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<SEC-DOCUMENT>0000930661-02-000906.txt : 20020415
<SEC-HEADER>0000930661-02-000906.hdr.sgml : 20020415
ACCESSION NUMBER:		0000930661-02-000906
CONFORMED SUBMISSION TYPE:	10-K405
PUBLIC DOCUMENT COUNT:		5
CONFORMED PERIOD OF REPORT:	20011231
FILED AS OF DATE:		20020328

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			CROSS TIMBERS ROYALTY TRUST
		CENTRAL INDEX KEY:			0000881787
		STANDARD INDUSTRIAL CLASSIFICATION:	OIL ROYALTY TRADERS [6792]
		IRS NUMBER:				756415930
		STATE OF INCORPORATION:			TX
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		10-K405
		SEC ACT:		1934 Act
		SEC FILE NUMBER:	001-10982
		FILM NUMBER:		02589635

	BUSINESS ADDRESS:	
		STREET 1:		500 WEST SEVENTH ST STE 1300
		STREET 2:		P O BOX 1317
		CITY:			FORT WORTH
		STATE:			TX
		ZIP:			76101-1317
		BUSINESS PHONE:		8173906592

	MAIL ADDRESS:	
		STREET 1:		NATIONALBANK OF TEXAS  N A
		STREET 2:		P O BOX 1317
		CITY:			FORT WORTH
		STATE:			TX
		ZIP:			76101-1317
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<FILENAME>d10k405.txt
<DESCRIPTION>FORM 10-K405
<TEXT>
<PAGE>

================================================================================

                      SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C. 20549

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

                                   FORM 10-K

               ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                      THE SECURITIES EXCHANGE ACT OF 1934


   For the fiscal year ended December 31, 2001 Commission file number 1-10982

                          Cross Timbers Royalty Trust
   (Exact name of registrant as specified in the Cross Timbers Royalty Trust
                                  Indenture)

                        Texas                          75-6415930
             (State or other jurisdiction           (I.R.S. Employer
          incorporation or of organization)        Identification No.)

                Bank of America, N.A.                  75283-0650
                       Trustee                         (Zip Code)
                   P.O. Box 830650
                    Dallas, Texas
       (Address of principal executive offices)

       Registrant's telephone number including area code: (877) 228-5084

          Securities registered pursuant to Section 12(b) of the Act:

         Title of each class      Name of each exchange on which registered
         -------------------      -----------------------------------------

     Units of Beneficial Interest          New York Stock Exchange

       Securities registered pursuant to Section 12(g) of the Act: None

   Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes __X__  No _____

   Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

   At March 1, 2002, there were 6,000,000 units of beneficial interest of the
trust outstanding. The aggregate market value of the units (based on the
closing price on the New York Stock Exchange on March 1, 2002) held by
non-affiliates of the registrant on that date was approximately $84.1 million.

                      DOCUMENTS INCORPORATED BY REFERENCE

   Listed below is the only document parts of which are incorporated herein by
reference and the parts of this report into which the document is incorporated:

                  2001 Annual Report to Unitholders--Part II

================================================================================

<PAGE>

                                    PART I

Item 1.  Business

   Cross Timbers Royalty Trust is an express trust created under the laws of
Texas pursuant to the Cross Timbers Royalty Trust Indenture entered into on
February 12, 1991 between predecessors of XTO Energy Inc., as grantors, and
NCNB Texas National Bank, as trustee. Bank of America, N.A., successor of NCNB
Texas National Bank, is now the trustee of the trust. The principal office of
the trust is located at 901 Main Street, Dallas, Texas 75202 (telephone number
877-228-5084).

   On February 12, 1991, the predecessors of XTO Energy (formerly known as
Cross Timbers Oil Company) conveyed defined net profits interests to the trust
under five separate conveyances:

    -- one in each of the states of Texas, Oklahoma and New Mexico, to convey a
       90% defined net profits interest carved out of substantially all royalty
       and overriding royalty interests owned by the predecessors in those
       states, and

    -- one in each of the states of Texas and Oklahoma, to convey a 75% defined
       net profits interest carved out of specific working interests owned by
       the predecessors in those states.

   The conveyance of these net profits interests was effective for production
from October 1, 1990. The net profits interests and the underlying properties
are further described under Item 2.

   In exchange for the conveyance of the net profits interests to the trust,
the predecessors of XTO Energy received 6,000,000 units of beneficial interest
of the trust. Predecessors of XTO Energy distributed units to their owners in
February 1991 and November 1992, and in February 1992, sold units in the
trust's initial public offering. Units are listed and traded on the New York
Stock Exchange under the symbol "CRT." During 1996 and 1997, XTO Energy's Board
of Directors authorized XTO Energy to purchase two million units. As of
March 1, 2002, XTO Energy owned 1,360,000 units, or 22.7%, of the outstanding
units.

   In June 1998 the trust and XTO Energy filed a registration statement with
the Securities and Exchange Commission to sell the 1,360,000 units held by XTO
Energy. As XTO Energy stated in a related news release, the filing was made in
anticipation of better commodity prices and any sale is dependent on an
improved market for oil and gas equities. The registration statement was
amended in October 2000 and June 2001. As of March 27, 2002, no sales have been
made under the registration statement. 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.

   Under the terms of each of the five conveyances, the trust receives net
profits income from the net profits interests on the last business day of each
month. Net profits income is determined by XTO Energy by multiplying the net
profit percentage (90% or 75%) times net proceeds from the underlying
properties for each of the five conveyances during the previous month. Net
proceeds are the gross proceeds received from the sale of production, less
production costs. For the 90% net profits interests and the 75% net profits
interests, "production costs" generally include applicable property taxes,
transportation, marketing and other charges. For the 75% net profits interests
only, production costs also include capital and operating costs paid (e.g.,
drilling, production and other direct costs of owning and operating the
property) and a monthly overhead charge that is adjusted annually. The monthly
overhead charge at December 31, 2001 was $23,925. If production costs exceed
gross proceeds for any conveyance, such excess is carried forward to the
computation of net proceeds for future months until the excess costs (plus
interest accrued as specified in the conveyances) are completely recovered.
Such excess production costs and related accrued interest from one conveyance
cannot be used to reduce net proceeds from any other conveyance.

   The trust is not liable for any production costs or liabilities attributable
to the net profits interests. If at any time the trust receives net profits
income in excess of the amount due, the trust is not obligated to return such
overpayment, but net profits income payable to the trust for the next month
will be reduced by the overpayment, plus interest at the prime rate.

                                      1

<PAGE>

   With the exception of working interests from which approximately 20
overriding royalty interests in the San Juan Basin were conveyed, XTO Energy
does not operate or control any of the underlying properties or related working
interests. As a working interest owner, XTO Energy can generally decline
participation in any operation and allow consenting parties to conduct such
operations, as provided under the operating agreements. XTO Energy also can
assign, sell, or otherwise transfer its interest in the underlying properties,
subject to the net profits interests, or can abandon an underlying property
that is a working interest if it is incapable of producing in paying
quantities, as determined by XTO Energy.

   To the extent it has the right to do so, XTO Energy is responsible for
marketing its production from the underlying properties under existing sales
contracts or new arrangements on the best terms reasonably obtainable in the
circumstances.

   Net profits income received by the trust on or before the last business day
of the month generally represents receipts attributable to oil production two
months prior and gas production three months prior. The monthly distribution
amount to unitholders is determined by:

   Adding--

   (1) net profits income received,

   (2) estimated interest income to be received on the monthly distribution
       amount, including an adjustment for the difference between the estimated
       and actual interest received for the prior monthly distribution amount,

   (3) cash available as a result of reduction of cash reserves, and

   (4) any other cash receipts, and

   Subtracting the sum of--

   (1) liabilities paid and

   (2) the reduction in cash available due to establishment of or increase in
       any cash reserve.

