apply to and affect only the production which accrues to such Subject Interest under and by virtue of the pooling and unitization, and it shall not be necessary for Assignee to agree to, consent to, ratify, confirm or adopt any exercise of such right and power by Assignor.
SECTION 7.03. Applicable Period. Assignor's power and rights in Section 7.02 shall be exercisable only during the period of the life of the last survivor of the descendants of the signers of the Declaration of Independence living on the date of execution hereof, plus twenty-one (21) years after the death of such last survivor, or the term of this Conveyance, whichever period shall first expire.
ARTICLE VIII
GOVERNMENT REGULATION
All obligations of Assignor hereunder shall be subject to all present and future valid federal, state and local laws, statutes, codes and orders; and all applicable rules, orders, regulations and decisions of every court, governmental agency, body or authority having jurisdiction over the Hydrocarbons in and under and that may be produced from the Subject Interests. Assignor's obligations are specifically, but not by way of limitation, subject, to the extent in effect, to all applicable provisions of the Emergency Petroleum Allocation Act of 1973, the Department of Energy Organization Act, the Natural Gas Act, the Natural Gas Policy Act of 1978, the Natural Gas Wellhead Decontrol Act of 1989 and each other statute purporting to provide regulation of the Sale of Hydrocarbons or establishing maximum prices at which the same may be Sold and all applicable laws, orders, rules and regulations thereunder of the Federal Energy Regulatory Commission, the Department of Energy and each other legislative or governmental body, agency, board or commission having jurisdiction. If maximum rates permitted under such statutes, rules and regulations for the Subject Hydrocarbons are lower than prices established in Sales Contracts, then the lower regulated prices received by Assignor shall control. Assignor shall be entitled to use its reasonable discretion in making filings, for itself and on behalf of Assignee, with the Federal Energy Regulatory Commission, the Department of Energy or any other governmental body, agency, board or commission having jurisdiction, affecting the price or prices at which Subject Hydrocarbons may be Sold, and with purchasers of production, operators or others with respect to any excise tax.
ARTICLE IX
ASSIGNMENTS
SECTION 9.01. Assignment by Assignor. Assignor shall have the right to assign, sell, transfer, convey, mortgage or pledge the Subject Interests, or any part thereof, subject to the Royalty Interest and the terms and provisions of this Conveyance. From and after the effective date of any such assignment, sale, transfer or conveyance by Assignor, the assignee thereunder shall succeed to all the requirements upon and responsibilities of Assignor hereunder, as to the interests in the Subject Interests so acquired by such assignee, and, from and after the said effective date, Assignor shall be relieved of such requirements and responsibilities, excepting only those accrued or due for performance prior to such effective date.
SECTION 9.02. Partial Assignment. If Assignor assigns its interest under the Subject Interests as to some of such Subject Interests or as to some part thereof, then, effective as of the date of such assignment, in determining the Royalty Interest payable with respect to production from such assigned Subject Interests or parts thereof, the Gross Proceeds, Production Costs and Net Proceeds attributable to such assigned interests will be computed and determined by the assignee of such assigned interests in the aggregate as to the assigned interests owned by such assignee, but separate from and not aggregated with the computation and determination made by Assignor as to Subject Interests that have not been assigned by Assignor.
SECTION 9.03. Assignment by Assignee. Assignee has the right to assign the Royalty Interest in whole or in part only as authorized by the Trust Indenture. However, no such assignment will affect the method of computing Net Proceeds, and if more than one Person becomes entitled to participate in the Royalty Interest, Assignor may withhold from such other Person payments to which such Person would otherwise be entitled hereunder and the furnishing of any data or information which Assignor is required by the terms hereof to furnish Assignee until Assignor is furnished a recordable instrument executed by or binding upon all Persons interested in the Royalty Interest designating one Person who is to receive such payments, data and information. In making conveyances or assignments of any of the Subject Interests (to the extent permitted hereunder), Assignee need not vest in its grantee or assignee all of the rights of Assignee hereunder with respect to the interest in the Subject Interests so conveyed or assigned.
SECTION 9.04. Certain Sales of Subject Interests. Subject to the limitations set forth in Section 3.02(b) of the Trust Indenture, Assignor may cause the sale of certain Subject Interests, including the appurtenant Royalty Interest from time to time and Assignee will join in such sales as provided in the Trust Indenture. The proceeds of any such sale shall be apportioned and paid as provided in the Trust Indenture, but the purchasers of such Subject Interests (inclusive of the appurtenant Royalty Interest) may pay the full amount of the purchase price therefor to Assignor and shall have no responsibility to see to the proper allocation thereof between Assignor and Assignee.
SECTION 9.05. Change in Ownership. No change of ownership or right to receive payment of the Royalty Interest, or of any part thereof, however accomplished, shall be binding upon Assignor until notice thereof shall have been furnished by the Person claiming the benefit thereof, and then only with respect to payments thereafter made. Notice of sale or assignment shall consist of a certified copy of the recorded instrument accomplishing the same; notice of change of ownership or right to receive payment accomplished in any other manner (for example by reason of incapacity, death or dissolution) shall consist of certified copies of recorded documents and complete proceedings legally binding and conclusive of the rights of all parties. Until such notice accompanied by such documentation shall have been furnished Assignor as above provided, the payment or tender of all sums payable on the Royalty Interest may be made in the manner provided herein precisely as if no such change in interest or ownership or right to receive payment had occurred, or (at Assignor's election) Assignor shall have the right to suspend payment of such sums without interest in the event of such change until such documentation is furnished. The kind of notice herein provided shall be exclusive, and no other kind, whether actual or constructive, shall be binding on Assignor.
SECTION 9.06. Rights of Mortgagee or Trustee. If Assignee shall at any time execute a mortgage or deed of trust covering all or part of the Royalty Interest, the mortgagee(s) or trustee(s) therein named or the holder of any obligation secured thereby shall be entitled, to the extent such mortgage or deed of trust so provides, to exercise all the rights, remedies, powers and privileges conferred upon Assignee by the terms of this Conveyance and to give or withhold all consents required to be obtained hereunder by Assignee, but the provisions of this Section 9.06 shall in no way be deemed or construed to impose upon Assignor any obligation or liability undertaken by Assignee under such mortgage or deed of trust or under the obligation secured thereby.
