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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, Commission file number 1-10476
1999
Hugoton Royalty Trust
(Exact name of registrant as specified in the Hugoton Royalty Trust Indenture)
Texas 58-6379215
(I.R.S. Employer
(State or other jurisdiction of Identification No.)
incorporation or organization)
Bank of America, N.A. 75283-0650
(Zip Code)
Trustee
P.O. Box 830650
Dallas, Texas
(Address of principal executive
offices)
Registrant's telephone number including area code: (877) 228-5083
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which
registered
Units of Beneficial Interest New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
At March 1, 2000, there were 40,000,000 units of beneficial interest of the
trust outstanding. The aggregate market value of the units (based on the
closing price on the New York Stock Exchange on March 1, 2000) held by non-
affiliates of the registrant on that date was approximately $142.7 million.
DOCUMENTS INCORPORATED BY REFERENCE
Listed below is the only document parts of which are incorporated herein by
reference and the parts of this report into which the document is
incorporated:
1999 Annual Report to Unit Holders--Part II
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<PAGE>
PART I
Item 1. Business
Hugoton Royalty Trust is an express trust created under the laws of Texas
pursuant to the Hugoton Royalty Trust Indenture entered into on December 1,
1998 between Cross Timbers Oil Company, as grantor, and NationsBank, N.A., as
trustee. Bank of America, N.A., successor to NationsBank, N.A., is now the
trustee of the trust. The principal office of the trust is located at 901 Main
Street, Dallas, Texas 75202 (telephone number 877-228-5083).
Effective December 1, 1998, Cross Timbers conveyed to the trust 80% defined
net profits interests in certain predominantly natural gas producing working
interest properties in Kansas, Oklahoma and Wyoming under three separate
conveyances. In exchange for these net profits interest conveyances to the
trust, 40,000,000 units of beneficial interest were issued to Cross Timbers.
On April 8, 1999, Cross Timbers sold 15,000,000 units in the trust's initial
public offering. An additional 2,004,000 units were sold on May 7, 1999 by
Cross Timbers pursuant to the underwriters' overallotment option. The trust
did not receive any proceeds from the sale of trust units. As of March 1,
2000, Cross Timbers owned 22,922,316 units in the trust. Units are listed and
traded on the New York Stock Exchange under the symbol "HGT."
The net profits interests entitle the trust to receive 80% of net proceeds
from the sale of oil and gas from the underlying properties. Each month Cross
Timbers determines the amount of cash received from the sale of production and
deducts property and production taxes, development and production costs and
overhead. For trust distributions declared through March 2000, net proceeds
from the sale of gas related to those distributions are computed differently.
Net proceeds for this period are computed monthly based on the greater of
either a realized price of $2.00 per Mcf or the actual price received by Cross
Timbers for natural gas sold.
Net proceeds payable to the trust depend upon production quantities, sales
prices of oil and gas and costs to develop and produce the oil and gas. If at
any time production costs exceed gross proceeds for any conveyance, such
excess is carried forward to the computation of net proceeds for future months
until the excess costs (plus interest accrued as specified in the conveyances)
are completely recovered. Such excess costs from one conveyance cannot be used
to reduce net proceeds from another conveyance.
The trust is not liable for any production costs or liabilities attributable
to the net profits interests. If at any time the trust receives royalty income
in excess of the amount due, the trust is not obligated to return such
overpayment, but royalty income payable to the trust for the next month will
be reduced by the overpayment, plus interest at the prime rate.
To the extent it has the right to do so, Cross Timbers is responsible for
marketing its production from the underlying properties under existing sales
contracts or new arrangements on the best terms reasonably obtainable in the
circumstances. See Item 2., "Pricing and Sales Information."
Royalty income received by the trust on or before the last business day of
the month is related to net proceeds received by Cross Timbers in the
preceding month, and generally represents receipts attributable to oil and gas
production two months prior. The amount to be distributed to unitholders each
month by the trustee is determined by:
Adding--
(1) royalty income received,
(2) interest income and any other cash receipts and
(3) cash available as a result of reduction of cash reserves, then
Subtracting the sum of--
(1) liabilities paid and
(2) the reduction in cash available related to establishment of or
increase in any cash reserve.
The monthly distribution amount is distributed to unitholders of record
within ten business days after the monthly record date. The monthly record
date is generally the last business day of the month. The trustee
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calculates the monthly distribution amount and announces the distribution per
unit at least ten days prior to the monthly record date.
The trustee may establish cash reserves for contingencies. Cash held for
such reserves, as well as for pending payment of the monthly distribution
amount, may be invested in federal obligations or certificates of deposit of
major banks.
The trustee's function is to collect the royalty income from the net profits
interests, to pay all trust expenses, and pay the monthly distribution amount
to unitholders. The trustee's powers are specified by the terms of the trust
indenture. The trust cannot engage in any business activity or acquire any
assets other than the net profits interests and specific short-term cash
investments. The trust has no employees since all administrative functions are
performed by the trustee.
Approximately 90% of the royalty income received by the trust during 1999,
as well as 91% of the estimated proved reserves of the net profits interests
at December 31, 1999 (based on the discounted present value using year-end oil
and gas prices), is attributable to natural gas. There has historically been a
greater demand for gas during the winter months than the rest of the year.
Otherwise, trust income generally is not subject to seasonal factors, nor
dependent upon patents, licenses, franchises or concessions. The trust
conducts no research activities.
Item 2. Properties
The net profits interests are the principal asset of the trust. The trustee
cannot acquire any other assets, with the exception of certain short-term
investments as specified under Item 1. The trustee may sell or otherwise
dispose of all or any part of the net profits interests if approved by at
least 80% of the unitholders, or upon termination of the trust. Otherwise, the
trust may only sell up to 1% of the value of the net profits interests in any
calendar year, pursuant to notice from Cross Timbers of its desire to sell the
related underlying properties. Any such sale must be for cash with the
proceeds promptly distributed to the unitholders. The underlying properties
are predominantly natural gas producing leases located in the states of
Kansas, Oklahoma and Wyoming. The principal productive areas are the Hugoton
area, Anadarko Basin and Green River Basin.
Hugoton Area
Natural gas was discovered in the Hugoton area in 1922. With an estimated
five million productive acres covering parts of Texas, Oklahoma and Kansas,
the Hugoton area is the largest natural gas producing area in North America.
More than 64 trillion cubic feet of natural gas have been produced from the
Hugoton area.
The Permian-aged Chase formation is the major productive formation in the
Hugoton area, ranging in depth from 2,700 to 2,900 feet. Additional productive
formations in the Hugoton area include the Council Grove between 2,950 and
3,400 feet, the Morrow between 6,000 and 6,300 feet, the Chester between 6,350
and 6,700 feet and the St. Louis between 7,500 and 8,000 feet. Cross Timbers
is actively exploring and developing these formations on the underlying
properties.
Sales volumes from the underlying properties in the Hugoton area averaged
approximately 34,300 Mcf of natural gas per day and 55 Bbls of oil per day.
Cross Timbers delivers most of its Hugoton natural gas production to a
gathering and processing system operated by a subsidiary. This system collects
approximately 74% of its throughput from underlying properties, which, in
recent months, has been approximately 26,000 Mcf per day from 243 wells. The
gathering subsidiary purchases the gas from Cross Timbers at the wellhead,
gathers and transports the gas to its plant, and treats and processes the gas
at the plant. The gathering subsidiary pays Cross Timbers for wellhead volumes
at a price of 80% to 85% of the residue price received upon sale to Cross
Timbers' marketing affiliate. Cross Timbers does not pay the gathering
subsidiary for fuel, gathering or compression. Under long-term contracts, the
gathering subsidiary sells residue volumes to Cross Timbers' marketing
affiliate at a price equal to the average price of several published indices
and is reduced by any pipeline access fees incurred by the marketing
affiliate, but is not reduced by any marketing fees. Pipeline access fees
currently are approximately $0.02 per Mcf.
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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 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
. drilling deeper in existing wells to new producing zones.
Cross Timbers plans to develop the Chase formation primarily through infill
drilling of up to 35 wells in Kansas. In June 1999, Oklahoma regulations were
amended to allow increased drilling density in the Oklahoma panhandle where
Cross Timbers has approximately 200 infill well locations on the underlying
properties. 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. Test wells
were drilled to delineate the Council Grove formation in 1999 and further test
wells are planned for 2000.
Cross Timbers drilled 5 gross (4 net) wells in 1999 to the Chester, Council
Grove and Chase formations, all of which were successfully completed. Cross
Timbers plans to drill up to three wells and perform up to 24 workovers in the
Hugoton area during 2000.
Anadarko Basin
Major County Area. Cross Timbers is one of the largest producers in the
Ringwood, Northwest Okeene and Cheyenne Valley fields in Major County,
Oklahoma. Average 1999 net daily sales volumes from the underlying properties
were 30,800 Mcf of gas and 865 Bbls of oil.
Oil and natural gas were 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, Inola,
Chester, Manning, Mississippian, Hunton and Arbuckle formations.
