<PAGE>

                                                                      EXHIBIT 13

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)

                      MMBtu    One million British Thermal Units, a common
                               energy measurement

               net proceeds    Gross proceeds received by XTO Energy from sale
                               of production from the underlying properties,
                               less applicable costs, as defined in the net
                               profits interest conveyances

         net profits income    Net proceeds multiplied by the applicable net
                               profits percentage of 75% or 90% and paid to the
                               trust by XTO Energy. "Net profits income" is
                               referred to as "royalty income" for income tax
                               purposes.

       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. The
                               following defined net profits interests were
                               conveyed to the trust from the underlying
                               properties:

                               90% net profits interests - interests that
                               entitle the trust to receive 90% of the net
                               proceeds from the underlying properties that are
                               royalty or overriding royalty interests in Texas,
                               Oklahoma and New Mexico

                               75% net profits interests - interests that
                               entitle the trust to receive 75% of the net
                               proceeds from the underlying properties that are
                               working interests in Texas and Oklahoma

           royalty interest    A nonoperating interest in an oil and gas
    (and overriding royalty    property that provides the owner a specified
                  interest)    share of production without any production or
                               development costs

      underlying properties    XTO Energy's interest in certain oil and gas
                               properties from which the net profits interests
                               were conveyed. The underlying properties include
                               royalty and overriding royalty interests in
                               producing and nonproducing properties in Texas,
                               Oklahoma and New Mexico, and working interests in
                               producing properties located in Texas and
                               Oklahoma.

           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

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 that are subject
to a number of risks and uncertainties which are detailed in Part II, Item 7 of
the accompanying Form 10-K. Although XTO Energy and the trustee believe that the
expectations reflected in such forward-looking statements are reasonable,
neither XTO Energy nor the trustee can give any assurance that such expectations
will prove to be correct.

<PAGE>

THE TRUST

Cross Timbers Royalty Trust was created on February 12, 1991 by conveyance of
90% net profits interests in certain royalty and overriding royalty interest
properties in Texas, Oklahoma and New Mexico, and 75% net profits interests in
certain working interest properties in Texas and Oklahoma. XTO Energy Inc. owns
the underlying properties from which these net profits interests were conveyed.
The net profits interests are the only assets of the trust, other than cash held
for trust expenses and for distribution to unitholders.

Net profits income received by the trust on the last business day of each month
is calculated and paid by XTO Energy 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 are listed and traded on the New
York Stock Exchange under the symbol "CRT." The following are the high and low
unit sales prices and total cash distributions per unit paid by the trust during
each quarter of 2002 and 2001:

                                            Sales Price        Distributions
                                       -------------------     -------------
  Quarter                                 High       Low          per Unit
----------------------------------     --------    -------     -------------
  2002
----------------------------------
First ..............................   $  19.50    $ 16.90     $    0.300791
Second .............................      19.40      15.00          0.287258
Third ..............................      18.03      14.50          0.415739
Fourth .............................      20.23      17.00          0.466597
                                                               -------------
                                                               $    1.470385
                                                               =============

  2001
----------------------------------
First ..............................   $  18.95    $ 15.50     $    0.674817
Second .............................      23.20      15.25          0.696495
Third ..............................      20.05      15.23          0.566440
Fourth .............................      18.80      15.05          0.430562
                                                                ------------
                                                                $   2.368314
                                                                ============

At December 31, 2002, there were 6,000,000 units outstanding and approximately
175 unitholders of record; 5,667,175 of these units were held by depository
institutions. As of March 3, 2003, XTO Energy owned 1,360,000 units.

                                                                               1

<PAGE>

SUMMARY

The trust was created to collect and distribute monthly net profits income to
unitholders. Trust net profits income is received from two major components, the
90% net profits interests and the 75% net profits interests.

     -   The 90% net profits interests were conveyed from underlying royalty and
         overriding royalty interests in producing properties in Texas, Oklahoma
         and New Mexico. Most net profits income is from long-lived gas
         properties in the San Juan Basin of northwestern New Mexico. Because
         the 90% net profits interests are not subject to production or
         development costs, net profits income from these interests generally
         only varies because of changes in sales volumes or prices.

     -   The 75% net profits interests were conveyed from underlying working
         interests in seven large, predominantly oil-producing properties in
         Texas and Oklahoma. Net profits income from these properties is reduced
         by production and development costs. If costs exceed revenues from the
         underlying working interest properties in either Texas or Oklahoma, the
         75% net profits interests for that state will not contribute to trust
         net profits 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 net profits income from the other 75% net
         profits interests or from the 90% net profits interests. Because of
         excess costs, the Texas 75% net profits interests did not contribute to
         trust net profits income from February through April 2002 and January
         through April 2000. Such excess costs generally occur during periods of
         higher development activity and/or lower oil prices. For further
         information, see "Trustee's Discussion and Analysis - Years Ended
         December 31, 2002, 2001 and 2000 - Costs."

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 coal seam gas
         production through 2002 from wells drilled on the properties underlying
         the 90% net profits interests after December 31, 1979 and prior to
         January 1, 1993. Unitholders are entitled to this tax credit (also
         referred to as "coal seam tax credit") which may be used to reduce the
         unitholder's regular income tax liability, but not below his tentative
         minimum tax. Congress has considered extending this credit beyond the
         December 31, 2002 expiration date, and the creation of similar new tax
         credits. Unless new legislation is passed, extending this credit on
         existing eligible production or allowing for credits on new production,
         there will be no further benefit on production past the year 2002.