   The monthly distribution amount is distributed to unitholders of record
within ten business days after the monthly record date. The monthly record date
is generally the last business day of the month. The trustee calculates the
monthly distribution amount and announces the distribution per unit at least
ten days prior to the monthly record date.

   The trustee may establish cash reserves for contingencies. Cash held for
such reserves, as well as for pending payment of the monthly distribution
amount may be invested in federal obligations or certificates of deposit of
major banks.

   The trustee's function is to collect the net profits income from the net
profits interests, to pay all trust expenses and pay the monthly distribution
amount to unitholders. The trustee's powers are specified by the terms of the
indenture. The trust cannot engage in any business activity or acquire any
assets other than the net profits interests and specific short-term cash
investments. The trust has no employees since all administrative functions are
performed by the trustee.

   Approximately 77% of the net profits income received by the trust during
2001, as well as 76% of the estimated proved reserves of the net profits
interests at December 31, 2001 (based on estimated future net revenues using
year-end oil and gas prices), is attributable to natural gas. There has
historically been a greater demand for gas during the winter months than the
rest of the year. Otherwise, trust income is not subject to seasonal factors,
nor dependent upon patents, licenses, franchises or concessions. The trust
conducts no research activities.

Item 2.  Properties

   The net profits interests are the principal asset of the trust. The trustee
cannot acquire any other asset, with the exception of certain short-term
investments as specified under Item 1. The trustee is prohibited from selling
any portion of the net profits interests unless approved by at least 80% of the
unitholders or at such time as trust gross revenue is less than $1,000,000 for
two successive years.

                                      2

<PAGE>

   The net profits interests are composed of:

   --the 90% net profits interests which are carved from:

    a) producing royalty and overriding royalty interest properties in Texas,
       Oklahoma and New Mexico, and

    b) 11.11% non-participating royalty interests in nonproducing properties
       located primarily in Texas and Oklahoma;

   --the 75% net profits interests which are carved from nonoperated working
     interests in four properties in Texas and three properties in Oklahoma.

   All underlying royalties, underlying nonproducing royalties and underlying
working interest properties are currently owned by XTO Energy. XTO Energy may
sell all or any portion of the underlying properties at any time, subject to
and burdened by the net profits interests.

Producing Acreage, Wells and Drilling

   Underlying Royalties.  The underlying royalties are royalty and overriding
royalty interests primarily located in mature producing oil and gas fields. The
most significant producing region in which the underlying royalties are located
is the San Juan Basin in northwestern New Mexico. The trust's estimated proved
reserves from this region totaled 26.1 Bcf at December 31, 2001, or
approximately 82% of trust total gas reserves at that date. XTO Energy
estimates that underlying royalties in the San Juan Basin include more than
2,000 gross (approximately 30 net) wells, covering over 60,000 gross acres.
Most of these wells are operated by Amoco Production Company or Burlington
Resources Oil & Gas Company. Production from conventional gas wells is
primarily from the Dakota, Mesaverde and Pictured Cliffs formations.

   Approximately 26% of trust 2001 gas sales volumes were from coal seam
production in the San Juan Basin. Through the year 2002, sales of certain coal
seam gas qualify for a federal income tax credit. See "Regulation--Coal Seam
Tax Credit." Operators are seeking approval to increase the density of coal
seam wells drilled in the San Juan Basin. XTO Energy anticipates that hearings
on the request will be held in June 2002. Although XTO Energy believes that the
outlook for approval of increased density drilling is good, there can be no
assurance that such an increase will be approved.

   Most of the trust's San Juan Basin conventional, or non-coal seam,
production is 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. There was minimal drilling in 2001 because of
environmental concerns that delayed the approval of drilling permits.

   During 1996, additional eastward pipeline capacity was completed in the San
Juan Basin, reducing the dependence of San Juan Basin gas on California markets
and effectively increasing San Juan Basin gas prices in relation to prices from
other regions. Gas-powered electricity generation continues to increase in the
southwest U.S., thereby increasing demand for San Juan Basin gas. Additional
eastward pipeline capacity for western Canadian gas supplies, which previously
were primarily directed to U.S. West Coast markets, has also improved the
market for San Juan Basin gas.

   The underlying royalties also include royalties in the Sand Hills field of
Crane County, Texas. Most of these properties are operated by ExxonMobil
Corporation or Chevron, U.S.A. The Sand Hills field was discovered in 1931 and
includes production from three main intervals, the Tubb, McKnight and Judkins.
Development potential for the field includes recompletions and additional
infill drilling.

   The underlying royalties contain approximately 462,000 gross (approximately
26,000 net) producing acres. Well counts for the underlying royalties cannot be
provided because information regarding the number of wells on royalty
properties is generally not made available to royalty interest owners.

                                      3

<PAGE>

   Underlying Working Interest Properties.  The underlying working interest
properties, detailed below, are developed properties undergoing secondary or
tertiary recovery operations:

<TABLE>
<CAPTION>
                                                                    Ownership of
                                                                     XTO Energy
                                                                  ----------------
                                                                  Working  Revenue
         Unit            County/State           Operator          Interest Interest
- ----------------------- --------------- ------------------------- -------- --------
<S>                     <C>             <C>                       <C>      <C>
North Cowden            Ector/Texas     Occidental Permian, Ltd.     1.7%    1.4%
North Central Levelland Hockley/Texas   ExxonMobil Corporation       3.2%    2.1%
Penwell                 Ector/Texas     Texaco Exploration           5.2%    4.6%
                                        and Production, Inc.
Sharon Ridge Canyon     Borden/Texas    ExxonMobil Corporation       4.3%    2.8%
Hewitt                  Carter/Oklahoma ExxonMobil Corporation      11.3%    9.9%
Wildcat Jim Penn        Carter/Oklahoma LeNorman Partners, L.L.C.    8.6%    7.5%
South Graham Deese      Carter/Oklahoma Maynard Oil Company          8.2%    7.0%
</TABLE>

   The underlying working interest properties consist of 60,154 gross (2,290
net) producing acres. As of December 31, 2001, there were 1,525 gross (70.0
net) productive oil wells, 1,015 gross (43.4 net) injection wells and two wells
in process of drilling on these properties. During 2001, 50 gross (1.4 net)
wells were drilled, during 2000, 12 gross (0.2 net) wells were drilled and
during 1999, eight gross (0.1 net) wells were drilled. Nine gross (0.2 net)
wells drilled in 2001 were water injections wells.