A gathering subsidiary of Cross Timbers 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 gas to a third-party
processor, which processes the gas and pays Cross Timbers and other producers
for at least 50% of the liquids processed. After the gas is processed, the
gathering subsidiary transports the gas via a 26-mile pipeline to a connection
with other pipelines. The gathering subsidiary sells the residue 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 $0.313 per Mcf of residue gas. This gathering fee was
previously approved by the Federal Energy Regulatory Commission when the
gathering subsidiary was regulated. During 1999, the gathering system
collected approximately 21,000 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 $0.125
per Mcf.
Cross Timbers also sells natural gas to its marketing subsidiary, which then
sells the 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.
3
<PAGE>
Cross Timbers plans to develop the Major County area primarily through:
. mechanical stimulation of existing wells;
. opening new producing zones in existing wells;
. deepening existing wells to new producing zones; and
. drilling additional wells.
Cross Timbers drilled 8 gross (5.5 net) wells in 1999 in the northwest
portion of Major County, targeting the Chester, Inola, Oswego and Red Fork
formations. All of these wells were successfully completed. Cross Timbers
plans to drill up to 13 wells and perform up to 42 workovers in the Major
County area during 2000.
Elk City Field. The Elk City Field is located in Beckham and Washita
counties of Western Oklahoma. Average 1999 sales volumes from the underlying
properties in the Elk City Field were approximately 3,900 Mcf of gas and 138
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 and plans to drill one
well to the Hoxbar formation in 2000.
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 less pipeline
access fees.
Green River Basin
The Green River Basin is located in southwestern Wyoming. Cross Timbers'
1999 average daily sales volumes from the underlying properties in the
Fontenelle field were approximately 27,600 Mcf of natural gas and 59 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 gas sold, Cross Timbers compresses the gas on
the lease, transports it off the lease and compresses the gas again prior to
entry into the gas plant pipeline. The pipeline transports the gas 35 miles to
the gas plant, where the gas is processed, then redelivered to Cross Timbers
and sold to Cross Timbers' marketing subsidiary. The owner of the gas plant
and related pipeline charges Cross Timbers for operational fuel and
processing. In 1999, the fuel charge was 0.5% of the volumes produced and the
processing fee was $0.05 per MMBtu. The marketing subsidiary then sells the
residue gas to third parties based upon a spot sales price and pays the net
sales proceeds to Cross Timbers. The marketing subsidiary does not receive a
marketing fee. Condensate is sold at the lease to an independent third party
at market rates. The gas not sold under the above arrangement is sold either
under a similar arrangement where the fee is $0.145 per MMBtu, or under a
contract where Cross Timbers directly sells the gas to a third party on the
lease at an adjusted index price.
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,
4
<PAGE>
. deepening existing wells to new producing zones, and
. drilling additional wells.
Cross Timbers drilled 7 gross (6.9 net) wells in the Fontenelle Unit in
1999, all of which were successfully completed. Cross Timbers plans to drill
up to five wells and perform up to five workovers in the Green River Basin
during 2000.
Producing Acreage and Well Counts
For the following data, "gross" refers to the total wells or acres on the
underlying properties 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 gas, a well is categorized as an oil well or a gas well based upon the
ratio of oil to natural gas production.
The underlying properties are interests in developed properties located
primarily in 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, 1999. Undeveloped acreage is not significant.
<TABLE>
<CAPTION>
Gross Net
-------- --------
<S> <C> <C>
Hugoton Area............................................. 217,590 200,390
Anadarko Basin........................................... 152,042 113,946
Green River Basin........................................ 42,654 28,841
-------- --------
Total.................................................... 412,286 343,177
======== ========
</TABLE>
The following is a summary of the producing wells on the underlying
properties as of December 31, 1999:
<TABLE>
<CAPTION>
Operated Non-Operated
Wells Wells Total
-------------- ------------- ---------------
Gross Net Gross Net Gross Net
------ ------- ------------- ------ --------
<S> <C> <C> <C> <C> <C> <C>
Gas........................... 1,025 933.8 257 59.8 1,282 993.6
Oil........................... 133 119.7 6 1.1 139 120.8
------ ------- ----- ------ ------ --------
Total......................... 1,158 1,053.5 263 60.9 1,421 1,114.4
====== ======= ===== ====== ====== ========
</TABLE>
There were five (2.1 net) wells in process of drilling at December 31, 1999.
The following is a summary of the number of wells drilled on the underlying
properties during the year ended December 31, 1999. Unless otherwise
indicated, all wells drilled are developmental.
<TABLE>
<CAPTION>
Gross Net
----- ----
<S> <C> <C>
Completed gas wells (a)......................................... 40 32.5
Non-productive--exploratory..................................... 1 1.0
--- ----
Total........................................................... 41 33.5
=== ====
</TABLE>
- --------
(a) Included in completed gas wells are 7 gross (1.1 net) wells drilled on
nonoperated interests.
Oil and Gas Production
Trust production is recognized in the period royalty income is received,
which is the month following receipt by Cross Timbers, and generally two
months after the time of production. Because of this two-month interval, the
trust's initial accounting year ended December 31, 1999 includes royalty
income related to eleven
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months of oil and gas sales, or December 1998 (the trust's initial month)
through October 1999 production. Oil and gas production and average sales
prices attributable to the underlying properties and the net profits interests
for the year ended December 31, 1999 were as follows:
<TABLE>
<CAPTION>
Production
<S> <C>
Underlying Properties
Gas--Sales (Mcf)............................................. 34,188,398
Average per day (Mcf)....................................... 102,055
Oil--Sales (Bbls)............................................ 388,038
Average per day (Bbls)...................................... 1,158
Net Profits Interests
Gas--Sales (Mcf)............................................. 15,583,364
Average per day (Mcf)....................................... 46,518
Oil--Sales (Bbls)............................................ 190,668
Average per day (Bbls)...................................... 569
Average Sales Price
Gas (per Mcf)................................................ $ 2.12
Oil (per Bbl)................................................ $ 16.53
</TABLE>
Oil and Natural Gas Reserves
General
The following are definitions adopted by the Securities and Exchange
Commission and the Financial Accounting Standards Board which are applicable
to terms used in the following discussion of oil and natural gas reserves:
Proved reserves--Estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geologic and engineering data,
appear with reasonable certainty to be recoverable in the future from known
oil and gas reservoirs under existing economic and operating conditions.
Proved developed reserves--Proved reserves which can be expected to be
recovered through existing wells with existing equipment and operating
methods.
Proved undeveloped reserves-- Proved reserves which are expected to be
recovered from new wells on undrilled acreage, or from existing wells where
a relatively major expenditure is required.
Estimated future net revenues--Also referred to herein as "estimated
future net cash flows." Computational result of applying current prices of
oil and gas (with consideration of price changes only to the extent
provided by existing contractual arrangements) to estimated future
production from proved oil and gas reserves as of the date of the latest
balance sheet presented, less estimated future expenditures (based on
current costs) to be incurred in developing and producing the proved
reserves. Estimated future net revenues do not include the effects of the
tight sands tax credit, since the trust is not a taxable entity and the
credit inures directly to the benefit of the unitholder.
Present value of estimated future net revenues--Also referred to herein
as "standardized measure of discounted future net cash flows" or
"standardized measure." Computational result of discounting estimated
future net revenues at a rate of 10% annually.
Miller and Lents, Ltd., independent petroleum engineers, has estimated oil
and gas reserves attributable to the underlying properties and net profits
interests as of December 31, 1999 and 1998. Numerous uncertainties are
inherent in estimating reserve volumes and values, and such estimates are
subject to change as additional information becomes available. The reserves
actually recovered and the timing of production of these reserves may be
substantially different from the original estimates.
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Reserve quantities and revenues for the net profits interests were estimated
from projections of reserves and revenues attributable to the combined
interests of the trust and Cross Timbers in the subject properties. Since the
trust has defined net profits interests, the trust does not own a specific
ownership percentage of the oil and gas reserve quantities. Accordingly,
reserves allocated to the trust pertaining to its 80% net profits interest in
the properties have effectively been reduced to reflect recovery of the
trust's 80% portion of applicable production and development costs, excluding
overhead. Because trust reserve quantities are determined using an allocation
formula, any fluctuations in actual or assumed prices or costs will result in
revisions to the estimated reserve quantities allocated to the net profits
interests.
The standardized measure of discounted future net cash flows and changes in
such discounted cash flows as presented below are prepared using assumptions
required by the Financial Accounting Standards Board. These assumptions
include the use of year-end prices for oil and gas and year-end costs for
estimated future development and production expenditures to produce the proved
reserves. Because natural gas prices are influenced by seasonal demand, use of
year-end prices, as required by the Financial Accounting Standards Board, may
not be the most representative in estimating future revenues or reserve data.
Future net cash flows are discounted at an annual rate of 10%. No provision is
included for federal income taxes since future net revenues are not subject to
taxation at the trust level.
Year-end oil prices used to determine the standardized measure were based on
a West Texas Intermediate crude oil posted price of $22.75 per Bbl in 1999 and
$9.50 per Bbl in 1998. The year-end weighted average realized gas prices used
to determine the standardized measure were $2.23 per Mcf in 1999 and $2.01 per
Mcf in 1998.