     -   Cost Depletion is generally available to unitholders as a deduction
         from net profits income. Available depletion is dependent upon the
         unitholder's cost of units, purchase date and prior allowable
         depletion. It may be more beneficial for unitholders to deduct
         percentage depletion. Unitholders should consult their tax advisors for
         further information.

           As an example, a unitholder that acquired units in January
           2002 and held them throughout 2002 would be entitled to a
           cost depletion deduction of approximately 9% of his cost.
           Assuming a cost of $18.00 per unit, cost depletion would
           completely offset 2002 taxable trust income. After
           considering the coal seam tax credit and assuming a 30% tax
           rate, the 2002 taxable equivalent return as a percentage of
           unit cost would be 13%. Excluding the effect of the coal
           seam tax credit, the taxable equivalent return was 12%.
           (NOTE- Because the units are a depleting asset, a portion
           of this return is effectively a return of capital.)

The following table summarizes the effect of the above components on
distributions per unit for the last three years:

<TABLE>
<CAPTION>
                                               2002                    2001                      2000
                                      ---------------------   ----------------------    --------------------
                                       Monthly      Annual     Monthly      Annual       Monthly     Annual
                                       Average       Total     Average       Total       Average      Total
                                      ---------    --------   ---------    ---------    ---------   --------
<S>                                   <C>          <C>        <C>          <C>          <C>         <C>
Net profits income:
- 90% net profits interests ........  $  0.109     $ 1.302    $ 0.178      $  2.130     $  0.129     $ 1.550

- 75% net profits interests ........     0.017       0.206      0.022         0.268        0.033       0.393

Administration expense
  (net of interest income) .........    (0.003)     (0.038)    (0.003)       (0.030)      (0.002)     (0.026)
                                      --------     -------    -------      --------     --------     -------
Total Distribution .................  $  0.123     $ 1.470    $ 0.197      $  2.368     $  0.160     $ 1.917
                                      ========     =======    =======      ========     ========     =======
Nonconventional Fuel
     Source Tax Credit .............       *       $ 0.082        *        $  0.107          *       $ 0.120
                                                   =======                 ========                  =======
</TABLE>

* - Not applicable

                                                                               2

<PAGE>

TO UNITHOLDERS

We are pleased to present the 2002 Annual Report of Cross Timbers Royalty Trust
and Form 10-K. Both reports contain important information about the trust's net
profits interests, including information provided to the trustee by XTO Energy,
and should be read in conjunction with each other.

For the year ended December 31, 2002, net profits income totaled $9,049,271.
After deducting trust administration expense and adding interest income,
distributable income was $8,822,310, or $1.470385 per unit. Distributions for
the year were lower than in 2001 primarily because of lower average gas prices.

Natural gas prices for 2002 averaged $2.79 per Mcf for sales from the underlying
properties, a 45% decrease from the 2001 average price of $5.09 per Mcf. Gas
sales volumes from the underlying properties for the year ended December 31,
2002 totaled 3,029,949 Mcf, or 8,301 Mcf per day, a 3% increase from 2001
production of 2,932,203 Mcf, or 8,033 Mcf per day. Gas volumes were higher
primarily because of a one-time correction of the trust's interest in properties
that were nonproducing at the trust's inception.

Oil sales volumes from the underlying properties during 2002 were 338,975 Bbls,
or 929 Bbls per day, a 3% decrease from 2001 levels of 350,691 Bbls, or 961 Bbls
per day. The average oil price decreased to $22.31 per Bbl, down 11% from the
2001 average price of $24.99.

Coal seam gas sales volumes from the underlying properties were 580,141 Mcf in
2002, or a 22% decline from 2001 coal seam gas production of 744,092 Mcf. Coal
seam gas sales volumes are lower because of natural production decline and an
adjustment in 2002 related to previously misclassified coal seam volumes.
Excluding the effect of this adjustment, 2002 coal seam production declined by
10%. The resulting 2002 coal seam tax credit was $0.081581 per unit. This credit
(or a portion thereof, if units were held less than the full year) is available
to be applied against a 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, 2002, proved reserves of the net profits interests were
estimated by independent engineers to be 1,716,000 Bbls of oil and 31.1 Bcf of
natural gas. Estimated oil reserves increased 32% from year-end 2001 to 2002
primarily because of higher year-end oil prices. Gas reserves decreased 2% from
year-end 2001 to 2002 primarily because of production. All reserve information
prepared by independent engineers has been provided to the trustee by XTO
Energy.

Estimated future net cash flows from proved reserves of the net profits
interests at December 31, 2002 are $164.1 million, or $27.35 per unit. Using an
annual discount factor of 10%, the present value of estimated future net cash
flows at December 31, 2002 is $80.0 million, or $13.33 per unit. Proved reserve
estimates and related future net cash flows have been determined based on a
year-end West Texas Intermediate posted oil price of $28.00 per barrel and a
year-end average realized gas price of $4.06 per Mcf. Other guidelines used in
estimating proved reserves, as prescribed by the Financial Accounting Standards
Board, are described under Item 2 of the accompanying Form 10-K. The present
value of estimated future net cash flows is not indicative of the market value
of trust units.

As discussed in the tax instructions provided to unitholders in February 2003,
trust distributions are considered portfolio income, rather than passive income.
Unitholders should consult their tax advisors for further information.