Oil and Gas Production

   Trust production is recognized in the period net profits income is received,
which is the month following receipt by XTO Energy, and generally two months
after the time of oil production and three months after gas production. Oil and
gas production and average sales prices attributable to the underlying
properties and the net profits interests for the three years ended December 31,
2001 were as follows:


<TABLE>
<CAPTION>
                              90% Net Profits Interests   75% Net Profits Interests             Total
                            ----------------------------- ------------------------- -----------------------------
                              2001      2000      1999      2001     2000    1999     2001      2000      1999
Production                  --------- --------- --------- -------  -------  ------- --------- --------- ---------
<S>                         <C>       <C>       <C>       <C>      <C>      <C>     <C>       <C>       <C>
Underlying Properties
  Oil--Sales (Bbls)........    92,329    86,970    92,650 258,362  257,153  255,959   350,691   344,123   348,609
   Average per day (Bbls)..       253       238       254     708      702      701       961       940       955
  Gas--Sales (Mcf)......... 2,845,132 2,964,687 3,548,594  87,071  115,914   94,429 2,932,203 3,080,601 3,643,023
   Average per day (Mcf)...     7,795     8,100     9,722     238      317      259     8,033     8,417     9,981
Net Profits Interests
  Oil--Sales (Bbls)........    82,745    76,959    77,783  62,933   86,260   19,894   145,678   163,219    97,677
   Average per day (Bbls)..       227       210       213     172      236       55       399       446       268
  Gas--Sales (Mcf)......... 2,530,916 2,659,139 3,152,693  21,291   30,120   10,249 2,552,207 2,689,259 3,162,942
   Average per day (Mcf)...     6,934     7,266     8,638      58       82       28     6,992     7,348     8,666
Average Sales Price
  Oil (per Bbl)............    $24.22    $26.41    $14.54  $25.26   $27.85   $15.01    $24.99    $27.49    $14.88
  Gas (per Mcf)............    $ 5.14    $ 3.36    $ 2.01  $ 3.31   $ 2.28   $ 1.35    $ 5.09    $ 3.32    $ 1.99
</TABLE>

Nonproducing Acreage

   The underlying nonproducing royalties contain approximately 200,000 gross
(approximately 3,000 net) acres in Texas, Oklahoma and New Mexico which were
nonproducing at the date of the trust's creation. XTO Energy is the owner of
underlying mineral interests in the majority of this acreage. The trust is
entitled to 10% of oil and gas production attributable to the underlying
mineral properties, but is not entitled to delay rental payments or lease
bonuses. There has been no significant development of such nonproducing acreage
since the trust's creation.

                                      4

<PAGE>

Pricing and Sales Information

   Oil and gas are generally sold from the underlying properties at
market-sensitive prices. The majority of sales from the underlying working
interest properties are to major oil and gas companies. Information about
purchasers of oil and gas from royalty properties is generally not provided by
operators to XTO Energy as a royalty owner, or to the trust.

Oil and Natural Gas Reserves

   General

   Miller and Lents, Ltd., independent petroleum engineers, has estimated oil
and gas reserves attributable to the underlying properties and net profits
interests as of December 31, 2001, 2000, 1999 and 1998. Numerous uncertainties
are inherent in estimating reserve volumes and values, and such estimates are
subject to change as additional information becomes available. The reserves
actually recovered and the timing of production of these reserves may be
substantially different from the original estimates.

   Reserve quantities and revenues for the net profits interests were estimated
from projections of reserves and revenues attributable to the combined
interests of the trust and XTO Energy in the subject properties. Since the
trust has defined net profits interests, the trust does not own a specific
percentage of the oil and gas reserve quantities. Accordingly, reserves
allocated to the trust pertaining to its 75% net profits interests in the
working interest properties have effectively been reduced to reflect recovery
of the trust's 75% portion of applicable production and development costs.
Because trust reserve quantities are determined using an allocation formula,
any fluctuations in actual or assumed prices or costs will result in revisions
to the estimated reserve quantities allocated to the net profits interests.

   The standardized measure of discounted future net cash flows and changes in
such discounted cash flows as presented below are prepared using assumptions
required by the Financial Accounting Standards Board. Such assumptions include
the use of year-end prices for oil and gas and year-end costs for estimated
future development and production expenditures to produce the proved reserves.
Because natural gas prices are influenced by seasonal demand, use of year-end
prices, as required by the Financial Accounting Standards Board, may not be the
most representative in estimating future revenues or reserve data. Future net
cash flows are discounted at an annual rate of 10%. No provision is included
for federal income taxes since future net revenues are not subject to taxation
at the trust level.

   Year-end oil prices used to determine the standardized measure were based on
a West Texas Intermediate crude oil posted price of $16.75 per Bbl in 2001,
$23.75 per Bbl in 2000, $22.75 per Bbl in 1999 and $9.50 per Bbl in 1998. The
year-end weighted average realized gas prices used to determine the
standardized measure were $2.28 per Mcf in 2001, $9.48 per Mcf in 2000, $2.19
per Mcf in 1999 and $1.88 per Mcf in 1998.

                                      5

<PAGE>

   Proved Reserves

<TABLE>
<CAPTION>
                                             Net Profits Interests
                              ---------------------------------------------------
                              90% Net Profits  75% Net Profits                         Underlying
                                 Interests        Interests           Total            Properties
(in thousands)                ---------------  ---------------  -----------------  -----------------
                               Oil     Gas      Oil      Gas     Oil       Gas      Oil       Gas
                              (Bbls)  (Mcf)    (Bbls)   (Mcf)   (Bbls)    (Mcf)    (Bbls)    (Mcf)
                              ------ --------  -------  ------  -------  --------  -------  --------
<S>                           <C>    <C>       <C>      <C>     <C>      <C>       <C>      <C>
Balance, December 31, 1998... 676.5  36,453.2    247.1    65.3    923.6  36,518.5  2,409.9  41,733.4
 Extensions, discoveries
   and other additions.......  10.5     162.2      -0-     -0-     10.5     162.2     13.1     186.0
 Revisions of prior estimates 109.9   1,462.1  1,251.8   533.4  1,361.7   1,995.5  2,385.7   2,322.0
 Production.................. (77.8) (3,152.7)   (19.9)  (10.2)   (97.7) (3,162.9)  (348.6) (3,643.0)
                              -----  --------  -------  ------  -------  --------  -------  --------
Balance, December 31, 1999... 719.1  34,924.8  1,479.0   588.5  2,198.1  35,513.3  4,460.1  40,598.4
 Extensions, discoveries and
   other additions...........   3.2      77.1      -0-     -0-      3.2      77.1      3.5      85.7
 Revisions of prior estimates  32.7   1,864.4     33.2    14.0     65.9   1,878.4    123.5   1,773.5
 Production.................. (77.0) (2,659.1)   (86.2)  (30.1)  (163.2) (2,689.2)  (344.1) (3,080.6)
                              -----  --------  -------  ------  -------  --------  -------  --------
Balance, December 31, 2000... 678.0  34,207.2  1,426.0   572.4  2,104.0  34,779.6  4,243.0  39,377.0
 Extensions, discoveries and
   other additions...........  12.3     247.8      -0-     -0-     12.3     247.8     13.7     274.8
 Revisions of prior estimates   6.9    (486.5)  (678.2) (282.9)  (671.3)   (769.4)  (483.6)   (713.2)
 Production.................. (82.8) (2,530.9)   (62.9)  (21.3)  (145.7) (2,552.2)  (350.7) (2,932.2)
                              -----  --------  -------  ------  -------  --------  -------  --------
Balance, December 31, 2001... 614.4  31,437.6    684.9   268.2  1,299.3  31,705.8  3,422.4  36,006.4
                              =====  ========  =======  ======  =======  ========  =======  ========
</TABLE>

   Revisions of prior estimates of the 75% net profits interests' proved
reserves and the underlying properties' proved oil reserves in each of the
years above were primarily the result of changes in the year-end oil prices
used in estimating proved reserves. During 2000 and 1999, upward revisions of
the 90% net profits interests' proved gas reserves were primarily because of
lower than anticipated production declines. Downward revisions of the 90% net
profits interests in 2001 were primarily because of significantly lower
year-end prices. Higher upward and downward revisions for the net profits
interests as compared to underlying properties in 2001 and 2000 were caused by
year-end price fluctuations which resulted in increased gas reserves allocated
to or from the trust. See "General" above.