ARTICLE X
MISCELLANEOUS
SECTION 10.01. Proportionate Reduction. In the event of failure or deficiency in title to any of the Subject Interests, the portion of the production from such Subject Interest out of which the Royalty Interest attributable to such Subject Interest shall be payable shall be reduced in the same proportion that such Subject Interest is reduced. Notwithstanding the foregoing, if any Person claims that this Conveyance gives rise to a preferential right of such Person to acquire any portion of the Royalty Interest (or any of the Subject Interests), then Assignor shall indemnify Assignee and the trustee of the Trust against any liability, expense, damage or loss in regard to such claim and the provisions of Section 6.05 of the Trust Indenture shall apply with respect to such indemnity obligation. If such claim results in the acquisition of any portion of the Royalty Interest by the Person claiming the preferential right then, subject to the proviso below, Assignor shall pay to Assignee the amount determined by multiplying (i) the product of 40,000,000 multiplied by the initial public offering price of the Trust's units of beneficial interest by (ii) a fraction, the numerator of which is the value of the portion of the Royalty Interest acquired by the Person claiming the preferential right, as determined by reference to the most recent Reserve Report (as defined in the Trust Indenture) of the Trust and the denominator of which is the value of all the Royalty Interest as determined by reference to such Reserve Report; provided, however, that if the Person claiming such preferential right makes any payment to the Trust in connection with the acquisition of a portion of the Royalty Interest, then the amount of such payment shall be credited against Assignor's payment obligation set forth above, but not to create a negative number.
SECTION 10.02. Term. This Conveyance shall remain in force as long as any of the Subject Interests are in effect.
SECTION 10.03. Further Assurances. Should any additional instruments of assignment and conveyance be required to describe more specifically any interests subject hereto, Assignor agrees to execute and deliver the same. Also, if any other or additional instruments are required in connection with the transfer of State, Federal or Indian lease interests in order to comply with applicable laws, regulations or agreements, Assignor will execute and deliver the same.
SECTION 10.04. Notices. All notices, statements, payments and communications between the parties hereto shall be deemed to have been sufficiently given and delivered if enclosed in a post paid wrapper and deposited in the United States Mails directed, or if personally delivered, to the party to whom the same is directed or to be furnished or made at the respective addresses, as follows:
If to Assignor:
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Fort Worth, Texas 76102
Attention: Corporate Secretary
If to Assignee:
NationsBank, N.A.
17th Floor
901 Main Street
NationsBank Plaza
Dallas, Texas 75202
Attention: Trust Department
Either party or the successors or assignees of the interest or rights or obligations of either party hereunder may change its address or designate a new or different address or addresses for the purposes hereof by a similar notice given or directed to all parties interested hereunder at the time.
SECTION 10.05. Binding Effect. This Conveyance shall bind and inure to the benefit of the successors and assigns of Assignor and Assignee.
SECTION 10.06. Governing Law. The validity, effect and construction of this Conveyance shall be governed by the laws of the State of Texas.
SECTION 10.07. Headings. Article and Section headings used in this Conveyance are for convenience only and shall not affect the construction of this Conveyance.
SECTION 10.08. Substitution of Warranty. This instrument is made with full substitution and subrogation of Assignee in and to all covenants of warranty by others heretofore given or made with respect to the Subject Interests or any part thereof or interest therein.
SECTION 10.09. Counterpart Execution. This Conveyance may be executed in multiple counterparts, each of which shall be an original. Certain counterparts may have descriptions relating to different recording jurisdictions omitted from Schedule A. A counterpart with all such descriptions is being filed for record in Lincoln County, Wyoming. Where a description covers an interest located in more than one county, such description may be included in counterparts recorded in each county but such inclusion of the same description in more than one counterpart does not have any cumulative effect as to the interests covered by such description.
SECTION 10.10. Amended and Restated Conveyance. This Conveyance amends and restates fully a document previously executed by Assignor and Assignee. Such prior document was
not recorded and is fully replaced and superseded by this Conveyance and such previously executed document is to be disregarded for all purposes.
IN WITNESS WHEREOF, each of the parties hereto has caused this Conveyance to be executed in its name and behalf and delivered as of the Effective Date.
ATTEST:
CROSS TIMBERS OIL COMPANY
------------------------------
Virginia Anderson, Secretary
of Cross Timbers Oil By:
Company --------------------------------------
Vaughn O. Vennerberg, II
Senior Vice President - Land
|
STATE OF TEXAS (S)
(S)
COUNTY OF TARRANT (S)
This instrument was acknowledged before me on this ____ day of _______, 1999, by Vaughn O. Vennerberg II, Senior Vice President - Land of Cross Timbers Oil Company, on behalf of said corporation.
THE STATE OF TEXAS (S)
(S)
COUNTY OF DALLAS (S)
This instrument was acknowledged before me on this ____ day of _______, 1999, by Ron E. Hooper, Vice President of NationsBank, N.A., Trustee of the Hugoton Royalty Trust, on behalf of said Bank as Trustee of the Hugoton Royalty Trust.
SCHEDULE B
Attached to and made a part of that certain Net Overriding Royalty Conveyance
(Hugoton Royalty Trust) dated effective December 1, 1998 (the "Conveyance")
ACCOUNTING PROCEDURE
I. GENERAL PROVISIONS
1. Definitions
"Joint Property" shall mean the real and personal property subject to the
Conveyance.
"Joint Operations" shall mean all operations necessary or proper for the
development, operation, protection and maintenance of the Joint Property.
"Joint Account" shall mean the account showing the charges paid and credits
received in the conduct of the Joint Operations and which are used in the
calculation of Gross Proceeds, Net Proceeds, Processing Costs and
Production Costs, as said terms are defined in the Conveyance.
"Operator" shall mean Cross Timbers Oil Company or any of its affiliates
that conduct Joint Operations on the Joint Property.
"Parties" shall mean Operator and the Hugoton Royalty Trust (herein
referred to as the "Trust").
"First Level Supervisors" shall mean those employees whose primary function
in Joint Operations is the direct supervision of other employees and/or
contract labor directly employed on the Joint Property in a field operating
capacity.
"Technical Employees" shall mean those employees having special and
specific engineering, geological or other professional skills, and whose
primary function in Joint Operations is the handling of specific operating
conditions and problems for the benefit of the Joint Property.
"Personal Expenses" shall mean travel and other reasonable reimbursable
expenses of Operator's employees.
"Material" shall mean personal property, equipment or supplies acquired or
held for use on the Joint Property.
"Controllable Material" shall mean Material which at the time is so
classified in the Material Classification Manual as most recently
recommended by the Council of Petroleum Accountants Societies.
2. Designation and Responsibilities of Operator
Cross Timbers Oil Company shall be the Operator of the Joint Property, and shall, to the extent it has the legal right to do so, conduct and direct and have full control of all operations on the Joint Property as permitted and required by, and within the limits of the Conveyance.
3. Payments and Accounting
Except as herein otherwise specifically provided, Operator shall promptly pay and discharge expenses incurred in the development and operation of the Joint Property and shall charge the Joint Account with the appropriate proportionate share upon the expense basis provided herein. Operator shall keep an accurate record of the expenses incurred and charges and credits made and received.
4. Application of Agreement
This Accounting Procedure will apply to Joint Properties where Cross Timbers Oil Company is the Operator and the Operator owns all or a portion of the leasehold interest in the Joint Properties. In the event there is an existing Accounting Procedure or related instrument governing the operations of the Joint Properties, this
Accounting Procedure will control except as to the overhead rate stated in the existing Accounting Procedure or related instrument.
5. Conflicts
In the event there exists any conflict between the terms of this Accounting Procedure or any Accounting Procedure that applies to the Joint Properties and the Conveyance to which it is attached, the Conveyance will control.