Proved Reserves
The following table reconciles the change in proved reserves attributable to
the underlying properties and net profits interests for the year ended
December 31, 1999 (in thousands):
<TABLE>
<CAPTION>
Underlying Net Profits
Properties Interests
---------------- ----------------
Gas Oil Gas Oil
(Mcf) (Bbls) (Mcf) (Bbls)
-------- ------ -------- ------
<S> <C> <C> <C> <C>
Balance, December 31, 1998.............. 515,073 4,030 282,297 2,193
Extensions, discoveries and other
additions............................ 28,262 89 16,173 51
Revisions of prior estimates.......... (3,778) 540 5,034 358
Production--sales volumes............. (34,188) (388) (15,583) (191)
-------- ------ -------- ------
Balance, December 31, 1999.............. 505,369 4,271 287,921 2,411
======== ====== ======== ======
</TABLE>
Extensions, discoveries and additions are primarily related to delineation
of additional proved undeveloped reserves in the Anadarko Basin during 1999.
Upward revisions of prior estimates of proved gas reserves of the net profits
interests as compared with downward revisions of the underlying properties
were caused by higher year-end 1999 gas prices which resulted in increased gas
reserves allocated to the trust.
Proved Developed Reserves
The following are estimated quantities of proved developed reserves
attributable to the underlying properties and net profits interests as of
December 31, 1998 and 1999 (in thousands):
<TABLE>
<CAPTION>
Underlying Net Profits
Properties Interests
--------------- ---------------
Gas Oil Gas Oil
(Mcf) (Bbls) (Mcf) (Bbls)
-------- ------ -------- ------
<S> <C> <C> <C> <C>
December 31, 1998............................. 435,328 3,368 249,215 1,934
======== ====== ======== ======
December 31, 1999............................. 431,399 3,595 253,567 2,105
======== ====== ======== ======
</TABLE>
7
<PAGE>
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
The following are summary calculations of the standardized measure of
discounted future net cash flows attributable to the underlying properties and
net profits interests as of December 31, 1999 and 1998 (in thousands):
<TABLE>
<CAPTION>
December 31
Underlying Properties ---------------------
1999 1998
---------- ----------
<S> <C> <C>
Future cash inflows................................. $1,240,476 $1,087,660
Future costs:
Production........................................ 388,923 364,930
Development....................................... 48,861 48,212
---------- ----------
Future net cash flows............................... 802,692 674,518
10% discount factor................................. 393,924 327,341
---------- ----------
Standardized measure................................ $ 408,768 $ 347,177
========== ==========
<CAPTION>
December 31
Net Profits Interests ---------------------
1999 1998
---------- ----------
<S> <C> <C>
Future cash inflows................................. $ 707,067 $ 595,301
Future production taxes............................. 64,913 55,686
---------- ----------
Future net cash flows............................... 642,154 539,615
10% discount factor................................. 315,140 261,873
---------- ----------
Standardized measure................................ $ 327,014 $ 277,742
========== ==========
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows from
Proved Reserves
The following summarizes the changes in the standardized measure during 1999
for the net profits interests (in thousands):
<TABLE>
<S> <C>
Standardized measure, January 1.................................. $277,742
Extensions, discoveries and other additions..................... 13,333
Accretion of discount........................................... 25,459
Revisions of prior estimates, changes in price and other........ 43,620
Royalty income.................................................. (33,140)
--------
Standardized measure, December 31................................ $327,014
========
</TABLE>
Regulation
Natural Gas Regulation
The interstate transportation and sale for resale of natural gas is subject
to federal regulation, including transportation rates charged, storage tariffs
and various other matters, by the Federal Energy Regulatory Commission.
Federal price controls on wellhead sales of domestic natural gas terminated on
January 1, 1993. While natural gas prices are currently unregulated, Congress
historically has been active in the area of natural gas regulation. It is
impossible to predict whether new legislation to regulate natural gas might be
proposed, what proposals, if any, might actually be enacted, and what effect,
if any, such proposals might have on the operations of the underlying
properties.
Environmental Regulation
Companies that are engaged in the oil and gas industry are affected by
federal, state and local laws regulating the discharge of materials into the
environment. Those laws may impact operations of the underlying
8
<PAGE>
properties. No material expenses have been incurred on the underlying
properties in complying with environmental laws and regulations. Cross Timbers
does not expect that future compliance will have a material adverse effect on
the trust.
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. The rates of production may be regulated
and the maximum daily production allowables from both oil and gas wells may be
established on a market demand or conservation basis, or both.
Other Regulation
The Minerals Management Service of the United States Department of the
Interior is evaluating existing methods of settling royalties on federal and
Native American oil and gas leases. Seven percent of the net acres of the
underlying properties, primarily 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, Cross Timbers' management does not believe that
the proposed rule changes will have a significant detrimental effect on trust
distributions.
Tight Sands Tax Credit
The trust receives royalty income from tight sands wells, certain production
from which qualifies for the federal income tax credit for producing
nonconventional fuels under Section 29 of the Internal Revenue Code. The
Section 29 tax credit is available for tight sands gas produced and sold
through 2002 from wells drilled prior to January 1, 1993 and after November 5,
1990, or after December 31, 1979 if the related formation was dedicated to
interstate commerce as of April 20, 1977. This tax credit is approximately
$0.52 per MMBtu. Such credit, calculated based on the unitholder's pro rata
share of qualifying production, may not reduce the unitholder's regular tax
liability (after the foreign tax credit and certain other nonrefundable
credits) below his tentative minimum tax. Any part of the Section 29 credit
not allowed for the tax year solely because of this limitation is subject to
certain carryover provisions.
Pricing and Sales Information
A subsidiary of Cross Timbers markets Cross Timbers' natural gas production,
and the natural gas is sold on a monthly basis to third parties for the best
available price. 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
is marketed under contracts existing at trust inception. Contracts covering
production from the Major County area are generally 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 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 with
Cross Timbers' 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 parties. The sales price is net of any deductions for
transportation from the wellhead to the unaffiliated parties and any gravity
or quality adjustments.
Item 3. Legal Proceedings
Cross Timbers 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
Cross Timbers.
9
<PAGE>
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 and selling natural gas through affiliated
companies at prices less favorable than those paid by third parties. The
plaintiffs are seeking an accounting and payment of the monies allegedly owed
to them. A hearing on the class certification has not been scheduled. Cross
Timbers believes that it has strong defenses to this lawsuit and intends to
vigorously defend its position. However, if Cross Timbers ultimately makes any
settlement payments, the trust will bear its 80% share of such settlement
related to production from the underlying properties for periods since
December 1, 1998. Additionally, if a judgment or settlement increases the
amount of future payments to royalty owners, the trust would bear its
proportionate share of the increased payments through reduced net proceeds.
The amount of any reduction in net proceeds is not presently determinable,
but, in Cross Timbers management's opinion, is not currently expected to be
material to the trust's annual 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 Cross Timbers underpaid
royalties on natural gas produced from federal leases and lands owned by
Native Americans by at least 20% during the past 10 years as a result of
mismeasuring the volume of natural gas and wrongfully analyzing its heating
content. The suit, which was brought under the qui tam provisions of the U.S.
False Claims Act, seeks treble damages for the unpaid royalties (with
interest), civil penalties between $5,000 and $10,000 for each violation of
the U.S. False Claims Act, and an order for Cross Timbers to cease the
allegedly improper measuring practices. The plaintiff has made similar
allegations in over 70 actions filed against over 300 other companies. After
its review, the U. S. Department of Justice decided in April 1999 not to
intervene, and the court unsealed the case in May 1999. A federal multi-
district litigation panel has ordered that most of the suits filed by
Grynberg, including the case against Cross Timbers, be transferred and
consolidated to the federal district court in Wyoming. Cross Timbers and other
defendants have filed a motion to dismiss the lawsuit. Cross Timbers believes
that the allegations of this lawsuit are without merit and intends to
vigorously defend the action. 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 Cross Timbers management's opinion, is not expected to be material to the
trust's annual distributable income, financial position or liquidity.
Certain of the trust properties are involved in various other lawsuits and
certain governmental proceedings arising in the ordinary course of business.
Cross Timbers has advised the trustee that it does not believe that the
ultimate resolution of these claims will have a material effect on the trust's
annual distributable income, financial position or liquidity.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of unitholders during 1999.
10
<PAGE>
PART II
Item 5. Market for Units of the Trust and Related Security Holder Matters
The section entitled "Units of Beneficial Interest" on page 1 of the trust's
Annual Report to unitholders for the year ended December 31, 1999 is
incorporated herein by reference.
Item 6. Selected Financial Data
<TABLE>
<CAPTION>
Year Ended
December 31, 1999
-----------------
<S> <C>
Royalty Income.............................................. $ 33,139,662
Distributable Income........................................ 33,090,049
Distributable Income per Unit............................... 0.827253
Distributions per Unit...................................... 0.827253
Total Assets at Year-End.................................... 237,980,449
</TABLE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The "Trustee's Discussion and Analysis" of financial condition and results
of operations for the year ended December 31, 1999 on pages 5, 6 and 7 of the
trust's Annual Report to unitholders for the year ended December 31, 1999 is
incorporated herein by reference.