Cross Timbers Royalty Trust
By:  Bank of America, N.A., Trustee

By:  Nancy G. Willis
     Assistant Vice President

                                                                               3

<PAGE>

THE UNDERLYING PROPERTIES

The underlying properties include over 2,900 producing properties with
established production histories in Texas, Oklahoma and New Mexico. The average
reserve-to-production index for the underlying properties as of December 31,
2002 is approximately 12 years. This index is calculated using total proved
reserves and estimated 2003 production for the underlying properties. Based on
estimated future net cash flows at year-end oil and gas prices, the proved
reserves of the underlying properties are approximately 29% oil and 71% natural
gas. The underlying properties also include certain nonproducing properties in
Texas, Oklahoma and New Mexico that are primarily mineral interests. XTO Energy
cannot significantly influence or control the operations of the underlying
properties.

90% Net Profits Interests

Royalty and overriding royalty properties underlying the 90% net profits
interests represent 80% of the discounted future net cash flows from trust
proved reserves at December 31, 2002. Approximately 87% of the discounted future
net cash flows from the 90% net profits interests is from gas reserves, totaling
30.6 Bcf. Oil reserves underlying the 90% net profits interests are primarily
located in West Texas and are estimated to be 645,000 Bbls at December 31, 2002.

Because the properties underlying the 90% net profits interests are royalty
interests and overriding royalty interests, net profits income from these
properties is not reduced by production and development costs. Additionally, net
profits income from these interests cannot be reduced by any excess costs of the
75% net profits interests. The trust, therefore, should generally receive
monthly net profits income from these interests, as determined by oil and gas
sales volumes and prices.

Most of the trust's gas reserves are located in the San Juan Basin of
northwestern New Mexico, one of the largest domestic gas fields. The San Juan
Basin royalties produced approximately 72% of gas sales volumes and 50% of net
profits income for 2002. As of December 31, 2002, trust proved reserves in this
region are estimated to be 24.9 Bcf, or 80% of total trust gas reserves.

Approximately 20% of trust 2002 gas sales volumes were from coal seam production
in the San Juan Basin. Through the year 2002, sales of production from coal seam
wells drilled after December 31, 1979 and prior to January 1, 1993 qualify for a
federal income tax credit under Section 29 of the Internal Revenue Code for
nonconventional fuel sources. This credit for 2002 coal seam gas sales was
approximately $1.10 per MMBtu or $0.081581 per unit, while the coal seam credit
for 2001 was $1.08 per MMBtu or $0.107183 per unit.

Congress has considered extending this credit beyond the December 31, 2002
expiration date, and the creation of similar new tax credits. Unless new
legislation is passed, extending this credit on existing eligible production or
allowing for credits on new production, there will be no further benefit on
production past the year 2002.

In October 2002, regulatory authorities approved increasing the density of coal
seam wells drilled in the San Juan Basin from 320 acres to 160 acres on a
significant portion of the trust's acreage. XTO Energy Inc. has informed the
trustee that it believes most operators of the related properties will pursue
such increased density drilling. However, there can be no assurance that any
potential development will significantly affect the trust.

Most of the trust's San Juan Basin conventional, or non-coal seam, gas is
produced from the Mesaverde formation. This formation has been approved for
increased density drilling, doubling the number of drill wells allowed to four
per spacing unit. XTO Energy has advised the trustee that it believes operators
will further develop the Mesaverde formation underlying the net profits
interests, and such future development could significantly impact underlying gas
sales volumes. Mesaverde drilling increased in 2002, after drilling permits were
delayed in 2001 because of environmental concerns.

75% Net Profits Interests

Underlying the 75% net profits interests are working interests in seven large
properties in Texas and Oklahoma operated primarily by established oil
companies. These properties are located in mature fields undergoing secondary or
tertiary recovery operations. With its relatively minor working interest, XTO
Energy generally has little influence or control over operations on any of these
properties.

Proved reserves from the 75% net profits interests are almost entirely oil,
estimated to be approximately 1,071,000 Bbls at year-end 2002. Based on year-end
oil and gas prices, proved reserves from these interests represent 20% of the
discounted future net cash flows of the trust's proved reserves at December 31,
2002.

Because these underlying properties are working interests, production and
development costs are deducted in calculating net profits income from the 75%
net profits interests. As a result, net profits income from these interests is
affected by the level of maintenance and development activity on these
underlying properties. Net profits income is also dependent upon oil and gas
sales volumes and prices and is subject to reduction for any prior period excess
costs.

Total 2002 development costs were $571,680, down 50% from 2001 development costs
of $1,133,869. First quarter 2003 development costs totaled approximately
$50,000; these costs are primarily related to fourth quarter 2002 expenditures.

As reported to XTO Energy by unit operators in February of each year, budgeted
development costs were $417,000 for 2002 and $896,000 for

                                                                               4

<PAGE>

2001. Actual development costs often differ from amounts budgeted because of
changes in product prices that may affect the timing of projects. Also, costs
are deducted in the calculation of trust net profits income several months after
they are incurred by the operator. Unit operators have reported total budgeted
costs, net to XTO Energy's interests, of approximately $242,000 for 2003 and
$236,000 for 2004.

In first quarter 2002, total excess costs and accrued interest of $67,484 were
incurred on the Texas 75% net profits interests as a result of lower oil prices.
There were no excess costs in 2001. For information regarding the effect of
excess costs on trust net profits income, see "Trustee's Discussion and Analysis
- Years Ended December 31, 2002, 2001 and 2000 - Costs."