II. DIRECT CHARGES
Operator shall charge the Joint Account with the following items, which shall be allocated to Processing Costs or Production Costs as appropriate:
1. Ecological and Environmental
Costs incurred for the benefit of the Joint Property as a result of governmental or regulatory requirements to satisfy environmental considerations applicable to the Joint Operations. Such costs may include surveys of an ecological or archaeological nature and pollution control procedures as required by applicable laws and regulations, and costs related to employees of Operator performing any environmental work involving the Joint Property.
2. Rentals and Royalties
Lease rentals and royalties paid by Operator for the Joint Operations.
3. Labor
A. (1) Salaries and wages of Operator's field employees employed on the Joint Property in the conduct of Joint Operations.
(2) Salaries of First Level Supervisors in the field.
(3) Salaries and wages of Technical Employees directly employed on the Joint Property.
(4) Salaries and wages of Technical Employees either temporarily or permanently assigned to and directly employed in the operation of the Joint Property.
B. Operator's cost of holiday, vacation, sickness and disability benefits
and other customary allowances paid to employees whose salaries and
wages are chargeable to the Joint Account under Paragraph 3A of this
Section II. Such costs under this Paragraph 3B may be charged on a
"when and as paid basis" or by "percentage assessment" on the amount
of salaries and wages chargeable to the Joint Account under Paragraph
3A of this Section II. If percentage assessment is used, the rate
shall be based on the Operator's cost experience.
C. Expenditures or contributions made pursuant to assessments imposed by
governmental authority which are applicable to Operator's costs
chargeable to the Joint Account under Paragraphs 3A and 3B of this
Section II.
D. Personal Expenses of those employees whose salaries and wages are chargeable to the Joint Account under Paragraph 3A of this Section II.
4. Employee Benefits
Operator's current costs of established plans for employees' group life insurance, hospitalization, pension, retirement, stock purchase, thrift, bonus, and other benefit plans of a like nature, applicable to Operator's labor cost chargeable to the Joint Account under Paragraph 3A and 3B of this Section II shall be Operator's actual cost not to exceed the percent most recently recommended by the Council of Petroleum Accountants Societies.
5. Material
Material purchased or furnished by Operator for use on the Joint Property as provided under Section IV. Only such Material shall be purchased for or transferred to the Joint Property as may be required for immediate use and is reasonably practical and consistent with efficient and economical operations. The accumulation of surplus stocks shall be avoided.
6. Transportation
Transportation of employees and Material necessary for the Joint Operations but subject to the following limitations:
A. If Material is moved to the Joint Property from the Operator's warehouse or other properties, no charge shall be made to the Joint Account for a distance greater than the distance from the nearest reliable supply store where like material is normally available or railway receiving point nearest the Joint Property.
B. If surplus Material is moved to Operator's warehouse or other storage point, no charge shall be made to the Joint Account for a distance greater than the distance to the nearest reliable supply store where like material is normally available, or railway receiving point nearest the Joint Property. No charge shall be made to the Joint Account for moving Material to other properties belonging to Operator.
C. In the application of subparagraphs A and B above, the option to equalize or charge actual trucking cost is available when the actual charge is $400 or less excluding accessorial charges. The $400 will be adjusted to the amount most recently recommended by the Council of Petroleum Accountants Societies.
7. Services
The cost of contract services, equipment and utilities provided by outside sources, except services excluded by Paragraph 10 of Section II and Paragraph i, ii, and iii, of Section III. The cost of professional consultant services and contract services of technical personnel directly engaged on the Joint Property if such charges are excluded from the overhead rates.
8. Equipment and Facilities Furnished By Operator
A. Operator shall charge the Joint Account for use of equipment and facilities owned by Operator or any of its affiliates at rates commensurate with costs of ownership and operation. Such rates shall include costs of maintenance, repairs, other operating expense, insurance, taxes, depreciation, and interest on gross investment less accumulated depreciation not to exceed twelve percent (12%) per annum. Such rates shall not exceed average commercial rates currently prevailing in the immediate area of the Joint Property.
B. In lieu of charges in paragraph 8A above, Operator may elect to use average commercial rates prevailing in the immediate area of the Joint Property less 20%. For automotive equipment, Operator may elect to use rates published by the Petroleum Motor Transport Association.
C. This Paragraph 8 shall not affect any current charges made by Operator to the Joint Account related to transportation, gathering, treating, compression or processing or related charges by an affiliate of Operator.
9. Damages and Losses to Joint Property
All costs or expenses necessary for the repair or replacement of Joint Property made necessary because of damages or losses incurred by fire, flood, storm, theft, accident, or other cause, except those resulting from Operator's gross negligence or willful misconduct.
10. Legal Expense
Expense of handling, investigating and settling litigation or claims, discharging of liens, payment of judgments and amounts paid for settlement of claims incurred in or resulting from operations under the Conveyance or necessary to protect or recover the Joint Property, and the costs and expenses incurred in connection with hearings and other matters before governmental bodies and agencies and costs and expenses incurred in curing title to the Joint Property. Costs incurred by Operator in procuring abstracts and fees paid outside attorneys for title examination (including preliminary, supplemental, shut-in gas royalty opinions and division order title opinions) shall be borne by the Joint Account. Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of the above functions. All other legal expense is considered to be covered by the overhead provisions of Section III.
11. Taxes
All taxes of every kind and nature assessed or levied upon or in connection with the Joint Property, the operation thereof, or the production therefrom, and which taxes have been paid by the Operator for the benefit of the Parties. If the ad valorem taxes are based in whole or in part upon separate valuations of each party's interest, then notwithstanding anything to the contrary herein, charges to the Joint Account shall be made and paid by the Parties hereto in accordance with the tax value generated by each party's interest.
12. Insurance
Net premiums paid for insurance required to be carried for the Joint Operations for the protection of the Parties. In the event Joint Operations are conducted in a state in which Operator may act as self- insurer for Worker's Compensation and/or Employers Liability under the respective state's laws, Operator may, at its election, include the risk under its self-insurance program and in that event, Operator shall include a charge at Operator's cost not to exceed manual rates.
13. Abandonment and Reclamation
Costs incurred for abandonment of the Joint Property, including costs required by governmental or other regulatory authority.
14. Communications
Cost of acquiring, leasing, installing, operating, repairing and maintaining communication systems, including radio and microwave facilities or any form of telephonic equipment or service used in serving the Joint Property. In the event communication facilities/systems serving the Joint Property are Operator owned, charges to the Joint Account shall be made as provided in Paragraph 8 of this Section II.
15. Other Expenditures
Any other expenditure not covered or dealt with in the foregoing provisions of this Section II, or in Section III and which is of direct benefit to the Joint Property and is incurred by the Operator in the necessary and proper conduct of the Joint Operations.