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 could have material adverse effects on
companies and organizations that rely upon those systems.
The trust's timely receipt of royalty income and disbursement of
distributable income to unitholders is largely dependent upon performance of
computer systems and computer-controlled equipment of Cross Timbers,
ChaseMellon Shareholder Services, L.L.C. and other third parties, including
oil and natural gas purchasers and significant service providers such as
electric utility companies and natural gas plant, pipeline and gathering
system operators. Since the trust does not use the trustee's computer systems
in any significant capacity, the trustee's Year 2000 compliance does not
materially affect the trust.
Cross Timbers completed remediation and testing of its significant computer
systems and computer-controlled field equipment in December 1999. No costs of
such modifications were incurred by the trust. Cross Timbers has not
experienced any material Year 2000 system failures, and does not foresee any
material system failures in the coming months. Cross Timbers also identified
significant third parties whose Year 2000 compliance could affect Cross
Timbers and formally inquired about their Year 2000 status. The trustee and
Cross Timbers are not aware of any significant third parties who experienced
material Year 2000 system failures. Despite their efforts to assure that such
third parties are Year 2000 compliant, neither the trustee nor Cross Timbers
can provide assurance that significant third parties will not experience
material Year 2000 system failures in the coming months. Such failures could
have a material adverse impact on timely trust distributions to unitholders.
Although the potential effect of Year 2000 noncompliance by third parties is
unknown, Cross Timbers has developed contingency plans in the event of
potential problems resulting from related system failures.
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
The only assets of and sources of income to the trust are the net profits
interests, which generally entitle the trust to receive a share of the net
profits from oil and gas production from the underlying properties.
11
<PAGE>
Consequently, the trust is exposed to market risk from fluctuations in oil and
gas prices. The trust is a passive entity and, other than the trust's ability
to periodically borrow money as necessary to pay expenses, liabilities and
obligations of the trust that cannot be paid out of cash held by the trust,
the trust is prohibited from engaging in borrowing transactions. The amount of
any such borrowings is unlikely to be material to the trust. In addition, the
trustee is prohibited by the trust indenture from engaging in any business
activity or causing the trust to enter into any investments other than
investing cash on hand in specific short-term cash investments. Therefore, the
trust cannot hold any derivative financial instruments. As a result of the
limited nature of the trust's borrowing and investing activities, the trust is
not subject to any material interest rate market risk. Additionally, any gains
or losses from any hedging activities conducted by Cross Timbers are
specifically excluded from the calculation of net proceeds due the trust under
the forms of the conveyances. The trust does not engage in transactions in
foreign currencies which could expose the trust to any foreign currency
related market risk.
Item 8. Financial Statements and Supplementary Data
The financial statements of the trust and the notes thereto, together with
the report thereon of Arthur Andersen LLP dated March 1, 2000, appearing on
pages 8 through 12 of the trust's Annual Report to unitholders for the year
ended December 31, 1999 are incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
There have been no changes in accountants or disagreements with accountants
on any matter of accounting principles or practices or financial statement
disclosures during the year ended December 31, 1999.
PART III
Item 10. Directors and Executive Officers of the Registrant
The trust has no directors or executive officers. The trustee is a corporate
trustee which may be removed, with or without cause, by the affirmative vote
of the holders of a majority of all the units then outstanding.
Item 11. Executive Compensation
The trustee received the following annual compensation in 1999 as specified
in the trust indenture:
<TABLE>
<CAPTION>
Other Annual
Name and Principal Position Compensation (1)
--------------------------- ----------------
<S> <C>
Bank of America, N.A., Trustee $29,333
</TABLE>
- --------
(1) Under the trust indenture, the trustee is entitled to an administrative
fee of $35,000 per year, paid in equal monthly installments. Such fee is
adjusted annually based on an oil and gas industry index. Upon termination
of the trust, the trustee is entitled to a termination fee of $15,000.
Item 12. Security Ownership of Certain Beneficial Owners and Management
(a) Security Ownership of Certain Beneficial Owners. The following table
sets forth as of March 1, 2000 information with respect to each person known
to the trustee to beneficially own more than 5% of the outstanding units of
the trust:
<TABLE>
<CAPTION>
Amount and Nature of Percent
Name and Address Beneficial Ownership of Class
---------------- -------------------- --------
<S> <C> <C>
Cross Timbers Oil Company 22,922,316 Units (1) 57.3%
810 Houston Street, Suite 2000
Fort Worth, TX 76102
</TABLE>
- --------
(1) Cross Timbers has the sole power to vote and dispose of all 22,922,316
units.
12
<PAGE>
(b) Security Ownership of Management. The trust has no directors or
executive officers. As of March 1, 2000, Bank of America, N.A. owned, in
various fiduciary capacities, an aggregate of 21,000 units without the right
to vote any of these units. Bank of America, N.A. disclaims any beneficial
interests in these units. The number of units reflected in this paragraph
includes units held by all branches of Bank of America, N.A.
(c) Changes in Control. The trustee knows of no arrangements which may
subsequently result in a change in control of the trust.
Item 13. Certain Relationships and Related Transactions
In computing royalty income paid to the trust for the net profits interests,
Cross Timbers deducts an overhead charge for reimbursement of administrative
expenses on the underlying properties it operates. This charge at December 31,
1999 was approximately $580,000 per month, or $6,960,000 annually (net to the
trust of $464,000 per month or $5,568,000 annually), and is subject to annual
adjustment based on an oil and gas industry index.
Cross Timbers sells a significant portion of natural gas production from the
underlying properties to certain of its wholly owned subsidiaries under
contracts in existence when the trust was created, generally at amounts
approximating monthly spot market prices. For further information, see Item 2.
"Hugoton Area," "Anadarko Basin," "Green River Basin" and "Pricing and Sales
Information."
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) The following documents are filed as a part of this report:
1.Financial Statements (incorporated by reference in Item 8 of this report)
Report of Independent Public Accountants
Statements of Assets, Liabilities and Trust Corpus at December 31, 1999
and 1998
Statement of Distributable Income for the year ended December 31, 1999
Statement of Changes in Trust Corpus for the year ended December 31,
1999
Notes to Financial Statements
2.Financial Statement Schedules
Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required
information is given in the financial statements or notes thereto.
3.Exhibits
<TABLE>
<C> <S>
(4) (a) Hugoton Royalty Trust Indenture by and between NationsBank,
N.A. (now Bank of America, N.A.), as trustee, and Cross Timbers
Oil Company heretofore filed as Exhibit 4.1 to the trust's
Registration Statement No. 333-68441 on Form S-1 filed with the
Securities and Exchange Commission on December 4, 1998, is
incorporated herein by reference.
(b) Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%--
Kansas) as amended and restated from Cross Timbers Oil Company
to NationsBank, N.A. (now Bank of America, N.A.), as trustee,
and Cross Timbers Oil Company dated December 1, 1998,
heretofore filed as Exhibit 10.1.1 to the trust's Registration
Statement No. 333-68441 on Form S-1 filed with the Securities
and Exchange Commission on March 16, 1999, is incorporated
herein by reference.
(c) Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%--
Oklahoma) as amended and restated from Cross Timbers Oil
Company to NationsBank, N.A. (now Bank of America, N.A.), as
trustee, and Cross Timbers Oil Company dated December 1, 1998,
heretofore filed as Exhibit 10.1.1 to the trust's Registration
Statement No. 333-68441 on Form S-1 filed with the Securities
and Exchange Commission on March 16, 1999, is incorporated
herein by reference.
</TABLE>
13
<PAGE>
<TABLE>
<C> <S>
(d) Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80%--
Wyoming) as amended and restated from Cross Timbers Oil Company
to NationsBank, N.A. (now Bank of America, N.A.), as trustee,
and Cross Timbers Oil Company dated December 1, 1998, heretofore
filed as Exhibit 10.1.1 to the trust's Registration Statement
No. 333-68441 on Form S-1 filed with the Securities and Exchange
Commission on March 16, 1999, is incorporated herein by
reference.
(13) Hugoton Royalty Trust Annual Report to unitholders for the year
ended December 31, 1999.
(23.1) Consent of Arthur Andersen LLP
(23.2) Consent of Miller and Lents, Ltd.
</TABLE>
Copies of the above Exhibits are available to any unitholder, at the
actual cost of reproduction, upon written request to the trustee, Bank of
America, N.A., P.O. Box 830650, Dallas, Texas 75283-0650.
(b) Reports on Form 8-K
During the last quarter of the trust's fiscal year ended December 31, 1999,
there were no reports filed on Form 8-K by the trust with the Securities and
Exchange Commission.
14
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed
on its behalf by the undersigned thereunto duly authorized.
HUGOTON ROYALTY TRUST
By BANK OF AMERICA, N.A., TRUSTEE
RON E. HOOPER
By: _________________________________
Ron E. Hooper
Vice President
CROSS TIMBERS OIL COMPANY
LOUIS G. BALDWIN
Date: March 30, 2000 By: _________________________________
Louis G. Baldwin
Executive Vice President and
Chief Financial Officer
(The Trust has no directors or executive officers.)