   Proved Developed Reserves

<TABLE>
<CAPTION>
                               Net Profits Interests
                  ------------------------------------------------
                  90% Net Profits 75% Net Profits                     Underlying
                     Interests       Interests         Total          Properties
(in thousands)    --------------- --------------- ---------------- ----------------
                   Oil     Gas      Oil     Gas    Oil      Gas     Oil      Gas
                  (Bbls)  (Mcf)    (Bbls)  (Mcf)  (Bbls)   (Mcf)   (Bbls)   (Mcf)
                  ------ -------- -------  -----  ------- -------- ------- --------
<S>               <C>    <C>      <C>      <C>    <C>     <C>      <C>     <C>

December 31, 1998 672.8  34,514.0   206.4   60.7    879.2 34,574.7 2,195.1 39,520.1
                  =====  ======== =======  =====  ======= ======== ======= ========

December 31, 1999 715.7  33,036.5 1,375.0  570.3  2,090.7 33,606.8 4,245.6 38,463.3
                  =====  ======== =======  =====  ======= ======== ======= ========

December 31, 2000 675.0  32,371.1 1,317.8  553.5  1,992.8 32,924.6 4,028.8 37,300.0
                  =====  ======== =======  =====  ======= ======== ======= ========

December 31, 2001 611.4  29,608.5   602.0  253.7  1,213.4 29,862.2 3,208.3 33,937.3
                  =====  ======== =======  =====  ======= ======== ======= ========
</TABLE>

                                      6

<PAGE>

   Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

<TABLE>
<CAPTION>
                          90% Net Profits Interests     75% Net Profits Interests               Total
                        -----------------------------  ---------------------------  -----------------------------
                                 December 31,                  December 31,                  December 31,
(in thousands)          -----------------------------  ---------------------------  -----------------------------
                          2001      2000       1999     2001      2000      1999      2001      2000       1999
                        --------  ---------  --------  -------  --------  --------  --------  ---------  --------

Net Profits Interests
<S>                     <C>       <C>        <C>       <C>      <C>       <C>       <C>       <C>        <C>

Future cash inflows.... $ 87,042  $ 347,874  $ 97,902  $12,275  $ 40,146  $ 36,670  $ 99,317  $ 388,020  $134,572
Future production taxes   (6,945)   (28,042)   (7,751)    (831)   (2,786)   (2,487)   (7,776)   (30,828)  (10,238)
                        --------  ---------  --------  -------  --------  --------  --------  ---------  --------

Future net cash flows..   80,097    319,832    90,151   11,444    37,360    34,183    91,541    357,192   124,334
10% discount factor....  (42,004)  (169,073)  (46,573)  (5,493)  (18,692)  (17,135)  (47,497)  (187,765)  (63,708)
                        --------  ---------  --------  -------  --------  --------  --------  ---------  --------

Standardized measure... $ 38,093  $ 150,759  $ 43,578  $ 5,951  $ 18,668  $ 17,048  $ 44,044  $ 169,427  $ 60,626
                        ========  =========  ========  =======  ========  ========  ========  =========  ========

Underlying Properties

Future cash inflows................................................................ $145,759  $ 484,675  $200,075
Future costs:
  Production.......................................................................  (40,984)   (78,973)  (52,858)
  Development......................................................................     (520)      (520)     (517)
                                                                                    --------  ---------  --------
Future net cash flows..............................................................  104,255    405,182   146,700
10% discount factor................................................................  (53,994)  (212,781)  (74,879)
                                                                                    --------  ---------  --------

Standardized measure............................................................... $ 50,261  $ 192,401  $ 71,821
                                                                                    ========  =========  ========
</TABLE>

                                      7

<PAGE>

   Changes in Standardized Measure of Discounted Future Net Cash Flows from
   Proved Reserves

<TABLE>
<CAPTION>

                                   90% Net Profits Interests    75% Net Profits Interests              Total
(in thousands)                   ----------------------------  --------------------------  ----------------------------
                                   2001       2000     1999      2001     2000     1999      2001       2000     1999
                                 ---------  --------  -------  --------  -------  -------  ---------  --------  -------
<S>                              <C>        <C>       <C>      <C>       <C>      <C>      <C>        <C>       <C>
Net Profits Interests
Standardized measure,
 January 1...................... $ 150,759  $ 43,578  $34,584  $ 18,668  $17,048  $ 1,192  $ 169,427  $ 60,626  $35,776
  Extensions, discoveries
   and other additions..........       507       461      384       -0-      -0-      -0-        507       461      384
  Accretion of discount.........    12,702     3,683    3,078     1,614    1,476      106     14,316     5,159    3,184
  Revisions of prior estimates,
   changes in price and other...  (113,093)  112,338   11,864   (12,724)   2,504   16,109   (125,817)  114,842   27,973
  Net profits income............   (12,782)   (9,301)  (6,332)   (1,607)  (2,360)    (359)   (14,389)  (11,661)  (6,691)
                                 ---------  --------  -------  --------  -------  -------  ---------  --------  -------
Standardized measure,
 December 31.................... $  38,093  $150,759  $43,578  $  5,951  $18,668  $17,048  $  44,044  $169,427  $60,626
                                 =========  ========  =======  ========  =======  =======  =========  ========  =======
Underlying Properties
Standardized measure, January 1........................................................... $ 192,401  $ 71,821  $40,593
                                                                                           ---------  --------  -------
Revisions:
  Prices and costs........................................................................  (140,000)  122,144   12,549
  Quantity estimates......................................................................    (1,581)    7,162   22,311
  Accretion of discount...................................................................    16,265     6,060    3,561
  Future development costs................................................................    (1,091)     (738)    (697)
  Other...................................................................................        49    (1,079)     591
                                                                                           ---------  --------  -------
    Net revisions.........................................................................  (126,358)  133,549   38,315
Extensions, additions and discoveries.....................................................       563       512      427
Production................................................................................   (17,479)  (14,220)  (8,250)
Development costs.........................................................................     1,134       739      736
                                                                                           ---------  --------  -------
    Net change............................................................................  (142,140)  120,580   31,228
                                                                                           ---------  --------  -------
Standardized measure, December 31......................................................... $  50,261  $192,401  $71,821
                                                                                           =========  ========  =======
</TABLE>

   Discounted Present Value of the Coal Seam Tax Credit

   The standardized measure above does not include the effects of the coal seam
tax credit since the trust is not a taxable entity. The following table
summarizes the estimated coal seam tax credit attributable to the 90% net
profits interests at December 31, 2001, 2000 and 1999. Such estimates are based
on projected coal seam gas production through the year 2002 (after which date
the tax credit may no longer be available) as estimated by independent
engineers. The estimates are also based on the current year estimated Btu
content and the coal seam tax credit of $1.08 per MMBtu at December 31, 2001,
$1.06 per MMBtu at December 31, 2000 and $1.02 per MMBtu at December 31, 1999.
See "Regulation--Coal Seam Tax Credit."

<TABLE>
<CAPTION>
                                                  December 31,
              (in thousands)                  --------------------
                                               2001   2000   1999
                                              ------ ------ ------
              <S>                             <C>    <C>    <C>
              Undiscounted................... $  922 $1,225 $1,979
                                              ====== ====== ======
              Discounted present value at 10% $  880 $1,120 $1,740
                                              ====== ====== ======
</TABLE>

Reversion Agreement

   Certain of the underlying royalties are subject to a reversion agreement
between XTO Energy and a third party. The agreement calls for XTO Energy to
transfer 25% of its interest in those properties to the third party when
amounts received by XTO Energy from the underlying properties subject to the
agreement equal the purchase price of the properties plus a 1% per month return
on the unrecouped purchase price, known as payout. If payout were to occur and
the 25% interest were to be transferred to the third party, the amounts payable
to the trust would be proportionately reduced. Based on 2001 prices and levels
of production, XTO Energy has advised

                                      8

<PAGE>

the trustee that payout is not projected to occur for approximately 20 years.
Unless higher prices and production are sustained for several years, this
reversion agreement is not expected to have a material impact on the trust.