III. OVERHEAD
1. Overhead - Drilling and Producing Operations
i. As compensation for administrative, supervision, office services and warehousing costs, Operator shall charge drilling and producing operations on a Fixed Rate Basis, Paragraph 1A. Such charge shall be in lieu of costs and expenses of all offices and salaries or wages plus applicable burdens and expenses of all personnel, except those directly chargeable under Paragraph 3A, Section II. The cost and expense of services from outside sources in connection with matters of taxation, traffic, accounting or matters before or involving governmental agencies shall not be considered as included in the overhead rates.
ii. The salaries, wages and Personal Expenses of Technical Employees and/or the cost of professional consultant services and contract services of technical personnel directly employed on the Joint Property shall not be covered by the overhead rates.
iii. The salaries, wages and Personal Expenses of Technical Employees and/or costs of professional consultant services and contract services of technical personnel either temporarily or permanently assigned to and directly employed in the operation of the Joint Property shall not be covered by the overhead rates.
A. Overhead - Fixed Rate Basis
(1) Operator shall charge the Joint Account at the following rates per well per month:
For wells located in the Hugoton Field Drilling Well Rate $2,350.00
(Prorated for less than a full month)
Producing Well Rate $235.00
For wells located in all other areas
Drilling Well Rate $4,760.00
(Prorated for less than a full month)
Producing Well Rate $476.00
(2) Application of Overhead - Fixed Rate Basis shall be as follows:
(a) Drilling Well Rate
(1) Charges for drilling wells shall begin on the date the well is spudded and terminate on the date the drilling rig, completion rig, or other units used in completion of the well is released, whichever is later, except that no charge shall be made during suspension of drilling or completion operations for fifteen (15) or more consecutive calendar days.
(2) Charges for wells undergoing any type of workover or recompletion or swabbing shall be made at the drilling well rate. Such charges shall be
applied for the period from date such operations, with rig or other units used, commence through date of rig or other unit release, except that no charge shall be made during suspension of operations for fifteen (15) or more consecutive calendar days.
(b) Producing Well Rates
(1) An active well either produced or injected into for any portion of the month shall be considered as a one-well charge for the entire month.
(2) Each active completion in a multi-completed well in which production is not commingled down hole shall be considered as a one-well charge providing each completion is considered a separate well by the governing regulatory authority.
(3) An inactive gas well shut in because of overproduction or failure of purchaser to take the production shall be considered as a one-well charge providing the gas well is directly connected to a permanent sales outlet.
(4) A one-well charge shall be made for the month in which plugging and abandonment operations are completed on any well. This one-well charge shall be made whether or not the well has produced except when drilling well rate applies.
(5) All other inactive wells (including but not limited to inactive wells covered by unit allowable, lease allowable, transferred allowable, etc.) shall not qualify for an overhead charge.
(3) The well rates shall be adjusted as of the first day of April each year beginning in 1999. The adjustment shall be computed by multiplying the rate currently in use 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 rates shall be the rates currently in use, plus or minus the computed adjustment.
2. Overhead - Major Construction
To compensate Operator for overhead costs incurred in the construction and installation of fixed assets, the expansion of fixed assets, and any other project clearly discernable as a fixed asset required for the development and operation of the Joint Property, Operator shall charge the Joint Account for overhead based on the following rates for any Major Construction project in excess of $25,000.00:
A. 5% of first $100,000 or total cost if less, plus
B. 3% of costs in excess of $100,000 but less than $1,000,000, plus
C. 2% of costs in excess of $1,000,000.
Total cost shall mean the gross cost of any one project. For the purpose of this paragraph, the component parts of a single project shall not be treated separately and the cost of drilling and workover wells and artificial lift equipment shall be excluded.
3. Catastrophe Overhead
To compensate Operator for overhead costs incurred in the event of expenditures resulting from a single occurrence due to oil spill, blowout, explosion, fire, storm, hurricane, or other catastrophes as agreed to by the Parties, which are necessary to restore the Joint Property to the equivalent condition that existed prior to the event causing the expenditures, Operator shall charge the Joint Account for overhead based on the following rates:
A. 5% of total costs through $100,000; plus
B. 3% of total costs in excess of $100,000 but less than $1,000,000; plus
C. 2% of total costs in excess of $1,000,000.
Expenditures subject to the overheads in this Section 3 above will not be
reduced by insurance recoveries, and no other overhead provisions of this
Section III shall apply.
IV. PRICING OF JOINT ACCOUNT MATERIAL PURCHASES, TRANSFERS AND DISPOSITIONS
Operator is responsible for Joint Account Materials and shall make proper and timely charges and credits for all Material movements affecting the Joint Property. Operator shall provide all Material for use on the Joint Property. Operator shall make timely disposition of idle and/or surplus Material, such disposal being made either through sale to Operator, or sale to outsiders. Operator may purchase, but shall be under no obligation to purchase, interest of the Trust in surplus condition A or B Material at the prices defined below.
1. Purchases
Material purchased shall be charged at the price paid by Operator after deduction of all discounts, adjustments or rebates received. In case of Material found to be defective or returned to vendor for any other reasons, credit shall be passed to the Joint Account when adjustment has been received by the Operator.
2. Transfers and Dispositions
Material furnished to the Joint Property and Material transferred from the Joint Property or disposed of by the Operator shall be priced on the following basis exclusive of cash discounts:
A. New Material (Condition A)
(1) Tubular Goods Other than Line Pipe
(a) Tubular goods, sized 2-3/8 inches OD and larger, except line pipe, shall be priced at Eastern mill published carload prices effective as of date of movement plus transportation cost using the 80,000 pound carload weight basis to the railway receiving point nearest the Joint Property for which published rail rates for tubular good exist. If the 80,000 pound rail rate is not offered, the 70,000 pound or 90,000 pound rail rate may be used. Freight charges for tubing will be calculated from Lorain, Ohio and casing from Youngstown, Ohio.
(b) For grades which are special to one mill only, prices shall be computed at the mill base of that mill plus transportation cost from that mill to the railway receiving point nearest the Joint Property as provided above in Paragraph 2.a.(1)(a). For transportation cost from points other than Eastern mills, the 30,000 pound Oil Field Haulers Association interstate truck rate shall be used.
(c) Special end finish tubular goods shall be priced at the lowest published out-of-stock price, f.o.b. Houston, Texas, plus transportation cost, using Oil Field Haulers Association interstate 30,000 pound truck rate, to the railway receiving point nearest the Joint Property.
(d) Macaroni tubing (size less than 2-3/8 inch OD) shall be priced at the lowest published out-of-stock prices f.o.b. the supplier plus transportation costs, using the Oil Field Haulers Association interstate truck rate per weight of tubing transferred, to the railway receiving point nearest the Joint Property.
(2) Line Pipe
(a) Line pipe movements (except size 24 inch OD and larger with walls 3/4 inch and over) 30,000 pounds or more shall be priced under provisions of tubular goods pricing in Paragraph A.(1)(a) as provided above. Freight charges shall be calculated from Lorain, Ohio.