Estimated Proved Reserves and Future Net Cash Flows

The following are proved reserves of the underlying properties and proved
reserves and future net cash flows from proved reserves of the net profits
interests at December 31, 2002, as estimated by independent engineers:

<TABLE>
<CAPTION>
                                   Underlying Properties                     Net Profits Interests
                                 -------------------------  -------------------------------------------------------
                                    Proved Reserves (a)      Proved Reserves (a) (b)     Future Net Cash Flows
                                 -------------------------  -------------------------
                                      Oil          Gas          Oil          Gas       from Proved Reserves (a) (c)
                                                                                     -------------------------------
(in thousands)                       (Bbls)       (Mcf)       (Bbls)        (Mcf)    Undiscounted      Discounted
                                 -----------   -----------  -----------  ----------- ------------    --------------
<S>                              <C>           <C>          <C>          <C>         <C>             <C>
90% Net Profits Interests
  San Juan Basin
    Conventional ..............           64      23,802            58       21,422   $      82,006  $       34,837
    Coal Seam .................            -       3,865             -        3,478          10,526           6,914
                                   ---------   ---------   -----------   ----------   -------------  --------------
       Total ..................           64      27,667            58       24,900          92,532          41,751
  Other New Mexico ............          122         284           109          263           4,105           2,336
  Texas .......................          458       3,753           412        3,380          26,870          14,370
  Oklahoma ....................           73       2,330            66        2,068          10,342           5,480
                                   ---------   ---------   -----------   ----------   -------------  --------------
       Total ..................          717      34,034           645       30,611         133,849          63,937
                                   ---------   ---------   -----------   ----------   -------------  --------------

75% Net Profits Interests
  Texas .......................        1,640         865           690          365          20,160           9,927
  Oklahoma ....................        1,300         398           381          116          10,102           6,127
                                   ---------   ---------   -----------   ----------   -------------  --------------
       Total ..................        2,940       1,263         1,071          481          30,262          16,054
                                   ---------   ---------   -----------   ----------   -------------  --------------

       TOTAL ..................        3,657      35,297         1,716       31,092   $     164,111  $       79,991
                                   =========   =========   ===========   ==========   =============  ==============
</TABLE>

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

(a)  Based on year-end oil and gas prices. Discounted estimated future net cash
     flows from proved reserves increased 82% from year-end 2001 to 2002,
     primarily because of a 78% increase in year-end gas prices over these
     periods. 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 since future net cash flows are not subject to taxation
     at the trust level.

5

<PAGE>

TRUSTEE'S DISCUSSION AND ANALYSIS

Years Ended December 31, 2002, 2001 and 2000

Net profits income for 2002 was $9,049,271, as compared with $14,389,316 for
2001 and $11,660,510 for 2000. The 37% decrease in net profits income from 2001
to 2002 was because of lower product prices. The 23% increase in net profits
income from 2000 to 2001 was because of higher average gas prices. During 2002,
2001 and 2000, 67%, 77% and 64%, respectively, of net profits income was derived
from gas sales.

Trust administration expense was $231,447 in 2002 as compared to $198,482 in
2001 and $185,624 in 2000. The 17% increase in administration expense from 2001
to 2002 was primarily because of the timing of expenditures. Interest income was
$4,486 in 2002, $19,050 in 2001 and $27,228 in 2000. The 76% decrease in
interest income from 2001 to 2002 was because of the decrease in net profits
income and interest rates.

Net profits income is recorded when received by the trust, which is the month
following receipt by XTO Energy, and generally two months after oil production
and three months after gas production. Net profits 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 net profits income.

Volumes

Oil. Underlying oil sales volumes decreased 3% from 2001 to 2002, as compared to
a 2% increase from 2000 to 2001. Sales volume decreases in 2002 were primarily
because of natural production decline. Sales volume increases in 2001 were
because of the timing of cash receipts partially offset by production decline.

Gas. Underlying gas sales volumes increased 3% from 2001 to 2002 as compared to
a 5% decrease from 2000 to 2001. Higher 2002 gas sales volumes were primarily
because of a one-time correction of the trust's interest in properties that were
nonproducing at the trust's inception. Lower 2001 gas sales volumes were
primarily because of coal seam gas production decline.

Prices

Oil. The average oil price for 2002 was $22.31 per Bbl, 11% lower than the 2001
average oil price of $24.99, which was 9% lower than the 2000 average price of
$27.49. The West Texas Intermediate ("WTI") posted price reached $34.25 per Bbl
in September 2000, then its highest level in ten years. Lagging demand,
resulting from a worldwide economic slowdown, caused oil prices to decline
during 2001. OPEC members agreed to cut daily production by one million barrels
in April 2001 and an additional one million barrels in September 2001 to adjust
for weak demand and excess supply. The economic decline was accelerated by the
terrorist attacks in the U.S. on September 11, 2001, placing additional downward
pressure on oil prices. OPEC cut an additional 1.5 million barrels per day
during 2002. Oil prices increased during 2002 largely because of OPEC production
discipline and rising uncertainty surrounding the Middle East. OPEC members
agreed to increase daily oil production 1.5 million barrels beginning February
1, 2003, to help stabilize a volatile world market. However, with continuing
threat of war in Iraq, oil prices are expected to remain volatile. The average
WTI posted price for January and February 2003 was $30.95, compared with $22.90
for the year 2002 and $24.99 for fourth quarter 2002. Oil prices have risen in
March 2003 to an average WTI posted price of about $33.63 through March 14.
Recent trust oil prices have averaged approximately $0.80 higher than the WTI
posted price.