Regulation

    Natural Gas Regulation

   The interstate transportation and sale for resale of natural gas is subject
to federal regulation, including transportation rates charged and various other
matters, by the Federal Energy Regulatory Commission (FERC). Federal price
controls on wellhead sales of domestic natural gas terminated on January 1,
1993. While natural gas prices are currently unregulated, Congress historically
has been active in the area of natural gas regulation. It is impossible to
predict whether new legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the various state
legislatures, and what effect, if any, such proposals might have on the
operations of the underlying properties.

    State Regulation

   The various states regulate the production and sale of oil and natural gas,
including imposing requirements for obtaining drilling permits, the method of
developing new fields, the spacing and operation of wells and the prevention of
waste of oil and gas resources. The rates of production may be regulated and
the maximum daily production allowables from both oil and gas wells may be
established on a market demand or conservation basis, or both.

    Coal Seam Tax Credit

   The trust receives net profits income from coal seam gas wells. Under
Section 29 of the Internal Revenue Code, coal seam gas produced through the
year 2002 from wells drilled after December 31, 1979 and prior to January 1,
1993 qualifies for the federal income tax credit for producing nonconventional
fuels. This tax credit for 2001 was approximately $1.08 per MMBtu. Such credit,
calculated based on the unitholder's pro rata share of qualifying production,
may not reduce the unitholder's regular tax liability (after the foreign tax
credit and certain other nonrefundable credits) below his tentative minimum
tax. Any part of the Section 29 credit not allowed for the tax year solely
because of this limitation is subject to certain carryover provisions.

   Congress is considering an extension of existing energy tax credits beyond
the scheduled December 31, 2002 expiration date, as well as the creation of
similar new tax credits. During 2001, the U.S. House passed a bill that would
extend existing Section 29 tax credits on certain production, while the U.S.
Senate is considering a separate bill to address energy tax credits, including
Section 29. The potential effect of any final legislation on unitholders is
unknown.

   In 1999, a U.S. Court of Appeals held that a well drilled and completed in
an otherwise qualifying formation prior to January 1, 1993 is not eligible for
the Section 29 credit unless the producer received an appropriate well category
determination from the FERC. The decision indicated that lack of a well
category determination may render the Section 29 credit unavailable with
respect to production from wells recompleted in a qualified formation after
January 1, 1993, the date that the FERC's authority to render category
determinations ended. Effective September 2000, the FERC amended its
regulations to reinstate certain regulations to allow it to provide well
category determinations for Section 29 tax credits for well recompletions
commenced after January 1, 1993.

    Other Regulation

   The petroleum industry is also subject to compliance with various other
federal, state and local regulations and laws, including, but not limited to,
regulations and laws relating to environmental protection, occupational safety,
resource conservation and equal employment opportunity. XTO Energy has advised
the trustee that it does not believe that compliance with these laws will have
any material adverse effect upon the unitholders.

                                      9

<PAGE>

Item 3.  Legal Proceedings

   Certain of the trust properties are involved in various lawsuits and certain
governmental proceedings arising in the ordinary course of business. XTO Energy
has advised the trustee that it does not believe that the ultimate resolution
of these claims will have a material effect on trust annual distributable
income, financial position or liquidity.

Item 4.  Submission of Matters to a Vote of Security Holders

   No matters were submitted to a vote of unitholders during 2001.

                                      10

<PAGE>

                                    PART II

Item 5.  Market for Units of the Trust and Related Security Holder Matters

   The section entitled "Units of Beneficial Interest" on page 1 of the trust's
annual report to unitholders for the year ended December 31, 2001 is
incorporated herein by reference.

Item 6.  Selected Financial Data

<TABLE>
<CAPTION>
                                               Year Ended Decxember 31,
                              -----------------------------------------------------------
                                 2001        2000        1999        1998        1997
                              ----------- ----------- ----------- ----------- -----------
<S>                           <C>         <C>         <C>         <C>         <C>
Net Profits Income........... $14,389,316 $11,660,510 $ 6,691,336 $ 7,079,632 $10,549,668
Distributable Income.........  14,209,884  11,502,114   6,549,803   6,927,338  10,407,250
Distributable Income per Unit    2.368314    1.917019    1.091635    1.154555    1.734541
Distributions per Unit.......    2.368314    1.917019    1.091635    1.154555    1.734541
Total Assets at Year-End.....  29,747,914  31,806,794  33,919,338  36,554,480  38,767,918
</TABLE>

Item 7.  Management's Discussion and Analysis of Financial Condition and
Results of Operations

   The "Trustee's Discussion and Analysis" of financial condition and results
of operations for the three-year period ended December 31, 2001 on pages 6
through 8 of the trust's annual report to unitholders for the year ended
December 31, 2001 is incorporated herein by reference.

Liquidity and Capital Resources

   The trust's only cash requirement is the monthly distribution of its income
to unitholders, which is funded by the monthly receipt of net profits income
after payment of trust administration expenses. The trust is not liable for any
production costs or liabilities attributable to the net profits interests. If
at any time the trust receives net profits income in excess of the amount due,
the trust is not obligated to return such overpayment, but future net profits
income payable to the trust will be reduced by the overpayment, plus interest
at the prime rate. The trust may borrow funds required to pay trust liabilities
if fully repaid prior to further distributions to unitholders.

   The trust does not have any transactions, arrangements or other
relationships with unconsolidated entities or persons that could materially
affect the trust's liquidity or the availability of capital resources.

Contractual Obligations and Commitments

   The trust had no obligations and commitments to make future contractual
payments as of December 31, 2001, other than the December distribution payable
to unitholders in January 2002, as reflected in the statement of assets,
liabilities and trust corpus. The trust has not guaranteed the debt of any
other party, nor does the trust have any other arrangements or relationships
with other entities that could potentially result in unconsolidated debt.

Related Party Transactions

   The underlying properties are currently owned by XTO Energy. As of March 1,
2002, XTO Energy owned 1,360,000, or 22.7%, of the 6,000,000 outstanding units.
XTO Energy deducts an overhead charge from monthly net proceeds as
reimbursement for costs associated with monitoring the 75% net profits
interests. As of December 31, 2001, this monthly charge was $23,925 ($17,944
net to the trust) and is subject to annual adjustment based on an oil and gas
industry index. For further information regarding the trust's relationship with
XTO Energy, see Note 6 to Financial Statements in the accompanying annual
report.

                                      11

<PAGE>

Critical Accounting Policies

   The financial statements of the trust are significantly affected by its
basis of accounting and estimates related to its oil and gas properties and
proved reserves, as summarized below.

   Basis of Accounting

   The trust's financial statements are prepared on a modified cash basis,
which is a comprehensive basis of accounting other than generally accepted
accounting principles. This method of accounting is consistent with reporting
of taxable income to trust unitholders. 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.

   For further information regarding the trust's basis of accounting, see Note
2 to Financial Statements in the accompanying annual report.

   All amounts included in the trust's financial statements are based on cash
amounts received or disbursed, or on the carrying value of the net profits
interests, which was derived from the historical cost of the interests at the
date of their transfer from XTO Energy. Accordingly, there are no fair value
estimates included in the financial statements based on either exchange or
non-exchange trade values.