(b) Line pipe movements (except size 24 inch OD and larger with
walls 3/4 inch and over) less than 30,000 pounds shall be
priced at Eastern mill published carload base prices
effective as of date of shipment, plus 20 percent, plus
transportation costs based on freight rates as set forth
under provisions of tubular goods pricing in Paragraph
A.(1)(a) as provided above. Freight charges shall be
calculated from Lorain, Ohio.
(c) Line pipe 24 inch OD and over and 3/4 inch wall and larger shall be priced f.o.b. the point of manufacture at current new published prices plus transportation cost to the railway receiving point nearest the Joint Property.
(d) Line pipe, including fabricated line pipe, drive pipe and conduit not listed on published price lists shall be priced at quoted prices plus freight to the railway receiving point nearest the Joint Property or at prices agreed to by the Parties.
(3) Other Material shall be priced at the current new price, in effect at date of movement, as listed by a reliable supply store nearest the Joint Property, or point of manufacture, plus transportation costs, if applicable, to the railway receiving point nearest the Joint Property.
(4) Unused new Material, except tubular goods, moved from the Joint Property shall be priced at the current new price, in effect on date of movement, as listed by a reliable supply store nearest the Joint Property, or point of manufacture, plus transportation costs, if applicable, to the railway receiving point nearest the Joint Property. Unused new tubulars will be priced as provided above in Paragraph 2 A (1) and (2).
B. Good Used Material (Condition B)
Material in sound and serviceable condition and suitable for reuse without reconditioning:
(1) Material moved to the Joint Property
At seventy-five percent (75%) of current new price, as determined by Paragraph A.
(2) Material used on and moved from the Joint Property
(a) At seventy-five percent (75%) of current new price, as determined by Paragraph A, if Material was originally charged to the Joint Account as new Material.
(b) At sixty-five percent (65%) of current new price, as determined by Paragraph A, if Material was originally charged to the Joint Account as used Material.
(3) Material not used on and moved from the Joint Property
At seventy-five percent (75%) of current new price as determined by Paragraph A.
The cost of reconditioning, if any, shall be absorbed by the transferring property.
C. Other Used Material
(1) Condition C
Material which is not in sound and serviceable condition and suitable for its original function until after reconditioning shall be priced at fifty percent (50%) of current new price as determined by Paragraph A. The cost of reconditioning shall be charged to the receiving property, provided Condition C value plus cost of reconditioning does not exceed Condition B value.
(2) Condition D
Material, excluding junk, no longer suitable for its original purpose, but usable for some other purpose shall be priced on a basis commensurate with its use. Operator may dispose of Condition D Material under procedures normally used by Operator without prior approval of the Assignee.
(a) Casing, tubing or drill pipe used as line pipe shall be priced as Grade A and B seamless line pipe of comparable size and weight. Used casing, tubing or drill pipe utilized as line pipe shall be priced at used line pipe prices.
(b) Casing, tubing or drill pipe used as higher pressure service lines than standard line pipe, e.g. power oil lines, shall be priced under normal pricing procedures for casing, tubing, or drill pipe. Upset tubular goods shall be priced on a non upset basis.
(3) Condition E
Junk shall be priced at prevailing prices. Operator may dispose of Condition E Material under procedures normally utilized by Operator without prior approval of Non-Operators.
D. Obsolete Material
Material which is serviceable and usable for its original function but condition and/or value of such Material is not equivalent to that which would justify a price as provided above may be specially priced as reasonably determined by Operator. Such price should result in the Joint Account being charged with the value of the service rendered by such Material.
E. Pricing Conditions
(1) Loading and unloading costs related to the movement of the Material to the Joint Property shall be charged in accordance with the methods specified in COPAS Bulletin 21.
(2) Material involving erection costs shall be charged at applicable percentage of the current knocked-down price of new Material.
3. Premium Prices
Whenever Material is not readily obtainable at published or listed prices because of national emergencies, strikes or other unusual causes over which the Operator has no control, the Operator may charge the Joint Account for the required Material at the Operator's actual cost incurred in providing such Material, in making it suitable for use, and in moving it to the Joint Property.
4. Warranty of Material Furnished by Operator
Operator does not warrant the Material furnished. In case of defective Material, credit shall not be passed to the Joint Account until adjustment has been received by Operator from the manufacturers or their agents.
V. INVENTORIES
The Operator shall maintain detailed records of Controllable Material.
1. Periodic Inventories, Notice and Representation
At reasonable intervals, inventories shall be taken by Operator of the Joint Account Controllable Material.
2. Reconciliation and Adjustment of Inventories
Adjustments to the Joint Account resulting from the reconciliation of a physical inventory shall be made within six months following the taking of the inventory. Inventory adjustments shall be made by Operator to the Joint Account for overages and shortages, but Operator shall be held accountable only for shortages due to lack of reasonable diligence.
3. Special Inventories
Special inventories may be taken whenever there is any sale, change of interest, or change of Operator in the Joint Property. It shall be the duty of the party selling to notify all other Parties as quickly as possible after the transfer of interest takes place. In such cases, both the seller and the purchaser shall be governed by such inventory. In cases involving a change of Operator, all Parties shall be governed by such inventory.
4. Expense of Conducting Inventories
A. The expense of conducting periodic inventories shall not be charged to the Joint Account.
B. The expense of conducting special inventories shall be charged to the Parties requesting such inventories, except inventories required due to change of Operator shall be charged to the Joint Account.
EXHIBIT 10.4
THIS AMENDED AND RESTATED REVOLVING CREDIT AGREEMENT is made and entered
into as of the 16th day of November, 1998, by and among CROSS TIMBERS OIL
COMPANY, a Delaware corporation ("Company"), the Banks that are signatories
hereto (collectively, the "Banks"), MORGAN GUARANTY TRUST COMPANY OF NEW YORK,
as Administrative Agent for Banks, NATIONSBANK, N.A., as Syndication Agent for
Banks and CHASE BANK OF TEXAS, N.A., as Documentation Agent for Banks.
W I T N E S S E T H:
WHEREAS, Company, Morgan Guaranty Trust Company of New York, as Administrative Agent for Banks, NationsBank, N.A., as Syndication Agent for Banks, Chase Bank of Texas, N.A., as Documentation Agent for Banks, and Banks have entered into that certain Amended and Restated Revolving Credit Agreement dated as of August 28, 1998, which amends and restates in its entirety that certain Revolving Credit Agreement dated as of April 17, 1998, as amended (as amended and as in effect as of the Closing Date (as defined below), as amended and restated hereby and as amended from time to time hereafter, the "Loan Agreement").
WHEREAS, the parties hereto desire to amend the Loan Agreement as set forth herein and to restate the Loan Agreement in its entirety to read as set forth in the Loan Agreement with the amendments specified below.
NOW, THEREFORE, in consideration of the premises herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties, intending to be legally bound, agree as follows:
ARTICLE I
Definitions and References
1.01 Unless otherwise specifically defined herein, each term used herein which is defined in the Loan Agreement as in effect immediately prior to the Closing Date shall have the meaning assigned to such term in the Loan Agreement as so in effect. Each reference to "hereof," "hereunder," "herein" and "hereby" and each other similar reference and each reference to "this Loan Agreement" and each other similar reference contained in the Loan Agreement shall from and after the Closing Date refer to the Loan Agreement as amended and restated hereby.
