<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 proceeds      Gross proceeds from sale of production from the underlying
                  properties, less applicable costs

net profits       An interest in an oil and gas property measured by net
interest          profits from the sale of production, rather than a specific
                  portion of production

royalty income    Net proceeds multiplied by the net profits percentage of 80%
                  and paid to the trust

underlying        Cross Timbers' interest in certain oil and gas properties
properties        from which the net profits interests were conveyed. 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 when Cross Timbers Oil
Company conveyed 80% net profits interests in certain predominantly gas-
producing properties located in Kansas, Oklahoma and Wyoming to the trust.  The
net profits interests are the only assets of the trust, other than cash held for
trust expenses 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 2000 and 1999:

<TABLE>
<CAPTION>

                               Sales Price
                         ----------------------  Distributions
    Quarter                 High         Low       per Unit
----------------------   -----------  ---------  -------------
<S>                      <C>          <C>        <C>
2000
----------------------
First.................   $ 9.000      $   7.625    $0.273482
Second................    13.000          8.188     0.281612
Third.................    15.688         11.188     0.404911
Fourth................    15.500         12.375     0.457797
                                                 -------------
                                                   $1.417802
                                                 =============

1999
---------------------
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, 2000, there were 40,000,000 units outstanding and approximately
86 unitholders of record; 17,411,800 of these units were held by a depository
institution.  As of March 1, 2001, Cross Timbers owned 21,705,893 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 properties in each state are calculated by deducting production
and development costs.  If costs exceed revenues from the underlying properties
in any state, the related net profits interests will not contribute to royalty
income until all excess costs and accrued interest have been recovered from the
state's future net proceeds.  These excess costs cannot 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 January 2000
               and held them throughout 2000 would be entitled to a cost
               depletion deduction of approximately 6% of his cost. Assuming a
               cost of $8.50 per unit, cost depletion would offset 39% of 2000
               taxable trust income. After considering the tight sands tax
               credit and assuming a 30% tax rate, the 2000 taxable equivalent
               return as a percentage of unit cost would be 20%. (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 2000 Annual Report of the Hugoton Royalty Trust.
This report includes a copy of the trust's 2000 Form 10-K filed as with the
Securities and Exchange Commission.  Both of these reports contain important
information about the trust's 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, 2000, royalty income totaled $56,812,141.  After
adding interest income of $128,150 and deducting trust administration expense of
$228,211, distributable income was $56,712,080 or $1.417802 per unit.  Royalty
income and distributions for the year were 71% higher than comparable 1999
amounts primarily because of higher oil and gas prices.

Natural gas prices averaged $3.14 per Mcf for 2000, a 48% increase from the 1999
average price of $2.12 per Mcf.  The average 2000 oil price was $28.67 per Bbl,
a 73% increase from the 1999 average price of $16.53 per Bbl.

Gas sales volumes from the underlying properties for 2000 were 36,842,156 Mcf,
or 100,662 Mcf per day, as compared with 1999 average daily sales volumes of
102,055 Mcf per day.  Oil sales volumes from the underlying properties were
399,929 Bbls, or 1,093 Bbls per day in 2000, as compared with 1,158 Bbls per day
in 1999.  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 2,157,336 Mcf
in 2000.  After reduction of volumes related to production and development
costs, tight sands gas sales volumes allocated to the net profits interests were
1,022,130 Mcf, resulting in a tight sands tax credit for the year of $0.014499
per unit. This credit (or a portion thereof, if units were acquired after
January 2000) 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, 2000, proved reserves for the net profits interests were
estimated by independent engineers to be 3,259,000 Bbls of oil and 372.2 Bcf of
natural gas. Estimated gas reserves increased 29% and oil reserves increased 35%
from year-end 1999 to 2000, primarily because of the increase in year-end
realized gas prices from $2.23 to $9.44 per Mcf and West Texas Intermediate
posted oil prices from $22.75 to $23.75 per Bbl, and the resulting increased
allocation of reserves to the net profits interests. 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, 2000 are $3.27 billion, or $81.63 per unit.  Using an annual
discount factor of 10%, the present value of estimated future net revenues at
December 31, 2000 is $1.55 billion, or $38.81 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 2001,
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

/s/ RON E. HOOPER

By: Ron E. Hooper
    Senior 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, 2000 is approximately 15 years.  The reserve-to-production index is
calculated using total proved reserves and estimated 2001 production for the
underlying properties.  Based on estimated future net revenues at year-end oil
and gas prices, the proved reserves of the underlying properties are
approximately 98% natural gas and 2% 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 2000
development costs for the underlying properties were $21,767,819, an increase of
92% from the prior year.  Cross Timbers has notified the trustee that total
budgeted development costs for 2001 for the underlying properties are $23.0
million, or $18.4 million 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 2000, gas sales volumes from the Hugoton area were
11,844,000 Mcf, or approximately 32% of total 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.  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 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.