Gas. The 2002 average gas price was $2.79 per Mcf, a 45% decrease from the 2001
average gas price of $5.09, which was a 53% increase from the 2000 average price
of $3.32. At the beginning of 2000, NYMEX gas prices approximated $2.30 per
MMBtu. Gas prices strengthened in 2000 reaching a record high of $10.10 per
MMBtu in December 2000 as winter demand strained gas supplies. Prices
subsequently declined in 2001 because of fuel switching due to higher prices,
milder weather and a weaker economy, which reduced demand for gas to generate
electricity. As of December 31, 2001, the NYMEX gas price was $2.57 per MMBtu.
Despite the winter of 2001-2002 being one of the warmest on record and higher
than average gas storage levels, gas prices gradually climbed in 2002 as a
result of low levels of drilling activity, increased industrial demand, colder
weather in late 2002 and international instability. With colder than normal
weather and seasonally low gas storage levels, gas prices have continued to rise
in 2003. The average NYMEX price for January and February 2003 was $5.97 per
MMBtu. Gas prices have risen in March 2003 to an average NYMEX price of $6.49
through March 14.

The trust's average gas price for December 2002 gas sales was approximately
$0.40 per MMBtu lower than the NYMEX price because of lower West Coast demand
for San Juan Basin gas. In early March 2003, the San Juan Basin index price was
approximately $3.00 lower than the NYMEX price of $9.00, which was elevated
because gas supplies to the northeast U.S. were strained from severe winter
weather.

Costs

Because properties underlying the 90% net profits interests are royalty and
overriding royalty interests, the calculation of net profits income from these
interests only includes deductions for production and

                                                           (Continued on page 8)

                                                                               6

<PAGE>

Calculation of Net Profits Income

The following is a summary of the calculation of net profits income received by
the trust:

<TABLE>
<CAPTION>
                                                                                                    Three Months
                                                     Year Ended December 31 (a)                 Ended December 31 (a)
                                             -------------------------------------------      --------------------------
                                                 2002           2001            2000             2002           2001
                                             ------------   ------------    ------------      -----------    -----------
<S>                                          <C>            <C>             <C>               <C>            <C>
Sales Volumes
   Oil (Bbls) (b)
     Underlying properties ...............        338,975        350,691         344,123           91,392         98,786
          Average per day ................            929            961             940              993          1,074
     Net profits interests ...............        138,249        145,678         163,219           47,382         49,341

   Gas (Mcf) (b)
     Underlying properties ...............      3,029,949      2,932,203       3,080,601          777,650        776,281
          Average per day ................          8,301          8,033           8,417            8,453          8,438
     Net profits interests ...............      2,648,794      2,552,207       2,689,259          682,936        669,272

Average Sales Price
   Oil (per Bbl) .........................   $      22.31   $      24.99    $      27.49      $     26.31    $     22.74
   Gas (per Mcf) .........................   $       2.79   $       5.09    $       3.32      $      3.00    $      3.00

Revenues
   Oil sales .............................   $  7,564,177   $  8,763,283    $  9,459,575      $ 2,404,515    $ 2,246,178
   Gas sales .............................      8,462,810     14,922,881      10,231,063        2,332,654      2,329,339
                                             ------------   ------------    ------------      -----------    -----------
     Total Revenues ......................     16,026,987     23,686,164      19,690,638        4,737,169      4,575,517
                                             ------------   ------------    ------------      -----------    -----------

Costs
   Taxes, transportation
      and other ..........................      2,110,506      3,298,631       2,566,816          656,925        691,398
   Production expense (c) ................      3,014,706      2,908,305       2,520,954          752,882        731,502
   Development costs .....................        571,680      1,133,869         738,605           65,117        163,208
   Excess costs ..........................        (66,867)             -               -                -              -
   Recovery of excess costs
     and accrued interest ................         67,484              -         383,836                -              -
                                             ------------   ------------    ------------      -----------    -----------
     Total Costs .........................      5,697,509      7,340,805       6,210,211        1,474,924      1,586,108
                                             ------------   ------------    ------------      -----------    -----------

Net Proceeds .............................   $ 10,329,478   $ 16,345,359    $ 13,480,427      $ 3,262,245    $ 2,989,409
                                             ============   ============    ============      ===========    ===========
Net Profits Income .......................   $  9,049,271   $ 14,389,316    $ 11,660,510      $ 2,827,239    $ 2,609,358
                                             ============   ============    ============      ===========    ===========
</TABLE>

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

  (a) Because of the interval between time of production and receipt of net
      profits income by the trust, oil and gas sales for the year ended December
      31 generally relate to oil production from November through October and
      gas production from October through September, while oil and gas sales for
      the three months ended December 31 generally relate to oil production from
      August through October and gas production from July through September.

  (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 is based on the
      underlying properties.

  (c) Includes an overhead fee deducted and retained by XTO Energy. As of
      December 31, 2002, this fee was $23,470 per month and is subject to
      adjustment each May based on an oil and gas industry index.

                                                                               7

<PAGE>

property taxes, legal costs, and marketing and transportation charges. In
addition to these costs, the calculation of net profits income from the 75% net
profits interests includes deductions for production and development costs since
the related underlying properties are working interests. Net profits income is
calculated monthly for each of the five conveyances under which the net profits
interests were conveyed to the trust. If monthly costs exceed revenues for any
conveyance, such excess costs must be recovered, with accrued interest, from
future net proceeds of that conveyance and cannot reduce net profits income from
other conveyances.