15
<PAGE>
HUGOTON ROYALTY TRUST
- -------------------------------------------------------------------------------
GLOSSARY OF TERMS
- -----------------
The following are definitions of significant terms used in this Annual Report:
Bbl Barrel (of oil)
Bcf Billion cubic feet (of natural gas)
Mcf Thousand cubic feet (of natural gas)
Mcfe Thousand cubic feet (of natural gas) equivalent,
computed with one barrel of oil as the energy
equivalent of six Mcf of natural gas
MMBtu One million British Thermal Units, a common energy
measurement
net profits interest An interest in an oil and gas property measured by net
profits from the sale of production, rather than a
specific portion of production
net proceeds Gross proceeds received by Cross Timbers from sale of
production from the underlying properties, less
applicable costs
royalty income Net proceeds, multiplied by the net profits percentage
of 80%, that is paid to the trust
underlying properties Cross Timbers' interest in certain oil and gas
properties from which the net profits interests were
carved. The underlying properties include working
interests in predominantly gas-producing properties
located in Kansas, Oklahoma and Wyoming.
working interest An operating interest in an oil and gas property that
provides the owner a specified share of production
that is subject to all production and development
costs
i
<PAGE>
THE TRUST
- -------------------------------------------------------------------------------
Hugoton Royalty Trust was created on December 1, 1998. Effective on that date,
80% net profits interests in certain predominantly gas-producing properties
located in Kansas, Oklahoma and Wyoming were conveyed to the trust by Cross
Timbers Oil Company, which currently owns the underlying properties. The net
profits interests are the only assets of the trust, other than cash held for
payment of liabilities and for distribution to unitholders.
Royalty income received by the trust on the last business day of each month is
calculated and paid by Cross Timbers based on net proceeds received from the
underlying properties in the prior month. Distributions, as calculated by the
trustee, are paid to month-end unitholders of record within ten business days.
UNITS OF BENEFICIAL INTEREST
- -------------------------------------------------------------------------------
The units of beneficial interest in the trust began trading on the New York
Stock Exchange on April 9, 1999 under the symbol "HGT." The following are the
high and low unit sales prices and total cash distributions per unit paid by the
trust during each quarter of 1999:
<TABLE>
<CAPTION>
Sales Price
------------------- Distributions
High Low per Unit
----------- ------ ---------
<S> <C> <C> <C>
Quarter
- ----------------
First....................... - - $0.089052
Second...................... $10.875 $9.500 0.220838
Third....................... 10.688 9.563 0.213208
Fourth...................... 10.375 7.500 0.304155
---------
$0.827253
=========
</TABLE>
At December 31, 1999, there were 40,000,000 units outstanding and approximately
48 unitholders of record; 16,649,550 of these units were held by a depository
institution. As of March 1, 2000, Cross Timbers owned 22,922,316 units.
Forward Looking Statements
This Annual Report, including the accompanying Form 10-K, includes "forward
looking statements" within the meaning of Section 27A of the Securities Act of
1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements other than statements of historical fact included in
this Annual Report and Form 10-K, including, without limitation, statements
regarding estimates of proved reserves, future development plans and costs, and
industry and market conditions, are forward looking statements. Although Cross
Timbers believes that the expectations reflected in such forward looking
statements are reasonable, neither Cross Timbers nor the trustee can give any
assurance that such expectations will prove to be correct.
1
<PAGE>
SUMMARY
- -------------------------------------------------------------------------------
The trust was created to collect and distribute to unitholders monthly royalty
income related to the 80% net profits interests. Such royalty income is
calculated as 80% of the net proceeds received from certain working interests in
predominantly gas-producing properties in Kansas, Oklahoma and Wyoming. Net
proceeds from these properties are calculated by deducting production and
development costs. If costs exceed revenues from the underlying properties in
any state, the net profits interests for that state will not contribute to
royalty income until all excess costs and accrued interest have been recovered
from future net proceeds of that state. However, such excess costs will not
reduce royalty income from the other states. Excess costs generally can occur
during periods of higher development activity and lower gas prices.
Unitholders may be eligible to receive the following tax benefits, but should
consult their tax advisors:
- The Nonconventional Fuel Source Tax Credit is related to tight sands gas
production sold through 2002 from wells drilled on the underlying
properties prior to January 1, 1993, and after November 5, 1990, or after
December 31, 1979 if the related formation was dedicated to interstate
commerce as of April 20, 1977. This tax credit may be used to reduce the
unitholder's regular income tax liability, but not below the unitholder's
tentative minimum tax.
- Cost Depletion is generally available to unitholders as a deduction from
royalty income. Available depletion is dependent upon the unitholder's
cost of units, purchase date and prior allowable depletion.
As an example, a unitholder that acquired units in April 1999 and held
them throughout 1999 would be entitled to a cost depletion deduction
of approximately 6% of his cost. Assuming a cost of $9.50 per unit,
cost depletion would offset 66% of 1999 taxable trust income. After
considering the tight sands tax credit and assuming a 30% tax rate,
the 1999 taxable equivalent return as a percentage of unit cost would
be 11.4%. This return is for eleven months since the trust's initial
year includes revenues related to production months of December 1998
through October 1999. (NOTE- Because the units are a depleting asset,
a portion of this return is effectively a return of capital.)
2
<PAGE>
TO UNITHOLDERS
- --------------
We are pleased to present the first Annual Report of the Hugoton Royalty Trust.
This report includes a copy of the trust's 1999 Form 10-K filed with the
Securities and Exchange Commission. Both of these reports contain important
information about the net profits interests, including information provided to
the trustee by Cross Timbers, and should be read in conjunction with each other.
For the year ended December 31, 1999, royalty income totaled $33,139,662. After
adding interest income of $46,374 and deducting trust administration expense of
$95,987, distributable income was $33,090,049 or $0.827253 per unit. Royalty
income related to monthly distributions declared through March 2000 includes
amounts to provide a minimum monthly gas price of $2.00 per Mcf. Such amounts
included in 1999 royalty income totaled $3,981,688, or approximately $0.10 per
unit.
Including the $2.00 per Mcf minimum price support, natural gas prices averaged
$2.12 per Mcf for 1999. Excluding such support, the average price was $1.96 per
Mcf. The average 1999 oil price was $16.53 per Bbl.
Gas sales volumes from the underlying properties for the year totaled 34,188,398
Mcf, or 102,055 Mcf per day. Oil sales volumes from the underlying properties
were 388,038 Bbls, or 1,158 Bbls per day. For further information on sales
volumes and product prices, see "Trustee's Discussion and Analysis."
Tight sands gas sales volumes from the underlying properties were 2,036,531 Mcf
in 1999. The resulting 1999 tight sands tax credit was $0.016093 per unit.
This credit (or a portion thereof, if units were acquired after March 1999) is
available to be applied against the unitholder's regular federal income tax
liability, subject to certain limitations. Unitholders should consult their tax
advisors regarding use of this credit.
As of December 31, 1999, proved reserves for the net profits interests were
estimated by independent engineers to be 2,411,000 Bbls of oil and 287.9 Bcf of
natural gas. All reserve information prepared by independent engineers has been
provided to the trustee by Cross Timbers.
Estimated future net revenues from proved reserves of the net profits interests
at December 31, 1999 are $642.2 million or $16.05 per unit. Using an annual
discount factor of 10%, the present value of estimated future net revenues at
December 31, 1999 is $327 million or $8.18 per unit. Proved reserve estimates
and related future net revenues have been determined based on year-end oil and
gas prices, as well as other guidelines prescribed by the Financial Accounting
Standards Board as further described under Item 2 of the accompanying Form 10-K.
The present value of estimated future net revenues is not necessarily
representative of the market value of trust units.
As discussed in the tax instructions provided to unitholders in February 2000,
trust distributions are considered portfolio income, rather than passive income.
Unitholders should consult their tax advisors for further information.
Hugoton Royalty Trust
By: Bank of America, N.A., Trustee
By: Ron E. Hooper
Vice President
3
<PAGE>
THE UNDERLYING PROPERTIES
- -------------------------
The underlying properties are predominantly gas-producing properties with
established production histories in the Hugoton area of Oklahoma and Kansas,
the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The
average reserve-to-production index for the underlying properties as of December
31, 1999 is approximately 14 years. The reserve-to-production index is
calculated using total proved reserves and estimated 2000 production for the
underlying properties. Based on discounted future net revenues at year-end oil
and gas prices, the proved reserves of the underlying properties are
approximately 91% natural gas and 9% oil. Cross Timbers operates approximately
90% of the underlying properties.
Because the underlying properties are working interests, production and
development costs are deducted in calculating royalty income from the net
profits interests. As a result, royalty income from these interests is affected
by the level of maintenance and development activity on the underlying
properties. See "Trustee's Discussion and Analysis - Costs." Total 1999
development costs for the underlying properties were $11,317,623. Cross Timbers
has notified the trustee that total budgeted development costs for 2000 are
$13,800,000 for the underlying properties, or $11,040,000 related to the net
profits interests.