   Oil and Gas Reserves

   The trust's proved oil and gas reserves are estimated by independent
petroleum engineers. Reserve engineering is a subjective process that is
dependent upon the quality of available data and the interpretation thereof.
Estimates by different engineers often vary, sometimes significantly. In
addition, physical factors such as the results of drilling, testing and
production subsequent to the date of an estimate, as well as economic factors
such as changes in product prices, may justify revision of such estimates.
Because proved reserves are required to be estimated using prices at the date
of the evaluation, estimated reserve quantities can be significantly impacted
by changes in product prices. Accordingly, oil and gas quantities ultimately
recovered and the timing of production may be substantially different from
original estimates.

   The standardized measure of discounted future net cash flows and changes in
such cash flows, as reported in Item 2 of the trust's Annual Report on Form
10-K, is prepared using assumptions required by the Financial Accounting
Standards Board and the Securities and Exchange Commission. Such assumptions
include using year-end oil and gas prices and year-end costs for estimated
future development and production expenditures. Discounted future net cash
flows are calculated using a 10% rate. Changes in any of these assumptions,
including consideration of other factors, could have a significant impact on
the standardized measure. Accordingly, the standardized measure does not
represent XTO Energy's or the trustee's estimated current market value of
proved reserves.

Forward-Looking Statements

   Certain information included in this annual report and other materials
filed, or to be filed, by the trust with the Securities and Exchange Commission
(as well as information included in oral statements or other written statements
made or to be made by XTO Energy or the trustee) contain forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended, and Section 27A of the Securities Act of 1933, as amended,
relating to the trust operations of the underlying properties and the oil and
gas industry. Such forward-looking statements may concern, among other things,
development activities, maintenance projects, development, production and other
costs, oil and gas prices, pricing differentials, proved reserves,

                                      12

<PAGE>

production levels, litigation, regulatory matters and competition. Such
forward-looking statements are based on XTO Energy's current plans,
expectations, assumptions, projections and estimates and are identified by
words such as "expects," "intends," "plans," "projects," " anticipates,"
"predicts," "believes," "goals," "estimates," "should," "could", and similar
words that convey the uncertainty of future events. These statements are not
guarantees of future performance and involve certain risks, uncertainties and
assumptions that are difficult to predict. Therefore, actual results may differ
materially from expectations, estimates or assumptions expressed in, implied
in, or forecasted in such forward-looking statements. Any number of factors
could cause actual results to differ materially, including, but not limited to,
crude oil and natural gas price fluctuations, changes in the underlying demand
for oil and natural gas, changes in ownership and/or the operator of the
underlying properties, the timing and results of development activity, the
availability of drilling equipment, as well as general domestic and
international economic and political conditions.

Item 7a.  Quantitative and Qualitative Disclosures about Market Risk

   The only assets of and sources of income to the trust are the net profits
interests, which generally entitle the trust to receive a share of the net
profits from oil and gas production from the underlying properties.
Consequently, the trust is exposed to market risk from fluctuations in oil and
gas prices. The trust is a passive entity and, other than the trust's ability
to periodically borrow money as necessary to pay expenses, liabilities and
obligations of the trust that cannot be paid out of cash held by the trust, the
trust is prohibited from engaging in borrowing transactions. The amount of any
such borrowings is unlikely to be material to the trust. In addition, the
trustee is prohibited by the trust indenture from engaging in any business
activity or causing the trust to enter into any investments other than
investing cash on hand in specific short-term cash investments. Therefore, the
trust cannot hold any derivative financial instruments. As a result of the
limited nature of its borrowing and investing activities, the trust is not
subject to any material interest rate market risk. Additionally, any gains or
losses from any hedging activities conducted by XTO Energy are specifically
excluded from the calculation of net proceeds due the trust under the forms of
the conveyances. The trust does not engage in transactions in foreign
currencies which could expose the trust to any foreign currency related market
risk.

Item 8.  Financial Statements and Supplementary Data

   The financial statements of the trust and the notes thereto, together with
the related report of Arthur Andersen LLP dated March 19, 2002, appearing on
pages 9 through 12 of the trust's annual report to unitholders for the year
ended December 31, 2001 are incorporated herein by reference.

Item 9.  Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure

   There have been no changes in accountants or disagreements with accountants
on any matter of accounting principles or practices or financial statement
disclosures during the two years ended December 31, 2001.

                                      13

<PAGE>

                                   PART III

Item 10.  Directors and Executive Officers of the Registrant

   The trust has no directors or executive officers. The trustee is a corporate
trustee which may be removed, with or without cause, by the affirmative vote of
the holders of a majority of all the units then outstanding.

Item 11.  Executive Compensation

   The trustee received the following annual compensation from 1999 through
2001 as specified in the trust indenture:

<TABLE>
<CAPTION>
                                                    Other Annual
               Name and Principal Position   Year Compensation (1)
              ------------------------------ ---- ----------------
              <S>                            <C>  <C>
              Bank of America, N.A., Trustee 2001      $7,195
                                             2000       5,830
                                             1999       3,346
</TABLE>

(1) Under the trust indenture, the trustee is entitled to an administrative fee
    of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of
    the trust, and 1/30 of 1% of the annual gross revenue of the trust in
    excess of $100 million, and (ii) trustee's standard hourly rates for time
    in excess of 300 hours annually.

Item 12.  Security Ownership of Certain Beneficial Owners and Management

   (a) Security Ownership of Certain Beneficial Owners.  The following table
sets forth as of March 1, 2002 information with respect to each person known to
the trustee to beneficially own more than 5% of the outstanding units of the
trust:

<TABLE>
<CAPTION>
                                     Amount and Nature of
             Name and Address        Beneficial Ownership Percent of Class
      ------------------------------ -------------------- ----------------
      <S>                            <C>                  <C>
      XTO Energy Inc.                1,360,000 units (1)       22.7%
      810 Houston Street, Suite 2000
      Fort Worth, TX 76102
</TABLE>

   (1) XTO Energy has the sole power to vote and dispose of these units.

   (b) Security Ownership of Management.  The trust has no directors or
executive officers. As of January 31, 2002, Bank of America, N.A. owned, in
various fiduciary capacities, 71,625 units with a shared right to vote 11,287
of these units and no right to vote 60,338 of these units. Bank of America,
N.A. disclaims any beneficial interests in these units. The number of units
reflected in this paragraph includes units held by all branches of Bank of
America, N.A.

   (c) Changes in Control.  The trustee knows of no arrangements which may
subsequently result in a change in control of the trust.

Item 13.  Certain Relationships and Related Transactions

   In computing net profits income paid to the trust for the 75% net profits
interests, XTO Energy deducts an overhead charge as reimbursement for costs
associated with monitoring these interests. This charge at December 31, 2001
was $23,925 per month, or $287,100 annually (net to the trust of $17,944 per
month or $215,325 annually), and is subject to annual adjustment based on an
oil and gas industry index.

   During 2001, Bank of America, N.A. received $938 for oil and gas consulting
services performed on behalf of the trust. See Item 11 for the remuneration
received by the trustee from 1999 through 2001 and Item 12(b) for information
concerning units owned by the trustee, Bank of America, N.A., in various
fiduciary capacities.