Cross Timbers drilled one gross (1.0 net) well in 2000 to the Chester, Council
Grove and Chase formations, which was successfully completed.  Cross Timbers
plans to perform up to 37 workovers in the Hugoton area during 2001.

Anadarko Basin

The Anadarko Basin of western Oklahoma was discovered in 1945.  Gas sales
volumes from the Anadarko Basin totaled 15,405,000 Mcf in 2000, or approximately
42% of total sales volumes from the underlying properties.  Cross Timbers is one
of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley
fields in Major County, the principal producing region of the underlying
properties in the Anadarko Basin.

Cross Timbers successfully drilled and completed 18 gross (12.9 net) wells in
2000 in the northwest portion of Major County, targeting the Chester, Inola,
Oswego and Redfork formations.  Cross Timbers plans to drill up to 27 wells and
perform up to 17 workovers in the Anadarko Basin during 2001.

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 Cretaceous-aged Frontier and Dakota sandstones
at depths ranging from 7,500 to 10,000 feet.

Gas sales volumes from the Green River Basin were 9,593,000 Mcf in 2000, or
approximately 26% of total sales volumes from the underlying properties.  Cross
Timbers drilled and completed five gross (4.9 net) wells in the Fontenelle Unit
in 2000.  Cross Timbers plans to drill up to ten wells and perform up to seven
workovers in the Green River Basin during 2001.

                                                                               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, 2000, as estimated by independent engineers:

<TABLE>
<CAPTION>

                                       Underlying Properties                                Net Profits Interests
                             -----------------------------------------  ------------------------------------------------------------
                                        Proved Reserves (a)              Proved Reserves (a) (b)          Future Net Revenues
                             -----------------------------------------  -------------------------     from Proved Reserves (a) (c)
                                     Gas                   Oil                Gas           Oil     --------------------------------
                                    (Mcf)                (Bbls)               (Mcf)         (Bbls)      Undiscounted      Discounted
                             --------------------  -------------------  ------------------  ------  --------------------  ----------
<S>                          <C>                   <C>                  <C>                 <C>     <C>                   <C>
(in thousands)

Oklahoma...................              306,188                4,226             219,529   3,032             $1,992,994  $  997,646
Wyoming....................              159,826                  244             117,591     179              1,007,737     428,726
Kansas.....................               49,004                   67              35,030      48                264,452     125,917
                                         -------                -----             -------   -----             ----------  ----------

     TOTAL.................              515,018                4,537             372,150   3,259             $3,265,183  $1,552,289
                                         =======                =====             =======   =====             ==========  ==========
</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 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
---------------------------------

Years Ended December 31, 2000 and 1999

Royalty income for 2000 was $56,812,141, as compared with $33,139,662 for 1999.
The 71% increase in royalty income from 1999 to 2000 was primarily because of
higher product prices.  During 2000 and 1999, approximately 90% of royalty
income was derived from natural gas sales.

Trust administration expense was $228,211 in 2000 as compared to $95,987 in
1999.  Administration expense was lower in 1999, the trust's initial accounting
year, because of costs not billed and paid until 2000. Because of higher royalty
income, interest income increased to $128,150 in 2000 from $46,374 in 1999.
Distributable income was $56,712,080 or $1.417802 per unit in 2000 and
$33,090,049 or $0.827253 per unit in 1999.

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 only eleven
months of oil and gas sales, or December 1998 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

Underlying gas sales volumes for 2000 were 36,842,156 Mcf, an 8% increase over
1999 underlying volumes of 34,188,398 Mcf.  Underlying oil sales volumes for
2000 were 399,929 Bbls, a 3% increase over 1999 underlying volumes of 388,038
Bbls.  Increased volumes were primarily because of the lag effect of cash
receipts in the trust's initial accounting period, which resulted in less than
eleven full months of sales volumes in 1999.  On a daily basis, underlying gas
sales volumes declined 1% to 100,662 Mcf in 2000 and underlying oil sales
volumes declined 6% to 1,093 Bbls.  Decreased daily sales volumes are primarily
because of natural production decline, largely offset by increased production
from new wells and timing of cash receipts.