ARTICLE II
Amendments
2.01. Amendments to Article I. Effective as of the Closing Date, Article I of the Loan Agreement is amended as follows:
(A) Amendments to Certain Definitions. The definitions of Closing Date, Commitment, Proposed Royalty Trust and Threshold Amount are amended in their entirety and the following are substituted therefor:
(i) "Closing Date" shall mean November 16, 1998.
(ii) "Commitment" shall mean at any time Banks' commitment to make the
Loan and any Borrowing thereunder available to Company in an
aggregate amount at any time not to exceed the lesser of (i) the
Borrowing Base then in effect or (ii) the Facility Amount. With
respect to each Bank, its Commitment shall never exceed its
Percentage of the lesser of (i) the Borrowing Base then in effect or
(ii) the Facility Amount. The amount of each Bank's Commitment may
be terminated or reduced from time to time in accordance with the
provisions hereof. The Commitment as of the Closing Date is
$600,000,000, and upon closing of the San Juan Basin Acquisition the
Commitment shall be increased to $615,000,000, but subject to
further adjustment as provided in Section 5.05(a).
(iii) "Proposed Royalty Trust" shall mean the royalty trust to be formed by Company, pursuant to which Company shall assign and convey to such royalty trust an 80% net profits interest in primarily leasehold Mineral Properties owned by Company in the Hugoton Field in Kansas and Oklahoma, in the Green River Basin in Wyoming, in the Elk City area in Oklahoma and in such other Mineral Properties located in Oklahoma and Kansas as may be selected by Company. Initially, all beneficial units representing ownership of the Proposed Royalty Trust will be owned and held by Company. The Proposed Royalty Trust is further described in Section 5.05(b).
(iv) "Threshold Amount" shall mean, at any time during the period between the Closing Date to April 15, 1999, the lesser of (A) the amount determined under the PV Borrowing Base Test or (B) the amount equal to the remainder of (i) the quotient of (a) the Present Value of Borrowing Base Reserves that are attributable to the Proved Reserves allocable to the Borrowing Base Assets (provided that at least eighty-five percent (85%) of such Proved Reserves shall consist of Proved Developed Producing Reserves) plus the Gas Subsidiaries' Loan Value divided by (b) 1.35, less (ii) the unpaid principal balance of the Subordinated Indebtedness then outstanding. At the Closing Date, the Threshold Amount is $565,000,000. Upon closing of the San Juan Basin Acquisition, the Threshold Amount shall be increased to $590,000,000. During the period between the Closing Date to April 15, 1999, the Threshold Amount shall be determined (and approved by Majority Banks) as provided in Section 2.03(d) hereof and upon each redetermination of the Borrowing Base.
(B) Additional Definitions. The following definitions are hereby included in Article I of the Loan Agreement:
(i) "San Juan Basin Acquisition" shall mean the acquisition transactions to be consummated pursuant to which Company, as buyer, shall acquire the San Juan Basin Properties.
(ii) "San Juan Properties" shall mean the oil and gas properties and tax credit partnerships to be acquired by Company upon closing of the San Juan Basin Acquisition. The San Juan Basin Properties consist of undivided interests in certain oil and gas properties located in Rio Arriba and San Juan Counties, New Mexico and in Major and Woodward Counties, Oklahoma and interests in two coal seam tax credit partnerships.
(C) Amendment to the Definition of Permitted Margin Debt. The definition of Permitted Margin Debt is hereby amended by deleting the reference to "subclause (xi) of Section 9.01" as set forth in such definition and substituting therefor the reference to "subclause (xii) of Section 9.01."
2.02. Amendment to Section 5.02. Effective as of the Closing Date,
Section 5.02 of the Loan Agreement is amended in its entirety and the following
is substituted therefor:
"5.02. Initial Borrowing Base. During the period from the Closing Date to the closing of the San Juan Basin Acquisition, the Borrowing Base shall be $600,000,000. Upon consummation of the San Juan Basin Acquisition, the Borrowing Base shall be increased to $615,000,000, but subject to further adjustment as provided in Section 5.05(a). The Borrowing Base in effect from time to time is subject to adjustment as provided in Sections 5.03, 5.04 and 5.05."
2.03. Amendment to Section 5.05(a). Effective as of the Closing Date,
Section 5.05(a) of the Loan Agreement is amended by including the following
sentences at the conclusion of such section:
"Pursuant to the terms of the purchase and sale agreements evidencing the San Juan Basin Acquisition, at closing of the San Juan Basin Acquisition, certain of the San Juan Basin Properties may be excluded from such acquisitions and the purchase price for the San Juan Basin Properties may be reduced by the value allocated to such excluded properties, on account of title defects and/or adverse environmental conditions. After the purchase price for the San Juan Basin Properties has been reduced by an aggregate amount of $5,000,000 on account of such title defects and/or environmental conditions, the Borrowing Base shall thereafter be reduced by the loan value assigned to any additional properties that are affected by such title defects and/or environmental conditions according to the reserve report covering the San Juan Basin Properties that was delivered by Company to Agents or, if available, the most recent Reserve Report delivered to Banks."
2.04. Amendment to Section 5.05(b). Effective as of the Closing Date,
Section 5.05(b) of the Loan Agreement is amended by deleting the phrase "Company
may (but has no present
plans to) make a public offering of some or all of the units in the Proposed Royalty Trust" as set forth in such Section and substituting therefor the phrase "Company plans to make a public offering of some or all of the units in the Proposed Royalty Trust."
2.05. Amendment to Article 7. Effective as of the Closing Date, Article 7 of the Loan Agreement is amended by including the following Section 7.06:
"7.06. San Juan Basin Acquisition. In addition to the conditions precedent set forth in Section 7.02, the obligation of Banks to increase the Borrowing Base and the Commitment by the amounts set forth herein shall be subject to the following additional conditions precedent:
(a) Environmental Certificate. A certificate signed by a duly authorized officer of Company, stating that Company has reviewed the effect of Environmental Laws on the San Juan Basin Properties, and associated liabilities and costs, and on the basis of such review, neither Company nor its predecessor in title to the San Juan Basin Properties is, in any material respect, in violation of any Environmental Laws applicable to the San Juan Basin Properties, and the Company reasonably believes that Environmental Laws then in effect that are applicable to the San Juan Basin Properties are unlikely to have a Material Adverse Effect on Company or its Subsidiaries considered as a whole.
(b) Title Information. Supplemental title opinions, updated title reports, existing title opinions, assignments, division orders, and/or other evidence of title requested by Agents, covering the properties to be acquired by Company pursuant to the San Juan Basin Acquisition evidencing that (subject to Permitted Liens) Company shall have good and marketable title to such properties that constitute not less than 60% of the value of all of the San Juan Basin Properties to be acquired pursuant to the San Juan Basin Acquisition, and assignments and other instruments of conveyance to Company that vest title to the San Juan Basin Properties to be acquired pursuant to the San Juan Basin Acquisition in Company."