Before adjustment for excess costs (see "Excess Costs" below), total costs
deducted in the calculation of net profits income were $5.7 million in 2002,
$7.3 million in 2001 and $5.8 million in 2000. The 22% decrease in costs from
2001 to 2002 is primarily attributable to lower development costs and lower
production and property taxes associated with decreased revenues. The 26%
increase in costs from 2000 to 2001 is primarily attributable to increased
production and property tax and other purchaser deductions associated with
higher revenues. In 2002, lower development costs are related to reduced
tertiary injectant cost and drilling activity. In 2001, higher development costs
are related to wells drilled on two of the underlying properties and increased
production expense is related to the timing of maintenance projects and higher
power and fuel costs.

Excess Costs

During February and March 2002, costs exceeded revenues by $66,867 ($50,150 net
to the trust) for the Texas 75% net profits interests as a result of lower oil
prices. Total excess costs and accrued interest of $67,484 ($50,613 net to the
trust) were fully recovered in April and May 2002. There were no excess costs or
related recoveries after May 2002 or in 2001.

See Note 5 to Financial Statements.

Fourth Quarter 2002 and 2001

During the quarter ended December 31, 2002, the trust received net profits
income totaling $2,827,239, compared with fourth quarter 2001 net profits income
of $2,609,358. The 8% increase in net profits income from fourth quarter 2001 to
2002 was primarily because of higher average oil prices.

Administration expense was $28,815 and interest income was $1,158, resulting in
fourth quarter 2002 distributable income of $2,799,582, or $0.466597 per unit.
Distributable income for fourth quarter 2001 was $2,583,372, or $0.430562 per
unit. Distributions to unitholders for the quarter ended December 31, 2002 were:

              Record Date            Payment Date              Per Unit
           -----------------       -----------------         -----------
           October 31, 2002        November 15, 2002         $  0.118985
           November 29, 2002       December 13, 2002            0.139397
           December 31, 2002       January 15, 2003             0.208215
                                                             -----------
                                                             $  0.466597
                                                             ===========

Volumes

Fourth quarter 2002 underlying oil sales volumes were 91,392 Bbls, or 7% lower
than 2001 levels. Oil sales volumes decreased in 2002 because of natural
production decline and prior period volume adjustments. Underlying gas sales
volumes were 777,650 Mcf, or flat with 2001 levels. Fourth quarter 2002 volumes
included additional volumes from a one-time correction of the trust's interests
in properties that were nonproducing at the trust's inception. Excluding this
correction, fourth quarter underlying volumes decreased 16% because of natural
production decline and prior period volume adjustments recorded in 2002.

Prices

The average fourth quarter 2002 oil price was $26.31 per Bbl, 16% higher than
the fourth quarter 2001 average price of $22.74. The average fourth quarter gas
price for 2002 and 2001 was $3.00 per Mcf. For further information about oil and
gas prices, see "Years Ended December 31, 2002, 2001 and 2000 - Prices" above.

Costs

Costs deducted in the calculation of fourth quarter 2002 net profits income
decreased $111,184, or 7%, from fourth quarter 2001. This decrease was the
result of lower property taxes and reduced development activity.

See Item 7 of the accompanying Form 10-K for disclosures regarding liquidity and
capital resources, contractual obligations and commitments, related party
transactions and critical accounting policies of the trust. See Item 7a of the
accompanying Form 10-K for quantitative and qualitative disclosures about market
risk affecting the trust.

                                                                               8

<PAGE>

CROSS TIMBERS ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

<TABLE>
<CAPTION>

                                                                             December 31
                                                                      2002                 2001
                                                                 ---------------      ---------------
<S>                                                              <C>                  <C>
Assets

  Cash and short-term investments ...........................    $     1,248,735      $       852,349

  Interest to be received ...................................                555                  479

  Net profits interests in oil and gas properties - net
    (Notes 1 and 2) .........................................         26,556,533           28,895,086
                                                                 ---------------      ---------------
                                                                 $    27,805,823      $    29,747,914
                                                                 ===============      ===============

Liabilities and Trust Corpus

  Distribution payable to unitholders .......................    $     1,249,290      $       852,828

  Trust corpus (6,000,000 units of beneficial
     interest authorized and outstanding) ...................         26,556,533           28,895,086
                                                                 ---------------      ---------------
                                                                 $    27,805,823      $    29,747,914
                                                                 ===============      ===============
</TABLE>

STATEMENTS OF DISTRIBUTABLE INCOME

<TABLE>
<CAPTION>
                                                             Year Ended December 31
                                            ---------------------------------------------------------
                                                  2002                2001                 2000
                                            ---------------      ---------------      ---------------
<S>                                         <C>                  <C>                  <C>
Net profits income .....................    $     9,049,271      $    14,389,316      $    11,660,510

Interest income ........................              4,486               19,050               27,228
                                            ---------------      ---------------      ---------------

  Total income .........................          9,053,757           14,408,366           11,687,738

Administration expense .................            231,447              198,482              185,624
                                            ---------------      ---------------      ---------------

  Distributable income .................    $     8,822,310      $    14,209,884      $    11,502,114
                                            ===============      ===============      ===============
  Distributable income per unit
    (6,000,000 units) ..................    $      1.470385      $      2.368314      $      1.917019
                                            ===============      ===============      ===============
</TABLE>