Prices

The 2000 average gas price was $3.14 per Mcf in 2000, or 48% higher than the
1999 average gas price of $2.12 per Mcf.  The 1999 average gas price included
the effect of adding $4,977,110 ($3,981,688 net to the trust) to royalty income
to achieve a $2.00 minimum price contractually provided to unitholders for
distributions through March 2000.  As of April 2000, there are no longer any
minimum price provisions.  See Note 3 to the financial statements.  The actual
1999 average price of $1.96 reflects lower prices caused by high levels of gas
in storage remaining from the abnormally warm winter of 1998-1999.  Gas prices
began to increase in May 1999 and, after declining briefly at year end,
continued to strengthen in 2000 as gas storage declined and a colder

                                                                               5
<PAGE>

winter was anticipated.  Higher 2000 gas prices also include the effect of
higher natural gas liquids prices, which were depressed in 1999.  NYMEX gas
prices rose to a record high of $10.10 per MMBtu in December 2000 as winter
demand strained gas supplies.  The average NYMEX price for January and February
2001 was $6.78 per MMBtu.  The trust's recent average gas price has been
approximately $0.40 per MMBtu lower than the NYMEX price.

Expansion of pipeline capacity during the past several years and increased
demand in the western U.S. has helped to strengthen gas prices in the Rocky
Mountain region.  Gas used for power generation has increased, causing more
summer demand for gas to supply electricity for cooling needs.

The 2000 average oil price was $28.67 per Bbl, or 73% higher than the 1999
average price of $16.53 per Bbl. Because of the two-month interval between oil
production and receipt by the trust of related royalty income, the 1999 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.  Despite OPEC production
increases in 2000, increased demand sustained higher prices.  The West Texas
Intermediate ("WTI") posted price reached $34.25 per Bbl in September 2000, its
highest level in ten years. Lagging demand, caused by a world economic slowdown,
has caused oil prices to decline in 2001. OPEC members have responded with
production cuts, which to date have not significantly affected prices. The
average WTI posted price for January and February 2001 was $26.55. Recent trust
oil prices have averaged approximately $2.60 higher than the WTI posted price.

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 2000 royalty income increased $18,555,813,
or 50% from 1999.  Costs per Mcfe increased 39% to $1.43 in 2000 from $1.03 in
1999.  This was primarily the result of increased development costs related to
drilling and workovers on operated properties in Oklahoma and Wyoming, increased
production taxes associated with higher oil and gas prices, and increased
production expenses related to the timing of maintenance projects.

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.

Fourth Quarter 2000 and 1999

During the quarter ended December 31, 2000, the trust received royalty income
totaling $18,291,467, compared with fourth quarter 1999 royalty income of
$12,177,926.  The 50% increase in royalty income from fourth quarter 1999 to
2000 was primarily because of higher product prices.

Administration expense was $23,912 and interest income was $44,325, resulting in
fourth quarter 2000 distributable income of $18,311,880, or $0.457797 per unit.
Distributable income for fourth quarter 1999 was $12,166,200, or $0.304155 per
unit.  Distributions to unitholders for the quarter ended December 31, 2000
were:

                  Record Date       Payment Date      Per Unit
               -----------------  -----------------  ---------
               October 31, 2000   November 14, 2000  $0.149929
               November 30, 2000  December 14, 2000   0.158464
               December 29, 2000  January 16, 2001    0.149404
                                                     ---------
                                                     $0.457797
                                                     =========

Volumes

Fourth quarter 2000 underlying gas sales volumes were 9,444,893 Mcf, or 1% below
1999 underlying volumes of 9,585,390 Mcf.  Fourth quarter 2000 underlying oil
sales volumes were 97,597 Bbls, or 5% below 1999 underlying volumes of 102,997
Bbls.  Lower oil and gas volumes are primarily because of natural production
decline largely offset by new wells.

Prices

The average fourth quarter 2000 gas price was $4.12 per Mcf in 2000, or 70%
higher than the fourth quarter 1999 average price of $2.42.  The average fourth
quarter oil price was $32.34 per Bbl, or 49% higher than the fourth quarter 1999
average price of $21.72.  For further information about product prices, see
"Years Ended December 31, 2000 and 1999 - Prices" above.


Costs

Costs deducted in the calculation of fourth quarter 2000 royalty income
increased $8,964,899, or 88%, from fourth quarter 1999.  This was primarily the
result of increased development costs related to drilling and workovers on
operated properties in Oklahoma and Wyoming, increased production taxes
associated with higher oil and gas prices, and increased production expenses
related to the timing of maintenance projects.