(c) Prior Notice. On the closing date of the San Juan Basin Acquisition, Company shall provide Agents (with copy to Administrative Agent's office at Morgan Christiana Center, 500 Stanton Christiana Road, Newark, Delaware 19713, Attention: Ms. Sandra Doherty) with written notice of the closing of the San Juan Basin Acquisition and the Commitment and Borrowing Base to be in effect after consummation of the San Juan Basin Acquisition."
2.06. Amendment to Section 9.01. Effective as of the Closing Date, the following subclause (xiv) is included in Section 9.01 of the Loan Agreement:
"(xiv) the obligation of Company to make up to $6,000,000 in deferred payments to the sellers of the Shell Properties pursuant to the terms of the purchase and sale agreement for the Shell Acquisition."
2.07. Amendment to Section 9.21. Effective as of the Closing Date, subclause (iii) of Section 9.21 of the Loan Agreement is amended in its entirety to read as follows:
"(iii) Company shall not form the Proposed Royalty Trust after December 31, 1999,"
2.08. Amendment to Schedule I. Effective as of the Closing Date, Schedule I of the Loan Agreement amended in its entirety and the Schedule I attached hereto shall be substituted therefor.
ARTICLE III
Condition Precedent
3.01 Counterparts; Conditions to Effectiveness.
(a) Majority Banks. As to Sections 2.01(A)(i) and (iii), Sections 2.01(C), Section 2.04, Section 2.06 and Section 2.07 hereof, this instrument shall become effective as to such Sections (and the Loan Agreement shall be amended and restated in the form of the Loan Agreement immediately before giving effect hereto and with the amendments referred to in such Sections) as of the Closing Date when Administrative Agent shall have received a duly executed counterpart hereof signed by the Company and Majority Banks (or, in the case of any Bank included within Majority Banks as to which an executed counterpart shall not have been received, Administrative Agent shall have received telegraphic, telex or other written confirmation from such party of execution of a counterpart hereof by such Bank).
(b) All Banks. As to Sections 2.01(A)(ii) and (iv), Section 2.01(B),
Section 2.02, Section 2.03, Section 2.05, and Section 2.08 hereof, this
instrument shall become effective as to such Sections (and the Loan Agreement
shall be amended and restated in the form of the Loan Agreement immediately
before giving effect hereto and with the amendments referred to in such
Sections) as of the Closing Date when Administrative Agent shall have received a
duly executed counterpart hereof signed by the Company and all of the Banks (or,
in the case of any Bank as to which an executed counterpart shall not have been
received, Administrative Agent shall have received telegraphic, telex or other
written confirmation from such party of execution of a counterpart hereof by
such Bank).
3.02. Corporate General Certificate. The obligation of each Bank hereunder is subject to the condition precedent that, on the Closing Date, Administrative Agent shall have received a Corporate General Certificate for Company in the form attached hereto as Exhibit "A".
ARTICLE IV
Ratifications, Representations and Warranties
4.01. Ratifications. The terms and provisions set forth herein shall modify and supersede all inconsistent terms and provisions set forth in the Loan Agreement immediately before giving effect hereto and the other Loan Papers, and, except as expressly modified, amended, and superseded herein, the terms and provisions of the Loan Agreement and the other Loan Papers are ratified and confirmed and shall continue in full force and effect. Company and Banks agree that the Loan Agreement, as amended and restated in its entirety hereby, and the other Loan Papers shall continue to be legal, valid, binding and enforceable in accordance with their respective terms.
4.02. Representations, Warranties and Agreements. Company hereby
represents and warrants to Banks that (a) the execution, delivery and
performance of the Loan Agreement as amended and restated in its entirety hereby
has been authorized by all requisite corporate action on the part of Company and
will not violate the Articles/Certificate of Incorporation or Bylaws of Company;
(b) the representations and warranties contained in the Loan Agreement, as
amended and restated in its entirety hereby, and any other Loan Papers are true
and correct on and as of the date hereof and on and as of the date of execution
hereof as though made on and as of each such date; (c) no Default or Event of
Default under the Loan Agreement, as amended and restated in its entirety
hereby, has occurred and is continuing; and (d) Company is in full compliance
with all covenants and agreements contained in the Loan Agreement and the other
Loan Papers, as amended and restated in its entirety hereby.
ARTICLE V
Miscellaneous Provisions
5.01. Reference to Loan Agreement. The other Loan Papers, and any and all other agreements, documents or instruments now or hereafter executed and delivered pursuant to the terms hereof or pursuant to the terms of the Loan Agreement, as amended and restated in its entirety hereby, are hereby amended so that any reference in the Loan Agreement and such other Loan Papers to the Loan Agreement shall mean a reference to the Loan Agreement as amended and restated in its entirety hereby.
5.02. Expenses of Agents. As provided in the Loan Agreement, Company agrees to pay on demand all reasonable costs and expenses incurred by Agents in connection with the preparation, negotiation and execution of this Amended and Restated Revolving Credit Agreement, including, without limitation, the costs and fees of Agent's legal counsel, and all reasonable costs and expenses incurred by Banks in connection with the enforcement or preservation of any rights under the Loan Agreement, as amended and restated in its entirety hereby, or any other Loan Papers, including, without, limitation, the reasonable costs and fees of Agents' legal counsel. Company shall not be responsible for the cost or expense of legal counsel of any other Bank in connection with the preparation, execution and delivery of this Amendment.
5.03. Counterparts. This instrument may be executed in one or more counterparts, each of which when so executed shall be deemed to be an original, but all of which when taken together shall constitute one and the same instrument.
5.04. Headings. The headings, captions, and arrangements used herein are for convenience only and shall not affect the interpretation of this instrument.
5.05. Applicable Law. THE LOAN AGREEMENT AS AMENDED AND RESTATED IN ITS ENTIRETY HEREBY AND ALL OTHER LOAN PAPERS EXECUTED PURSUANT HERETO SHALL BE DEEMED TO HAVE BEEN MADE AND TO BE PERFORMABLE IN AND SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS UNLESS THE LAWS GOVERNING NATIONAL BANKS SHALL HAVE APPLICATION.
5.06. Final Agreement. THE LOAN AGREEMENT AS AMENDED AND RESTATED IN ITS ENTIRETY HEREBY AND THE OTHER LOAN PAPERS, EACH AS AMENDED HEREBY, REPRESENT THE ENTIRE EXPRESSION OF THE PARTIES WITH RESPECT TO THE SUBJECT MATTER HEREOF ON THE CLOSING DATE THIS AMENDMENT IS EXECUTED. THE LOAN AGREEMENT AS AMENDED AND RESTATED IN ITS ENTIRETY HEREBY AND THE OTHER LOAN PAPERS, AS AMENDED HEREBY, MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. NO MODIFICATION, RESCISSION, WAIVER, RELEASE OR AMENDMENT OF ANY PROVISION OF THE LOAN AGREEMENT OR THE OTHER LOANS PAPERS SHALL BE MADE, EXCEPT BY A WRITTEN AGREEMENT SIGNED BY COMPANY AND EITHER BANKS OR MAJORITY BANKS, AS PROVIDED IN THE LOAN AGREEMENT.