STATEMENTS OF CHANGES IN TRUST CORPUS

<TABLE>
<CAPTION>
                                                             Year Ended December 31
                                            ---------------------------------------------------------
                                                  2002                  2001               2000
                                            ---------------       ---------------     ---------------

<S>                                         <C>                   <C>                 <C>
Trust corpus, beginning of year ........    $    28,895,086       $    30,755,456     $    33,005,334

Amortization of net profits
  interests ............................         (2,338,553)           (1,860,370)         (2,249,878)

Distributable income ...................          8,822,310            14,209,884          11,502,114

Distributions declared .................         (8,822,310)          (14,209,884)        (11,502,114)
                                            ---------------       ---------------     ---------------
Trust corpus, end of year ..............    $    26,556,533       $    28,895,086     $    30,755,456
                                            ===============       ===============     ===============
</TABLE>

See Accompanying Notes to Financial Statements.

                                                                               9

<PAGE>

NOTES TO FINANCIAL STATEMENTS

1.  Trust Organization and Provisions

    Cross Timbers Royalty Trust was created on February 12, 1991 by predecessors
of XTO Energy Inc., when the following net profits interests were conveyed under
five separate conveyances to the trust effective October 1, 1990, in exchange
for 6,000,000 units of beneficial interest in the trust:

    -    90% net profits interests in certain producing and nonproducing royalty
         interest properties in Texas, Oklahoma and New Mexico, and
    -    75% net profits interests in certain nonoperated working interest
         properties in Texas and Oklahoma.

    The underlying properties from which the net profits interests were carved
are currently owned by XTO Energy. Bank of America, N.A. is the trustee of the
trust. The trust indenture provides, among other provisions, that:

    -    the trust may not engage in any business activity or acquire any assets
         other than the net profits interests and specific short-term cash
         investments;
    -    the trust may not dispose of all or part of the net profits interests
         unless approved by 80% of the unitholders, or upon trust termination,
         and 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 required to pay trust liabilities if fully
         repaid 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 revenue of the trust is less than $1 million per year for two
             successive years, 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:

    -    Net profits income is recorded in the month received by the trustee
         (Note 3).
    -    Interest income, interest to be received and distribution payable to
         unitholders include interest to be earned on net profits income from
         the monthly record date (last business day of the month) through the
         date of the next distribution.
    -    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:

    -    Net profits 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 certain
         contingencies that would not be recorded under generally accepted
         accounting principles.

    The initial carrying value of the net profits interests of $61,100,449 was
XTO Energy's historical net book value of the interests on February 12, 1991,
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 $34,543,916 as of December 31, 2002 and
$32,205,363 as of December 31, 2001.

3.  Distributions to Unitholders

    The trustee determines the amount to be distributed to unitholders each
month by totaling net profits income and other cash receipts, and subtracting
liabilities paid and adjustments in cash reserves established by the trustee.
The resulting amount (with estimated interest to be received on such amount
through the distribution date) is distributed to unitholders of record within
ten business days after the monthly record date, the last business day of the
month.

    Net profits income received by the trustee consists of net proceeds received
in the prior month by XTO Energy from the underlying properties multiplied by
the net profits percentage of 90% or 75%. Net proceeds are the gross proceeds
received from the sale of production, less applicable costs. For the 90% net
profits interests, such costs generally include applicable taxes,
transportation, legal and marketing charges, and do not include other production
and development costs. For the 75% net profits interests, such costs include
production costs, development and drilling costs, applicable taxes, operating
charges and other costs.

    XTO Energy, as owner of the underlying properties, computes net profits
income separately for each of the five conveyances (Note 1). If costs exceed
gross proceeds for any conveyance, such excess costs cannot be used to reduce
the amounts to be received under the other conveyances. The trust is not liable
for excess costs; however, future net profits income from the net profits
interests created by that conveyance will be reduced by such excess costs plus
accrued interest. See Note 5.

                                                                              10

<PAGE>

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 trust 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.

XTO Energy has advised the trustee that the trust receives net profits income
from coal seam gas wells. Production through 2002 from coal seam gas wells
drilled between December 31, 1979 and January 1, 1993 qualifies for the federal
income tax credit for producing nonconventional fuels under Section 29 of the
Internal Revenue Code. This tax credit was approximately $1.10 per MMBtu
($0.081581 per unit) in 2002, $1.08 per MMBtu ($0.107183 per unit) in 2001 and
$1.06 per MMBtu ($0.120389 per unit) in 2000. This credit, based on the
unitholder's pro rata share of qualifying production, may not reduce the
unitholder's regular tax liability (after the foreign tax credit and certain
other nonrefundable credits) below his tentative minimum tax. Any part of the
Section 29 credit not allowed for the tax year solely because of this limitation
may be carried over indefinitely as a credit against the unitholder's regular
tax liability, subject to the tentative minimum tax limitation.

Congress has considered extending this credit beyond the December 31, 2002
expiration date, and the creation of similar new tax credits. Unless new
legislation is passed, extending this credit on existing eligible production or
allowing for credits on new production, there will be no further benefit on
production past the year 2002.

5.  Excess Costs

XTO Energy has advised the trustee that costs exceeded revenues by $66,867 from
the underlying properties of the Texas 75% net profits interests during February
and March 2002, which, with accrued interest of $617, were recovered in April
and May 2002. There were no excess costs or recoveries in 2001. Excess costs and
accrued interest for each conveyance must be fully recovered from the respective
future net proceeds of the 75% net profits interests before they can again
contribute to trust net profits income.