See Item 7 of the accompanying Form 10-K 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:

<TABLE>
<CAPTION>

                                        Year Ended                                           Three Months
                                      December 31 (a)                                    Ended December 31 (a)
                                --------------------------          Increase           -------------------------      Increase
                                    2000          1999             (Decrease)             2000          1999         (Decrease)
                                ------------   -----------                             -----------   -----------
<S>                           <C>              <C>                <C>                 <C>            <C>            <C>
Sales Volumes
 Gas (Mcf) (b)
  Underlying properties.....      36,842,156    34,188,398              8%               9,444,893     9,585,390         (1%)
   Average per day..........         100,662       102,055             (1%)                102,662       104,189         (1%)
  Net profits interests.....      18,199,754    15,583,364             17%               4,568,895     5,103,893        (10%)

 Oil (Bbls) (b)
  Underlying properties.....         399,929       388,038              3%                  97,597       102,997         (5%)
   Average per day..........           1,093         1,158             (6%)                  1,061         1,120         (5%)
  Net profits interests.....         198,677       190,668              4%                  47,562        52,372         (9%)

Average Sales Prices
 Gas (per Mcf)..............          $ 3.14        $ 2.12             48%                  $ 4.12        $ 2.42         70%
 Oil (per Bbl)..............          $28.67        $16.53             73%                  $32.34        $21.72         49%

Revenues
 Gas sales..................    $115,579,023   $72,484,491             59%             $38,879,716   $23,191,816         68%
 Oil sales..................      11,467,882     6,416,003             79%               3,156,163     2,237,238         41%
                                ------------   -----------                             -----------   -----------
    Total Revenues..........     127,046,905    78,900,494             61%              42,035,879    25,429,054         65%
                                ------------   -----------                             -----------   -----------

Costs
 Taxes, transportation
     and other..............      12,023,222     8,264,983             45%               3,855,334     2,644,280         46%
 Production expense.........      15,029,592    11,043,348             36%               4,647,899     2,993,302         55%
 Development costs..........      21,767,819    11,317,623             92%               8,872,831     2,821,463        214%
 Overhead...................       7,211,096     6,849,712              5%               1,795,481     1,747,601          3%
 Excess costs...............               -       (35,718)             -                        -             -          -
 Recovery of excess costs
   and accrued interest.....               -        35,968              -                        -             -          -
                                ------------   -----------                             -----------   -----------
    Total Costs.............      56,031,729    37,475,916             50%              19,171,545    10,206,646         88%
                                ------------   -----------                             -----------   -----------

Net Proceeds................      71,015,176    41,424,578             71%              22,864,334    15,222,408         50%

Net Profits Percentage......              80%           80%                                     80%           80%
                                ------------   -----------                             -----------   -----------

Royalty Income..............    $ 56,812,141   $33,139,662             71%             $18,291,467   $12,177,926         50%
                                ============   ===========                             ===========   ===========

</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 December 1998 (the trust's initial month) through October 1999, 2)
     oil and gas sales for the year ended December 31, 2000 generally relate to
     twelve months of production for the period November 1999 through October
     2000, and 3) oil and gas sales for the three months ended December 31
     generally relate to production for the period August through October.

(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 discussion of oil and gas sales
     volumes is based on the underlying properties.

                                                                               7
<PAGE>

HUGOTON ROYALTY TRUST
--------------------------------------------------------------------------------

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS


                                                        December 31
                                                 --------------------------
                                                     2000          1999
                                                 ------------  ------------
Assets

 Cash and short-term investments...............  $  5,976,160  $  4,551,840

 Net profits interests in oil and gas
  properties - net (Notes 1 and 2).............   226,081,443   233,428,609
                                                 ------------  ------------

                                                 $232,057,603  $237,980,449
                                                 ============  ============

Liabilities and Trust Corpus

 Distribution payable to unitholders...........  $  5,976,160  $  4,551,840

 Trust corpus (40,000,000 units of beneficial
  interest authorized and outstanding).........   226,081,443   233,428,609
                                                 ------------  ------------

                                                 $232,057,603  $237,980,449
                                                 ============  ============

--------------------------------------------------------------------------------
STATEMENTS OF DISTRIBUTABLE INCOME

                                               Year Ended December 31
                                             ---------------------------
                                                 2000           1999
                                             ------------   ------------

Royalty income.............................  $ 56,812,141   $ 33,139,662

Interest income............................       128,150         46,374
                                             ------------   ------------

 Total income..............................    56,940,291     33,186,036

Administration expense.....................       228,211         95,987
                                             ------------   ------------

 Distributable income......................  $ 56,712,080   $ 33,090,049
                                             ============   ============

 Distributable income per unit
  (40,000,000 units).......................  $   1.417802   $   0.827253
                                             ============   ============

--------------------------------------------------------------------------------

STATEMENTS OF CHANGES IN TRUST CORPUS

                                               Year Ended December 31
                                             ---------------------------
                                                 2000           1999
                                             ------------   ------------

Trust corpus, beginning of year............  $233,428,609   $247,067,951

Amortization of net profits interests......    (7,347,166)   (13,638,342)

Return of initial contribution to grantor..             -         (1,000)

Distributable income.......................    56,712,080     33,090,049

Distributions declared.....................   (56,712,080)   (33,090,049)
                                             ------------   ------------

Trust corpus, end of year..................  $226,081,443   $233,428,609
                                             ============   ============

--------------------------------------------------------------------------------

See Accompanying Notes to Financial Statements.

