<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