6.  XTO Energy Inc.

In computing net profits income for the 75% net profits interests (Note 3), XTO
Energy deducts an overhead charge as reimbursement for costs associated with
monitoring these interests. This charge at December 31, 2002 was $23,470 per
month, or $281,640 annually (net to the trust of $17,603 per month or $211,236
annually), and is subject to annual adjustment based on an oil and gas industry
index.

With the exception of working interests from which approximately 20 overriding
royalty interests were conveyed, XTO Energy does not operate or control any of
the underlying properties or related working interests. XTO Energy acquired
these working interests after the overriding royalty interests were conveyed to
the trust.

As of March 3, 2003, XTO Energy owned 22.7% of the outstanding trust units. In
June 2001, the trust and XTO Energy filed an amended registration statement with
the Securities and Exchange Commission to sell 1,360,000 units (22.7% of
outstanding units) held by XTO Energy. The trust did not participate in XTO
Energy's decisions to acquire or sell units and will not receive any of the
proceeds in the event of such sale.

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 net profits income, distributable income and
distributable income per unit by quarter for 2002 and 2001:

<TABLE>
<CAPTION>
                                                                                  Distributable
                                             Net Profits       Distributable          Income
                                                Income            Income             per Unit
                                            --------------    --------------     ---------------
<S>                                         <C>               <C>                <C>
2002
----
First Quarter ..........................    $    1,879,550    $    1,804,746     $      0.300791
Second Quarter .........................         1,816,119         1,723,548            0.287258
Third Quarter ..........................         2,526,363         2,494,434            0.415739
Fourth Quarter .........................         2,827,239         2,799,582            0.466597
                                            --------------    --------------     ---------------
                                            $    9,049,271    $    8,822,310     $      1.470385
                                            ==============    ==============     ===============
2001
----
First Quarter ..........................    $    4,107,459    $    4,048,902     $      0.674817
Second Quarter .........................         4,221,331         4,178,970            0.696495
Third Quarter ..........................         3,451,168         3,398,640            0.566440
Fourth Quarter .........................         2,609,358         2,583,372            0.430562
                                            --------------    --------------     ---------------
                                            $   14,389,316    $   14,209,884     $      2.368314
                                            ==============    ==============     ===============
</TABLE>

                                                                              11

<PAGE>

INDEPENDENT AUDITORS' REPORTS

Bank of America, N.A., as Trustee for the Cross Timbers Royalty Trust:

         We have audited the accompanying statement of assets, liabilities and
trust corpus of the Cross Timbers Royalty Trust as of December 31, 2002, and the
related statements of distributable income and changes in trust corpus for the
year 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 audit. The 2001 and 2000 financial statements were
audited by other auditors who have ceased operations. Those auditors' report,
dated March 19, 2002, on those financial statements was unqualified and included
an explanatory paragraph that described the trust's method of accounting as
explained in Note 2 to the financial statements.

         We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. 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 audit provides 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 of America.

         In our opinion, the 2002 financial statements referred to above present
fairly, in all material respects, the assets, liabilities and trust corpus of
the trust as of December 31, 2002 and its distributable income and changes in
trust corpus for the year then ended in conformity with the modified cash basis
of accounting described in Note 2.

KPMG LLP

Dallas, Texas
March 14, 2003

Bank of America, N.A., as Trustee for the Cross Timbers Royalty Trust:

         We have audited the accompanying statements of assets, liabilities and
trust corpus of the Cross Timbers Royalty Trust as of December 31, 2001 and
2000, and the related statements of distributable income and changes in trust
corpus for each of the three years in the period ended December 31, 2001. 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, 2001 and 2000 and its distributable income and
changes in trust corpus for each of the three years in the period ended December
31, 2001, in conformity with the modified cash basis of accounting described in
Note 2.

ARTHUR ANDERSEN LLP

Fort Worth, Texas
March 19, 2002

The above report of Arthur Andersen LLP ("Arthur Andersen") is a copy of a
report previously issued by Arthur Andersen on March 19, 2002. This audit report
has not been reissued by Arthur Andersen in connection with this filing on Form
10-K. After reasonable efforts, the trust has been unable to obtain the consent
of Arthur Andersen, our former independent auditors, as to the incorporation by
reference of their report for our fiscal years ended December 31, 2001 and 2000
into the trust's and XTO Energy's previously filed registration statements under
the Securities Act of 1933, and the trust has not filed that consent with this
Annual Report on Form 10-K in reliance on Rule 437a of the Securities Act of
1933. Because the trust has not been able to obtain Arthur Andersen's consent,
you will not be able to recover against Arthur Andersen under Section 11 of the
Securities Act for any untrue statements of a material fact contained in our
financial statements audited by Arthur Andersen or any omissions to state a
material fact required to be stated therein.

                                                                              12

<PAGE>

CROSS TIMBERS ROYALTY TRUST

901 Main Street, 17th Floor
P.O. Box 830650
Dallas, Texas 75283-0650
(877) 228-5084
Bank of America, N.A., Trustee

A copy of the Cross Timbers 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. Copies of exhibits to the
Form 10-K may be obtained upon request.

WEB SITE

www.crosstimberstrust.com

AUDITORS

KPMG LLP
Dallas, 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

                                                                              13