                                      14

<PAGE>

                                    PART IV

Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a) The following documents are filed as a part of this report:

    1. Financial Statements (incorporated by reference in Item 8 of this report)

       Report of Independent Public Accountants
       Statements of Assets, Liabilities and Trust Corpus at December 31, 2001
       and 2000
       Statements of Distributable Income for the years ended December 31,
       2001, 2000 and 1999
       Statements of Changes in Trust Corpus for the years ended December 31,
       2001, 2000 and 1999
       Notes to Financial Statements

    2. Financial Statement Schedules

       Financial statement schedules are omitted because of the absence of
       conditions under which they are required or because the required
       information is given in the financial statements or notes thereto.

    3. Exhibits

     (4)  (a) Cross Timbers Royalty Trust Indenture amended and restated on
              January 13, 1992 by NationsBank, N.A. (now Bank of America,
              N.A.), as trustee, heretofore filed as Exhibit 3.1 to the trust's
              Registration Statement No. 33-44385 filed with the Securities and
              Exchange Commission on February 19, 1992, is incorporated herein
              by reference.

          (b) Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust,
              90%--Texas) from South Timbers Limited Partnership, West Timbers
              Limited Partnership, North Timbers Limited Partnership, East
              Timbers Limited Partnership, Hickory Timbers Limited Partnership,
              and Cross Timbers Partners, L.P. (predecessors of Cross Timbers
              Oil Company, L.P.) to NCNB Texas National Bank (now Bank of
              America, N.A.), as trustee, dated February 12, 1991 (without
              Schedules A and B), heretofore filed as Exhibit 10.1 to the
              trust's Registration Statement No. 33-44385 filed with the
              Securities and Exchange Commission on February 19, 1992, is
              incorporated herein by reference.

          (c) Correction to Net Overriding Royalty Conveyance (Cross Timbers
              Royalty Trust, 90%--Texas) from South Timbers Limited
              Partnership, West Timbers Limited Partnership, North Timbers
              Limited Partnership, East Timbers Limited Partnership, Hickory
              Timbers Limited Partnership, and Cross Timbers Partners, L.P.
              (predecessors of Cross Timbers Oil Company, L.P.) to NCNB Texas
              National Bank (now Bank of America, N.A.), as trustee, dated
              September 23, 1991 (without Schedules A and B), heretofore filed
              as Exhibit 10.2 to the trust's Registration Statement No.
              33-44385 filed with the Securities and Exchange Commission on
              February 19, 1992, is incorporated herein by reference.

          (d) Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust,
              75%--Texas) from South Timbers Limited Partnership, West Timbers
              Limited Partnership, North Timbers Limited Partnership, East
              Timbers Limited Partnership, Hickory Timbers Limited Partnership,
              and Cross Timbers Partners, L.P. (predecessors of Cross Timbers
              Oil Company, L.P.) to NCNB Texas National Bank (now Bank of
              America, N.A.), as trustee, dated February 12, 1991 (without
              Schedules A and B), heretofore filed as Exhibit 10.5 to the
              trust's Registration Statement No. 33-44385 filed with the
              Securities and Exchange Commission on February 19, 1992, is
              incorporated herein by reference.

       (13)   Cross Timbers Royalty Trust annual report to unitholders for the
              year ended December 31, 2001

       (23.1) Consent of Arthur Andersen LLP

       (23.2) Consent of Miller and Lents, Ltd.

                                      15

<PAGE>

(99.1)  Assurance Letter Regarding Arthur Andersen LLP

          Copies of the above Exhibits are available to any unitholder, at the
       actual cost of reproduction, upon written request to the trustee, Bank
       of America, N.A., P.O. Box 830650, Dallas, Texas 75283-0650.

(b) Reports on Form 8-K

   During the last quarter of the trust's fiscal year ended December 31, 2001,
there were no reports filed on Form 8-K by the trust with the Securities and
Exchange Commission.

                                      16

<PAGE>

                                  SIGNATURES

   Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed
on its behalf by the undersigned thereunto duly authorized.

                                        CROSS TIMBERS ROYALTY TRUST
                                        By BANK OF AMERICA, N.A., TRUSTEE

                                        By             RON E. HOOPER
                                               ---------------------------------
                                                       Ron E. Hooper
                                                   Senior Vice President


                                        XTO ENERGY INC.

Date: March 27, 2002                    By           LOUIS G. BALDWIN
                                            ----------------------------------
                                                     Louis G. Baldwin
                                               Executive Vice President and
                                                 Chief Financial Officer

              (The trust has no directors or executive officers.)

                                      17

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13
<SEQUENCE>3
<FILENAME>dex13.txt
<DESCRIPTION>CROSS TIMBERS ROYALTY TRUST ANNUAL REPORT
<TEXT>
<PAGE>

                                                                      EXHIBIT 13

CROSS TIMBERS 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)

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 property that
(and overriding          provides the owner a specified share of production
royalty interest)        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 believes 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.
(formerly known as Cross Timbers Oil Company) 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 2001 and 2000:

<TABLE>
<CAPTION>
                                                    Sales Price
                                              ----------------------      Distributions
     Quarter                                   High            Low          per Unit
- -------------------------------------         ------         -------      -------------
<S>                                           <C>            <C>          <C>


  2001
- -------------------------------
First ...............................         $18.950        $15.500      $ 0.674817
Second ..............................          23.200         15.250        0.696495
Third ...............................          20.050         15.230        0.566440
Fourth ..............................          18.800         15.050        0.430562
                                                                          ----------
                                                                          $ 2.368314
                                                                          ==========

  2000
- -------------------------------
First ...............................         $14.750        $ 9.500      $ 0.383466
Second ..............................          14.188         10.438        0.404105
Third ...............................          17.000         13.000        0.557722
Fourth ..............................          16.938         13.375        0.571726
                                                                          ----------
                                                                          $ 1.917019
                                                                          ==========
</TABLE>

At December 31, 2001, there were 6,000,000 units outstanding and approximately
175 unitholders of record; 5,595,758 of these units were held by depository
institutions. As of March 1, 2002, 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 in 1999 and through April 2000, and the
         Oklahoma 75% net profits interests did not contribute to trust net
         profits income from February through June 1999 and for September 1999.
         Such excess costs generally occur during periods of higher development
         activity and lower oil prices. For further information, see "Trustee's
         Discussion and Analysis - Years Ended December 31, 2001, 2000 and 1999
         - 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 the year 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 is considering an extension of existing
         energy tax credits beyond the scheduled December 31, 2002 expiration
         date, as well as the creation of similar new tax credits. During 2001,
         the U.S. House passed a bill that would extend existing tax credits on
         certain production, while the U.S. Senate is considering a separate
         bill to address energy tax credits. The potential effect of any final
         legislation on unitholders is unknown.

     -   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 2001 and
            held them throughout 2001 would be entitled to a cost depletion
            deduction of approximately 8% of his cost. Assuming a cost of $18.00
            per unit, cost depletion would offset 59% of 2001 taxable trust
            income. After considering the coal seam tax credit and assuming a
            30% tax rate, the 2001 taxable equivalent return as a percentage of
            unit cost would be 17%. (NOTE- Because the units are a depleting
            asset, a portion of this return is effectively a return of capital.)

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

<TABLE>
<CAPTION>
                                           2001                      2000                      1999
                                   -------------------       -------------------       -------------------
                                   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 .....  $0.178       $2.130       $0.129        $1.550        $0.088        $1.055
- - 75% net profits interests .....   0.022        0.268        0.033         0.393         0.005         0.060
Administration expense
  (net of interest income) ......  (0.003)      (0.030)      (0.002)       (0.026)       (0.002)       (0.023)
                                   ------       ------       ------        ------        ------        ------
Total Distribution ..............  $0.197       $2.368       $0.160        $1.917        $0.091        $1.092
                                   ======       ======       ======        ======        ======        ======
Nonconventional Fuel
     Source Tax Credit ..........      *        $0.107           *         $0.120            *         $0.158
                                                ======                     ======                      ======
</TABLE>

* - Not applicable

                                                                               2

<PAGE>

TO UNITHOLDERS
- --------------

We are pleased to present the 2001 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, 2001, net profits income totaled $14,389,316.
After deducting trust administration expense and adding interest income,
distributable income was $14,209,884, or $2.368314 per unit. Distributions for
the year were the highest since the trust's inception and were 24% higher than
in 2000 primarily because of higher average gas prices.