Hugoton Area
Discovered in 1922, the Hugoton area is the largest natural gas producing area
in North America. During 1999, gas sales volumes from the Hugoton area were
11,477,000 Mcf, or approximately 33% of total trust sales volumes from the
underlying properties. Most of the production is from the Permian-aged Chase
formation which has a depth of 2,700 to 2,900 feet. Cross Timbers plans to
develop the Chase formation primarily through infill drilling of up to 35 wells
in Kansas. In June 1999, Oklahoma regulations were amended to allow increased
drilling density in the Oklahoma panhandle where Cross Timbers has approximately
200 infill well locations on the underlying properties. Cross Timbers also
plans to develop 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 its net acreage position beneath the Chase
formation. Test wells were drilled to delineate the Council Grove formation in
1999 and further test wells are planned for 2000.
Cross Timbers drilled 5 gross (4.0 net) wells in 1999 to the Chester, Council
Grove and Chase formations, all of which were successfully completed. Cross
Timbers plans to drill up to three wells and perform up to 24 workovers in the
Hugoton area during 2000.
Anadarko Basin
The Major County area and the Elk City field are the two principal producing
areas in the Anadarko Basin of western Oklahoma. Cross Timbers is one of the
largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields
in Major County. Gas sales volumes from the Major County area and the Elk City
field totaled 13,509,000 Mcf in 1999, or approximately 40% of total trust sales
volumes from the underlying properties.
Cross Timbers successfully drilled and completed 8 gross (5.5 net) wells in 1999
in the northwest portion of Major County, targeting the Chester, Inola, Oswego
and Redfork formations. Cross Timbers plans to drill up to 13 wells and perform
up to 42 workovers in the Major County area during 2000.
Cross Timbers has increased production in the Elk City field primarily by
mechanically stimulating and opening new producing zones in existing wells.
Opportunities remain for additional development in the field. Cross Timbers has
added significant additional reserves through recent recompletions to the Atoka
formation and plans to drill one well to the Hoxbar formation in 2000.
Green River Basin
The Green River Basin is located in southwestern Wyoming. Natural gas was
discovered in the Fontenelle field of the Green River Basin in the early 1970s.
The producing reservoirs are the Cretacious-aged Frontier and Dakota sandstones
at depths ranging from 7,500 to 10,000 feet.
Gas sales volumes from the Green River Basin were 9,202,000 Mcf in 1999, or
approximately 27% of total trust sales volumes from the underlying properties.
Cross Timbers drilled and completed 7 gross (6.9 net) wells in the Fontenelle
Unit in 1999. Cross Timbers plans to drill up to five wells and perform up to
five workovers in the Green River Basin during 2000.
4
<PAGE>
Estimated Proved Reserves and Future Net Revenues
The following are proved reserves of the underlying properties and proved
reserves and future net revenues from proved reserves of the net profits
interests at December 31, 1999, as estimated by independent engineers:
<TABLE>
<CAPTION>
Underlying Properties Net Profits Interests
---------------------- -----------------------------------------------------
Proved Reserves (a) Proved Reserves (a) (b) Future Net Revenues
---------------------- -------------------------
Gas Oil Gas Oil from Proved Reserves (a) (c)
---------------------------
(Mcf) (Bbls) (Mcf) (Bbls) Undiscounted Discounted
-------- ------ ------- ------ ------------ ----------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Oklahoma................... 293,149 3,939 166,313 2,219 $ 387,065 $ 212,503
Wyoming.................... 164,139 268 95,381 156 213,400 92,312
Kansas..................... 48,081 64 26,227 36 41,689 22,199
-------- ------ ------- ------ ------------ ----------
TOTAL................. 505,369 4,271 287,921 2,411 $ 642,154 $ 327,014
======== ====== ======== ====== ============ ==========
</TABLE>
(a) Based on year-end oil and gas prices. For further information regarding
trust proved reserves, see Item 2 of the accompanying Form 10-K.
(b) Since the trust has defined net profits interests, the trust does not own a
specific ownership percentage of the oil and gas reserves. 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.
(c) Before income taxes (and the tax benefit of the estimated tight sands tax
credit) since future net revenues are not subject to taxation at the trust
level.
TRUSTEE'S DISCUSSION AND ANALYSIS
- ---------------------------------
For the Year and Quarter Ended December 31, 1999
Royalty income for 1999 was $33,139,662. Approximately 90% of royalty income
was derived from natural gas sales. After deducting administration expense of
$95,987 and adding interest income of $46,374, distributable income was
$33,090,049 or $0.827253 per unit.
Royalty income for the quarter ended December 31, 1999 totaled $12,177,926.
After adding interest income of $21,857 and deducting administration expense of
$33,584, fourth quarter distributable income was $12,166,200, or $0.304155 per
unit. Distributions to unitholders for the quarter ended December 31, 1999
were:
<TABLE>
<CAPTION>
Record Date Payment Date Per Unit
----------------- ----------------- ------------
<S> <C> <C>
October 29, 1999 November 15, 1999 $ 0.090249
November 30, 1999 December 14, 1999 0.100110
December 31, 1999 January 14, 2000 0.113796
------------
$ 0.304155
============
</TABLE>
Royalty income is recorded when received by the trust, which is the month
following receipt by Cross Timbers, and generally two months after oil and gas
production. Because of this two-month interval, the trust's initial accounting
year ended December 31, 1999 includes royalty income related to eleven months of
oil and gas sales, or December 1998 (the trust's initial month) through October
1999 production. Royalty income for the fourth quarter represents oil and gas
sales related to August through October 1999 production. Royalty income is
generally affected by three major factors:
. oil and gas sales volumes,
. oil and gas sales prices, and
. costs deducted in the calculation of royalty income.
Volumes
Gas sales volumes for the underlying properties were 34,188,398 Mcf, while oil
sales volumes were 388,038 Bbls for the year ended December 31, 1999. Daily gas
sales volumes of 102,055 Mcf for the year were lower than daily volumes of
104,189 Mcf for the fourth quarter because of the lag effect on cash receipts in
the trust's initial accounting period. Compared to the third quarter, fourth
quarter gas sales volumes were 1% higher and oil sales volumes were 1% lower.
Prices
The 1999 average oil price was $16.53 per Bbl. Because of the two-month
interval between oil production and receipt by the trust of related royalty
income, the 1999
5
<PAGE>
average price includes the effect of oil prices that hit a 20-year low in
December 1998, offset by improvements that began in March 1999 after production
cuts were made by OPEC members and other leading oil producers.
The average gas price was $2.12 per Mcf for the year and $2.42 per Mcf for the
quarter. For trust distributions declared through March 2000, related royalty
income is based on the greater of:
. the actual amount received from sales of production, or
. the imputed amount that would be received from sales of production based
on a gas price of $2.00 per Mcf.
The average gas price of $2.42 per Mcf for the fourth quarter represents the
actual amount received from gas sales. The average price of $2.12 for the year
includes the effect of adding to royalty income $4,977,110 ($3,981,688 net to
the trust) to achieve the $2.00 minimum price for several months in 1999. The
actual average gas price of $1.96 for the year ended December 31, 1999, reflects
high levels of gas storage from the previous two abnormally warm winters. Gas
prices trended higher during 1999 as gas storage declined. Higher gas prices
also reflect the effect of higher natural gas liquids prices, which were
depressed in 1998.
Expansion of pipeline capacity during the past several years and demand growth
in the western U.S. has helped to strengthen gas prices in the Rocky Mountain
region relative to prices in the eastern U.S. Gas is increasingly being used
for power generation in southwestern U.S. markets, which because of the
significant summer demand, has helped to sustain prices throughout the year.
Costs
The calculation of royalty income from the net profits interests includes
deductions for production and development costs and overhead since the related
underlying properties are working interests. Royalty income is calculated
monthly for each of the three conveyances under which the net profits interests
were conveyed to the trust. If monthly costs exceed revenues for any
conveyance, such excess costs cannot reduce royalty income from other
conveyances, but must be recovered, with accrued interest, from future net
proceeds of that conveyance.
Costs deducted in the calculation of royalty income totaled $10,206,646 for the
fourth quarter and $37,475,916 for the year. Costs for the quarter reflect
Cross Timbers' disbursements for the three months of September through November
1999, while costs for the year reflect Cross Timbers' disbursements for the
twelve months of December 1998 through November 1999. Development costs for the
fourth quarter were 24% lower than for the third quarter primarily because of
the timing of development projects and payment of related billings. Development
costs are primarily associated with drilling and workovers on operated
properties in Oklahoma and Wyoming. Costs per Mcfe declined to $1.00 for the
fourth quarter from $1.02 for the third quarter because of lower development
costs, partially offset by increased taxes related to higher product prices.
Because 1999 is the trust's initial accounting year, costs per Mcfe for the year
of $1.03 reflect twelve months of cost divided by only eleven months of oil and
gas sales volumes.
Costs exceeded revenues from properties underlying the Wyoming net profits
interests in August 1999 because of new wells drilled. All excess costs and
accrued interest were fully recovered in September 1999.