IN WITNESS WHEREOF, this Amendment has been executed in multiple originals and is effective as of the date first above-written.
[SIGNATURE PAGES TO FOLLOW]
COMPANY:
CROSS TIMBERS OIL COMPANY,
a Delaware corporation
BANKS:
MORGAN GUARANTY TRUST COMPANY
OF NEW YORK
NATIONSBANK, N.A.
CHASE BANK OF TEXAS, N.A.
BANKBOSTON, N.A.
WELLS FARGO BANK (TEXAS), N.A.
FROST NATIONAL BANK, as the surviving bank by merger of Overton Bank and Trust, N.A., effective May 29, 1998
ABN-AMRO BANK N.V.
BANK OF MONTREAL
THE BANK OF NEW YORK
BANQUE PARIBAS
CREDIT LYONNAIS NEW YORK BRANCH
BANK OF AMERICA NATIONAL TRUST AND SAVINGS
ASSOCIATION
FIRST UNION NATIONAL BANK
BANK ONE, TEXAS, N.A.
NATEXIS Banque
THE BANK OF NOVA SCOTIA
COMERICA BANK-TEXAS
EXHIBIT 12.1
CROSS TIMBERS OIL COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(in thousands)
Year Ended December 31,
-----------------------------------------------
1994 1995 1996 1997 1998
------- --------- ------- ------- ---------
Earnings (loss) available to common stock.. $ 3,048 $(10,538) $19,790 $23,905 $(71,498)
Income tax expense......................... 1,730 (5,825) 10,669 13,517 (35,851)
Interest and debt expense.................. 8,289 12,922 17,224 26,747 58,499
Interest portion of rentals (a)............ 519 637 1,830 3,044 3,727
Preferred stock dividends.................. - - 514 1,779 1,779
------- -------- ------- ------- --------
Earnings (loss) before provision for.......
taxes and fixed charges................... $13,586 $ (2,804) $50,027 $68,992 $(43,344)
======= ======== ======= ======= ========
Interest and debt expense.................. $ 8,289 $ 12,922 $17,224 $26,747 $ 58,499
Interest portion of rentals (a)............ 519 637 1,830 3,044 3,727
Preferred stock dividends.................. - - 514 1,779 1,779
------- -------- ------- ------- --------
Total Fixed Charges........................ $ 8,808 $ 13,559 $19,568 $31,570 $ 64,005
======= ======== ======= ======= ========
Ratio of Earnings to Fixed Charges......... 1.5 (0.2)(c) 2.6 2.2 (0.7)(b)
Excess of Fixed Charges over Earnings
(Loss).................................... $ - $ 16,363 $ - $ - $107,349
|
(a) Calculated as one-third of rentals.
(b) Negative ratio is the result of a $20,280,000 pre-tax, non-cash charge
recorded upon adoption of Statement of Financial Accounting Standards No.
121, Accounting for the Impairment of Long-Lived Assets to be Disposed Of.
Excluding the effect of this charge, the ratio of earnings to fixed charges
is 1.3.
(c) Negative ratio is the result of a $93.7 million pre-tax net loss on
investment in equity securities and a $2 million pre-tax, non-cash
impairment charge. Excluding the effects of these charges, the ratio of
earnings to fixed charges is 0.8.
EXHIBIT 21.1
SUBSIDIARIES OF CROSS TIMBERS OIL COMPANY
Jurisdiction of
Incorporation
---------------
Cross Timbers Operating Company Texas
Cross Timbers Energy Services, Inc. Texas
Cross Timbers Trading Company Texas
Ringwood Gathering Company Delaware
Timberland Gathering & Processing Company, Inc. Texas
WTW Properties, Inc. Texas
|
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. 2 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
March 16, 1999
EXHIBIT 23.5
[LETTERHEAD OF MILLER AND LENTS, LTD. APPEARS HERE]
March 16, 1999
Hugoton Royalty Trust
901 Main St., 17th Floor
Dallas, Texas 75202
Cross Timbers Oil Company
810 Houston Street, Suite 2000
Forth Worth, Texas 76102
Re: Securities and Exchange Commission
Form S-1 Registration Statement No. 333-68441
Gentlemen:
The firm of Miller and Lents, Ltd. consents to the incorporation of its estimated Proved Reserves, Future Net Revenues, and Present Values of Future Net Revenues for the Hugoton Royalty Trust and Cross Timbers Oil Company in their Form S-1 Registration Statement, No. 333-68441, and to references to our Firm in such registration statement.
Miller and Lents, Ltd. has no interests in Hugoton Royalty Trust or Cross Timbers Oil Company or any of its affiliated companies or subsidiaries and is not to receive any such interest as payment for such reports and has no director, officer, or employee, or otherwise, connected with Hugoton Royalty Trust or Cross Timbers Oil Company. We are not employed by Hugoton Royalty Trust or Cross Timbers Oil Company on a contingent basis.
Yours very truly,
MILLER AND LENTS, LTD.
By: /s/ James C. Pearson -------------------------------- James C. Pearson President |
| ARTICLE 5 |
| CIK: 0000868809 |
| NAME: CROSS TIMBERS OIL COMPANY |
| MULTIPLIER: 1,000 |
| PERIOD TYPE | 12 MOS |
| FISCAL YEAR END | DEC 31 1998 |
| PERIOD START | JAN 01 1998 |
| PERIOD END | DEC 31 1998 |
| CASH | 12,333 |
| SECURITIES | 44,386 |
| RECEIVABLES | 50,607 |
| ALLOWANCES | 0 |
| INVENTORY | 0 |
| CURRENT ASSETS | 137,578 |
| PP&E | 1,370,518 |
| DEPRECIATION | 319,507 |
| TOTAL ASSETS | 1,207,594 |
| CURRENT LIABILITIES | 99,588 |
| BONDS | 921,000 |
| PREFERRED MANDATORY | 0 |
| PREFERRED | 28,468 |
| COMMON | 541 |
| OTHER SE | 148,442 |
| TOTAL LIABILITY AND EQUITY | 1,207,594 |
| SALES | 249,486 |
| TOTAL REVENUES | 249,486 |
| CGS | 0 |
| TOTAL COSTS | 209,224 |
| OTHER EXPENSES | 93,719 |
| LOSS PROVISION | 0 |
| INTEREST EXPENSE | 52,113 |
| INCOME PRETAX | (105,570) |
| INCOME TAX | (35,851) |
| INCOME CONTINUING | (69,719) |
| DISCONTINUED | 0 |
| EXTRAORDINARY | 0 |
| CHANGES | 0 |
| NET INCOME | (71,498) |
| EPS PRIMARY | (1.65) |
| EPS DILUTED | (1.65) |