                                                                               8
<PAGE>

Hugoton  Royalty Trust
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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,
          -    gross 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 was $20,985,508 as of December 31, 2000
and was $13,638,342 as of December 31, 1999.

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, which is 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 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).

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     For monthly trust distributions declared through March 2000, the related
royalty income was 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). For the year ended
          December 31, 2000, there were no imputed proceeds because actual gas
          prices were higher than the $2.00 price support.

     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 was approximately $0.52 per MMBtu
($0.014499 per unit) in 2000 and $0.52 per MMBtu ($0.016093 per unit) in 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, 2000, the overhead charge was approximately
$615,000 ($492,000 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 54.3% 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 published 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 $0.317 per Mcf
compression and 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 to Cross Timbers' wholly
owned subsidiaries were $89.0 million for the year ended December 31, 2000, or
77% of total sales, and $55.9 million for the year ended December 31, 1999, or
77% of total sales.

6.   Litigation

     Cross Timbers is a defendant in three separate lawsuits that could, if
adversely determined, decrease future trust distributable income.  Any 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 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 potential settlement related to
the trust and reduction in net proceeds is not presently determinable, but, in

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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 ten 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 cases against Cross Timbers and other defendants have
been consolidated in the United States District Court for Wyoming. Cross Timbers
and other defendants have filed a motion to dismiss the lawsuit. The motion to
dismiss has been heard by the Court and a decision is pending. 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.

     A third lawsuit, Bishop, et al. v. Amoco Production Co., et al., was filed
in May 2000 in the Third Judicial District Court in Lincoln County, Wyoming by
owners of royalty and overriding royalty interests in wells located in Wyoming.
The plaintiffs alleged that Cross Timbers and the other producer defendants
deducted impermissible costs of production from royalty payments that were made
to the plaintiffs and other similarly situated persons, and failed to properly
inform the plaintiffs and others of the deductions taken. The action was brought
as a class action on behalf of all persons who own an interest in wells located
in Wyoming as to which the defendants pay royalties and overriding royalties.
The plaintiffs sought a declaratory judgment that the deductions made were
impermissible and sought damages in the amount of the deductions made together
with interest and attorneys' fees. Cross Timbers has reached a settlement in
this action, which is subject to court approval. Cross Timbers will receive a
release of claims relating to deductions taken, the statutory reporting of
claims, and other miscellaneous matters. Cross Timbers agreed not to take
similar deductions in the future and to itemize other deductions from future
royalty disbursements. Cross Timbers expects the court will approve the
settlement in April 2001. The trust's portion of the settlement is expected to
be less than $200,000.

     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 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 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 2000 and 1999:


                                                     Distributable
                            Royalty    Distributable     Income
                            Income        Income        per Unit
                         -----------  -------------  -------------
2000
----
First Quarter........    $10,981,680    $10,939,280      $0.273482
Second Quarter.......     11,288,646     11,264,480       0.281612
Third Quarter........     16,250,348     16,196,440       0.404911
Fourth Quarter.......     18,291,467     18,311,880       0.457797
                         -----------    -----------      ---------
                         $56,812,141    $56,712,080      $1.417802
                         ===========    ===========      =========

1999
----
First Quarter........    $ 3,565,075    $ 3,562,075      $0.089052
Second Quarter.......      8,854,991      8,833,454       0.220838
Third Quarter........      8,541,670      8,528,320       0.213208
Fourth Quarter.......     12,177,926     12,166,200       0.304155
                         -----------    -----------      ---------
                         $33,139,662    $33,090,049      $0.827253
                         ===========    ===========      =========


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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, 2000 and 1999, and
the statements of distributable income and changes in trust corpus for each of
the years then ended. 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 accounting principles generally
accepted in the United States.

     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, 2000 and 1999 and its distributable income and changes in
trust corpus for each of the years then ended, in conformity with the modified
cash basis of accounting described in Note 2.

/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP

Fort Worth, Texas
March 19, 2001

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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
----------------------------

Mellon Investor Services, L.L.C.
Dallas, Texas
www.melloninvestor.com