See Item 7 of the accompanying Form 10-K for trust year 2000 compliance
considerations, and Item 7a for disclosures of market risks affecting the trust.
6
<PAGE>
- -------------------------------------------------------------------------------
Calculation of Royalty Income
The following is a summary of the calculation of royalty income received by the
trust for the year and quarter ended December 31, 1999.
<TABLE>
<CAPTION>
Year Quarter
Ended Ended
December 31, December 31,
1999 (a) 1999 (a)
------------ ------------
<S> <C> <C> <C> <C>
Sales Volumes
Gas (Mcf) (b)
Underlying properties........................ 34,188,398 9,585,390
Average per day............................. 102,055 104,189
Net profits interests........................ 15,583,364 5,103,893
Oil (Bbls) (b)
Underlying properties........................ 388,038 102,997
Average per day............................. 1,158 1,120
Net profits interests........................ 190,668 52,372
Mcfe
Underlying properties........................ 36,516,626 10,203,372
Average per day............................. 109,005 110,906
Average Sales Price
Gas (per Mcf).................................. $2.12 $2.42
Oil (per Bbl).................................. $16.53 $21.72
Per Mcfe Per Mcfe
-------- --------
Revenues
Gas sales $ 72,484,491 $ 23,191,816
Oil sales 6,416,003 2,237,238
------------ ------------
Total......................................... 78,900,494 $ 2.16 25,429,054 $ 2.49
------------ ------- ------------ -------
Costs
Taxes, transportation and other................ 8,264,983 0.23 2,644,280 0.26
Production expense............................. 11,043,348 0.30 2,993,302 0.29
Development costs.............................. 11,317,623 0.31 2,821,463 0.28
Overhead....................................... 6,849,712 0.19 1,747,601 0.17
Excess costs................................... (35,718) (0.00) - -
Recovery of excess costs and accrued interest.. 35,968 0.00 - -
------------ ------- ------------ -------
Total......................................... 37,475,916 1.03 10,206,646 1.00
------------ ------- ------------ -------
Net Proceeds..................................... 41,424,578 $ 1.13 15,222,408 $ 1.49
======= =======
Net Profits Percentage........................... 80% 80%
------------ ------------
Royalty Income................................... $33,139,662 $12,177,926
============ ============
- -----------------------------------
</TABLE>
(a) Because of the two month interval between time of production and receipt of
royalty income by the trust 1) oil and gas sales for the year ended December
31, 1999 generally relate to eleven months of production for the period
ended December 1998 (the trust's initial month) through October 1999, and 2)
oil and gas sales for the quarter ended December 31, 1999 generally relate
to production for the period August 1999 through October 1999.
(b) Oil and gas sales volumes are allocated to the net profits interests based
upon a formula that considers oil and gas prices and the total amount of
production expenses and development costs. Changes in any of these factors
may result in disproportionate fluctuations in volumes allocated to the net
profits interests. Therefore, comparative analysis of oil and gas sales is
based on the underlying properties.
7
<PAGE>
HUGOTON ROYALTY TRUST
- --------------------------------------------------------------------------------
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
December 31
---------------------------
1999 1998
------------- ------------
<S> <C> <C>
Assets
Cash and short-term investments............... $ 4,551,840 $ 1,000
Net profits interests in oil and gas
properties - net (Notes 1 and 2)............. 233,428,609 247,066,951
------------- -------------
$ 237,980,449 $ 247,067,951
============= =============
Liabilities and Trust Corpus
Distribution payable to unitholders........... $ 4,551,840 $ -
Trust corpus (40,000,000 units of beneficial
interest authorized and outstanding)......... 233,428,609 247,067,951
------------- -------------
$ 237,980,449 $ 247,067,951
============= =============
</TABLE>
- -------------------------------------------------------------------------------
STATEMENT OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
Year Ended
December 31,
1999
-------------
<S> <C>
Royalty income............................................... $ 33,139,662
Interest income.............................................. 46,374
-------------
Total income................................................ 33,186,036
Administration expense....................................... 95,987
-------------
Distributable income........................................ $ 33,090,049
=============
Distributable income per unit..
(40,000,000 units)......................................... $ 0.827253
=============
</TABLE>
- -------------------------------------------------------------------------------
STATEMENT OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
Year Ended
December 31,
1999
-------------
<S> <C>
Trust corpus, beginning of year.............................. $ 247,067,951
Amortization of net profits interests........................ (13,638,342)
Return of initial contribution to grantor.................... (1,000)
Distributable income......................................... 33,090,049
Distributions declared....................................... (33,090,049)
-------------
Trust corpus, end of year.................................... $ 233,428,609
=============
</TABLE>
- -------------------------------------------------------------------------------
See Accompanying Notes to Financial Statements.
8
<PAGE>
Hugoton Royalty Trust
- -------------------------------------------------------------------------------
NOTES TO FINANCIAL STATEMENTS
1. Trust Organization and Provisions
Hugoton Royalty Trust was created on December 1, 1998 by Cross Timbers Oil
Company. Effective on that date, Cross Timbers conveyed 80% defined net profits
interests in certain predominantly gas-producing working interest properties in
Kansas, Oklahoma and Wyoming to the trust under separate conveyances for each of
the three states. Cross Timbers currently owns, and operates the majority of,
the underlying working interest properties.
The trust receives royalty income in the month following receipt of related
net proceeds by Cross Timbers. Accordingly, the trust did not receive royalty
income or declare distributions for December 1998.
In exchange for the conveyances of the net profits interests to the trust,
40,000,000 units of beneficial interest in the trust were issued to Cross
Timbers. On April 8, 1999, Cross Timbers sold 15,000,000 units in the trust's
initial public offering. On May 7, 1999, Cross Timbers sold an additional
2,004,000 units pursuant to the underwriters' overallotment option. The trust
did not receive any proceeds from the sale of trust units.
Bank of America, N.A. is the trustee for the trust. The trust indenture
provides, among other provisions, that:
- the trust cannot engage in any business activity or acquire any assets
other than the net profits interests and specific short-term cash
investments;
- the trust may dispose of all or part of the net profits interests if
approved by 80% of the unitholders, or upon trust termination.
Otherwise, the trust may sell up to 1% of the value of the net profits
interests in any calendar year, pursuant to notice from Cross Timbers of
its desire to sell the related underlying properties. Any sale must be
for cash with the proceeds promptly distributed to the unitholders;
- the trustee may establish a cash reserve for payment of any liability
that is contingent or not currently payable;
- the trustee may borrow funds to pay trust liabilities if repaid in full
prior to further distributions to unitholders;
- the trustee will make monthly cash distributions to unitholders (Note
3); and
- the trust will terminate upon the first occurrence of:
- disposition of all net profits interests pursuant to terms of the
trust indenture,- gr oss proceeds from the underlying properties
falling below $1 million per year for two successive years after
1999, or
- a vote of 80% of the unitholders to terminate the trust in accordance
with provisions of the trust indenture.
2. Basis of Accounting
The financial statements of the trust are prepared on the following basis
and are not intended to present financial position and results of operations in
conformity with generally accepted accounting principles:
- Royalty income is recorded in the month received by the trustee (Note
3).
- Trust expenses are recorded based on liabilities paid and cash reserves
established by the trustee for liabilities and contingencies.
- Distributions to unitholders are recorded when declared by the trustee
(Note 3).
The most significant differences between the trust's financial statements
and those prepared in accordance with generally accepted accounting principles
are:
- Royalty income is recognized in the month received rather than accrued
in the month of production.
- Expenses are recognized when paid rather than when incurred.
- Cash reserves may be established by the trustee for contingencies that
would not be recorded under generally accepted accounting principles.
The initial carrying value of the net profits interests of $247,066,951 was
Cross Timbers' historical net book value of the interests on December 1, 1998,
the date of the transfer to the trust. Amortization of the net profits
interests is calculated on a unit-of-production basis and charged directly to
trust corpus. Accumulated amortization as of December 31, 1999 was $13,638,342.
3. Distributions to Unitholders
The trustee determines the amount to be distributed to unitholders each
month by totaling royalty income, interest income and other cash receipts, and
subtracting liabilities paid and adjustments in cash reserves established by the
trustee. The resulting amount is distributed to unitholders of record within ten
business days after the monthly record date, the last business day of the month.
Royalty income received by the trustee consists of net proceeds received in
the prior month by Cross Timbers from the underlying properties, multiplied by
80%. Net proceeds are the gross proceeds received from the
9
<PAGE>
sale of production, less applicable costs. Applicable costs generally include
applicable taxes, transportation, legal and marketing charges, production costs,
development and drilling costs, and overhead (Note 5).
For monthly trust distributions declared through March 2000, the related
royalty income is based on gross proceeds equal to the greater of:
- the actual amount received from sales of production, or
- the imputed amount that would be received from sales of production at a
gas price of $2.00 per Mcf. For the year ended December 31, 1999,
imputed proceeds based on a $2.00 gas price exceeded actual proceeds by
$4,977,110 ($3,981,688 net to the trust).
Cross Timbers, as owner of the underlying properties, computes royalty
income separately for each of the three conveyances (Note 1). If costs exceed
gross proceeds for any conveyance, such excess costs cannot be used to reduce
the amounts payable to the trust under the other conveyances. The trust is not
liable for excess costs; however, future royalty income from the net profits
interests created by that conveyance will be reduced by such excess costs plus
accrued interest.
4. Federal Income Taxes
Tax counsel has advised the trust that, under current tax laws, the trust
will be classified as a grantor trust for federal income tax purposes and,
therefore, is not subject to taxation at the trust level. However, the opinion
of tax counsel is not binding on the Internal Revenue Service.
For federal income tax purposes, unitholders of a grantor trust are
considered to own the trust's income and principal as though no trust were in
existence. The income of the trust is deemed to be received or accrued by the
unitholders at the time such income is received or accrued by the trust, rather
than when distributed by the trust.
Cross Timbers has advised the trustee that the trust receives royalty
income from tight sands gas wells. Production sold through 2002 from wells
drilled on the underlying properties prior to January 1, 1993, and after
November 5, 1990, or after December 31, 1979 if the related formation was
dedicated to interstate commerce as of April 20, 1977, qualifies for the federal
income tax credit for producing nonconventional fuels under Section 29 of the
Internal Revenue Code. This tax credit is approximately $0.52 per MMBtu and,
based on qualifying sales volumes, was $0.016093 per unit for 1999. The credit
is recalculated annually based on each year's qualifying production through the
year 2002. Unitholders should consult their tax advisors regarding use of this
credit and other trust tax compliance matters.
5. Cross Timbers Oil Company
Cross Timbers operates approximately 90% of the wells on the underlying
properties. In computing net proceeds, Cross Timbers deducts an overhead charge
for reimbursement of administrative expenses on the underlying properties it
operates. As of December 31, 1999, the overhead charge was approximately
$580,000 ($464,000 net to the trust) per month and is subject to annual
adjustment based on an oil and gas industry index. As of March 1, 2000, Cross
Timbers owned 57.3% of the trust.
Cross Timbers sells a significant portion of natural gas production from
the underlying properties to certain of Cross Timbers' wholly owned subsidiaries
under contracts in existence when the trust was created, 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 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 gas to Cross Timbers Energy Services, Inc.
("CTES"), which markets gas to third parties. Cross Timbers sells directly to
CTES most gas production not sold directly to TGPC or RGC.
Total gas sales from the underlying properties directly to each of Cross
Timbers' wholly owned subsidiaries, and the percentage to total oil and gas
sales for the year ended December 31, 1999 were $37.5 million to CTES (47%),
$14.1 million to TGPC (18%) and $4.3 million to RGC (5%).
6. Litigation
Cross Timbers 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
Cross Timbers.
On April 3, 1998, a class action lawsuit, Booth, et al. v. Cross Timbers
Oil Company, was filed in the District
10
<PAGE>
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 and
selling natural gas through affiliated companies at prices less favorable than
those paid by third parties. Cross Timbers believes that it has strong defenses
to this lawsuit and intends to vigorously defend its position. However, if Cross
Timbers ultimately makes any settlement payments, the trust will bear its 80%
share of such settlement related to production from the underlying properties
for periods since December 1, 1998. Additionally, if a judgment or settlement
increases the amount of future payments to royalty owners, the trust would bear
its proportionate share of the increased payments through reduced net proceeds.
The amount of any reduction in net proceeds is not presently determinable, but,
in Cross Timbers management's opinion, is not currently expected to be material
to the trust's annual 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 Cross Timbers
underpaid royalties on natural gas produced from federal leases and lands owned
by Native Americans by at least 20% during the past 10 years as a result of
mismeasuring the volume of natural gas and wrongfully analyzing its heating
content. The suit, which was brought under the qui tam provisions of the U.S.
False Claims Act, seeks treble damages for the unpaid royalties (with interest),
civil penalties between $5,000 and $10,000 for each violation of the U.S. False
Claims Act, and an order for Cross Timbers to cease the allegedly improper
measuring practices. Cross Timbers and other defendants have filed a motion to
dismiss the lawsuit. Cross Timbers believes that the allegations of this lawsuit
are without merit and intends to vigorously defend the action. 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 Cross Timbers management's opinion, is not expected to be
material to the trust's annual distributable income, financial position or
liquidity.
For further information regarding these lawsuits and other legal
proceedings pertaining to the trust, see Item 3 of the trust's Annual Report on
Form 10-K which is included in this report.
7. Supplemental Oil and Gas Reserve Information (Unaudited)
Proved oil and gas reserve information is included in Item 2 of the trust's
Annual Report on Form 10-K which is included in this report.
8. Quarterly Financial Data (Unaudited)
The following is a summary of royalty income, distributable income and
distributable income per unit by quarter for 1999:
<TABLE>
<CAPTION>
Distributable
Royalty Distributable Income
Quarter Income Income per Unit
- ------------------------ ----------- ------------- -------------
<S> <C> <C> <C>
First................... $ 3,565,075 $ 3,562,075 $ 0.089052
Second.................. 8,854,991 8,833,454 0.220838
Third................... 8,541,670 8,528,320 0.213208
Fourth.................. 12,177,926 12,166,200 0.304155
------------ ------------ ----------
$ 33,139,662 $ 33,090,049 $ 0.827253
============ ============ ==========
</TABLE>
11
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
- ----------------------------------------
Bank of America, N.A., as Trustee for the Hugoton Royalty Trust:
We have audited the accompanying statements of assets, liabilities and
trust corpus of the Hugoton Royalty Trust as of December 31, 1999 and 1998, and
the statement of distributable income and changes in trust corpus for the year
ended December 31, 1999. These financial statements are the responsibility of
the trustee. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. 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 the trustee, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As described in Note 2 to the financial statements, these financial
statements were prepared on the modified cash basis of accounting, which is a
comprehensive basis of accounting other than generally accepted accounting
principles.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of the trust
as of December 31, 1999 and 1998 and its distributable income and changes in
trust corpus for the year ended December 31, 1999, on the modified cash basis of
accounting described in Note 2.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 1, 2000
12
<PAGE>
HUGOTON ROYALTY TRUST
- ---------------------
901 Main Street, 17/th/ Floor
P.O. Box 830650
Dallas, Texas 75283-0650
(877) 228-5083
Bank of America, N.A., Trustee
A copy of the Hugoton Royalty Trust Form 10-K
has been provided with this Annual Report. Additional copies
of this Annual Report and Form 10-K will be provided to
unitholders without charge upon request.
AUDITORS
- --------
Arthur Andersen LLP
Fort Worth, Texas
LEGAL COUNSEL
- -------------
Thompson & Knight L.L.P.
Dallas, Texas
TAX COUNSEL
- -----------
Winstead Sechrest & Minick P.C.
Houston, Texas
TRANSFER AGENT AND REGISTRAR
- ----------------------------
ChaseMellon Shareholder Services, L.L.C.
Dallas, Texas
www.chasemellon.com
<PAGE>
EXHIBIT 23.1
INDEPENDENT PUBLIC ACCOUNTANTS' CONSENT
Hugoton Royalty Trust
Dallas, Texas
As independent public accountants, we hereby consent to the incorporation by
reference in Registration Statement No. 333-81849 on Form S-8 of Cross Timbers
Oil Company of our report dated March 1, 2000, included in the Annual Report on
Form 10-K of Hugoton Royalty Trust for the year ended December 31, 1999.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 30, 2000
<PAGE>
EXHIBIT 23.2
[LETTERHEAD OF MILLER AND LENTS, LTD. APPEARS HERE]
March 30, 2000
Hugoton Royalty Trust
P.O. Box 830650
Dallas, TX 75283-0650
Re: Hugoton Royalty Trust
1999 Annual Report on Form 10-K
Gentlemen:
The firm of Miller and Lents, Ltd., consents to the use of its name and to
the use of its report dated March 29, 2000, regarding the Hugoton Royalty Trust
Proved Reserves and Future Net Revenue as of January 1, 2000, in the 1999 Annual
Report on Form 10-K.
Miller and Lents, Ltd., has no interests in the Hugoton Royalty Trust or in
any affiliated companies or subsidiaries and is not to receive any such interest
as payment for such reports and has no director, officer, or employee otherwise
connected with Hugoton Royalty Trust. We are not employed by Hugoton Royalty
Trust on a contingent basis.
Yours very truly,
MILLER AND LENTS, LTD.
By /s/ James C. Pearson
--------------------------
James C. Pearson
President
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 4,551,840
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 4,551,840
<PP&E> 247,066,951
<DEPRECIATION> 13,638,342
<TOTAL-ASSETS> 237,980,449
<CURRENT-LIABILITIES> 4,551,840
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 233,428,609
<TOTAL-LIABILITY-AND-EQUITY> 237,980,449
<SALES> 33,139,662
<TOTAL-REVENUES> 33,186,038
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 95,987
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 33,090,049
<INCOME-TAX> 0
<INCOME-CONTINUING> 33,090,049
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 33,090,049
<EPS-BASIC> 0.827
<EPS-DILUTED> 0.827
</TABLE>