Natural gas prices for 2001 averaged $5.09 per Mcf for sales from the underlying
properties, a 53% increase from the 2000 average price of $3.32 per Mcf. Gas
sales volumes from the underlying properties for the year ended December 31,
2001 totaled 2,932,203 Mcf, or 8,033 Mcf per day, a 5% decrease from 2000
production of 8,417 Mcf per day. Gas volumes were lower primarily because of
coal seam gas production decline.

Oil sales volumes from the underlying properties during 2001 were 350,691 Bbls,
or 961 Bbls per day, a 2% increase over 2000 levels of 940 Bbls per day. The
average oil price decreased to $24.99 per Bbl, down 9% from the 2000 average
price of $27.49.

Coal seam gas sales volumes from the underlying properties were 744,092 Mcf in
2001, or a 15% decline from 2000 coal seam gas production of 874,819 Mcf. Coal
seam gas sales volumes are lower because of natural production decline. The
resulting 2001 coal seam tax credit was $0.107183 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, 2001, proved reserves of the net profits interests were
estimated by independent engineers to be 1,299,000 Bbls of oil and 31.7 Bcf of
natural gas. Estimated oil reserves and gas reserves decreased 38% and 9%,
respectively, from year-end 2000 to 2001 primarily because of lower oil and gas
prices. All reserve information prepared by independent engineers has been
provided to the trustee by XTO Energy.

Estimated future net revenues from proved reserves of the net profits interests
at December 31, 2001 are $91.5 million, or $15.26 per unit. Using an annual
discount factor of 10%, the present value of estimated future net revenues at
December 31, 2001 is $44.0 million, or $7.34 per unit. Proved reserve estimates
and related future net revenues have been determined based on a year-end West
Texas Intermediate posted oil price of $16.75 per barrel and a year-end average
realized gas price of $2.28 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 revenues is not necessarily indicative of the market value
of trust units.

As discussed in the tax instructions provided to unitholders in February 2002,
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:   Ron E. Hooper
      Senior 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,
2001 is approximately 12 years for oil and gas. This index is calculated using
total proved reserves and estimated 2002 production for the underlying
properties. Based on estimated future net revenues at year-end oil and gas
prices, the proved reserves of the underlying properties are approximately 24%
oil and 76% 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 86% of the discounted future net cash flows from trust
proved reserves at December 31, 2001. Approximately 88% of the discounted future
net cash flows from the 90% net profits interests is from gas reserves, totaling
31.4 Bcf. Oil reserves underlying the 90% net profits interests are primarily
located in West Texas and are estimated to be 614,000 Bbls at December 31, 2001.

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 77% of gas sales volumes and 63% of net
profits income for 2001. As of December 31, 2001, trust proved reserves in this
region are estimated to be 26.1 Bcf, or 82% of total trust gas reserves.

Approximately 26% of trust 2001 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 2001 coal seam gas sales was
approximately $1.08 per MMBtu or $0.107183 per unit, while the coal seam credit
for 2000 was $1.06 per MMBtu or $0.120389 per unit. As of December 31, 2001, the
trust's proved coal seam gas reserves are estimated to be 3.9 Bcf, as compared
with 4.4 Bcf at December 31, 2000.

Congress is considering an extension of existing energy tax credits beyond the
scheduled December 31, 2002 expiration date, as well as the creation of similar
new tax credits. During 2001, the U.S. House passed a bill that would extend
existing tax credits on certain production, while the U.S. Senate is considering
a separate bill to address energy tax credits. The potential effect of any final
legislation on unitholders is unknown.

Operators are seeking approval to increase the density of coal seam wells
drilled in the San Juan Basin. XTO Energy anticipates that hearings on the
request will be held in June 2002. Although XTO Energy believes that the outlook
for approval of increased density drilling is good, there can be no assurance
that such an increase will be approved.

Most of the trust's San Juan Basin conventional, or non-coal seam, production is
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.
There was minimal drilling in 2001 because of environmental concerns that
delayed approval of drilling permits.

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 685,000 Bbls at year-end 2001. Based on year-end
oil and gas prices, proved reserves from these interests represent 14% of the
discounted future net cash flows of the trust's proved reserves at December 31,
2001.

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 sales
volumes and prices and is subject to reduction for any prior period excess
costs.

Total 2001 development costs were $1,133,869, up 54% from 2000 development costs
of $738,605. First quarter 2002 development costs totaled approximately
$286,000; these costs are primarily related to fourth quarter 2001 expenditures.

As reported to XTO Energy by unit operators in February of each year, budgeted
development costs were $896,000 for 2001 and $356,000 for 2000. Actual
development costs often differ from amounts budgeted because of changes in
product prices that may affect the timing of

                                                                               4

<PAGE>

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 $417,000 for 2002 and $204,000 for 2003.

Higher development costs and lower oil prices during 1998 and early 1999 caused
costs to exceed revenues from the properties underlying the 75% net profits
interests. During 1999 and 2000, $1,018,113 ($763,585 net to the trust) of such
excess costs and accrued interest were recovered. There were no excess costs in
2001. In February and March 2002, total excess costs and accrued interest of
$71,006 were incurred on the Texas 75% net profits interests as a result of
lower oil prices and increased development costs. For information regarding the
effect of excess costs on trust net profits income, see "Trustee's Discussion
and Analysis - Years Ended December 31, 2001, 2000 and 1999 - Costs."

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

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, 2001, as estimated by independent engineers:

<TABLE>
<CAPTION>
                                        Underlying Properties                    Net Profits Interests
                                        ---------------------    ------------------------------------------------------
                                         Proved Reserves (a)     Proved Reserves (a) (b)       Future Net Revenues
                                        ---------------------    -----------------------   from Proved Reserves (a) (c)
                                            Oil        Gas          Oil        Gas         ----------------------------
(in thousands)                            (Bbls)      (Mcf)       (Bbls)      (Mcf)        Undiscounted      Discounted
                                          ------      -----       ------      -----        ------------      ----------
<S>                                       <C>         <C>      <C>            <C>          <C>               <C>
90% Net profits interests

  San Juan Basin

    Conventional ...................        66      24,661          59       22,195        $ 53,323        $ 22,487
    Coal Seam ......................        -0-      4,336          -0-       3,902           5,564           3,688
                                         -----      ------       -----       ------           -----        --------
       Total .......................        66      28,997          59       26,097          58,887          26,175
  Other New Mexico .................       125         294         112          248           2,435           1,427
  Texas ............................       425       3,795         383        3,410          14,216           8,003
  Oklahoma .........................        67       1,886          60        1,683           4,559           2,488
                                         -----      ------       -----       ------        --------        --------
       Total .......................       683      34,972         614       31,438          80,097          38,093
                                         -----      ------       -----       ------        --------        --------

75% Net profits interests

  Texas ............................     1,553         720         458          213           7,714           3,854
  Oklahoma .........................     1,186         314         227           55           3,730           2,097
                                         -----      ------       -----       ------        --------        --------
       Total .......................     2,739       1,034         685          268          11,444           5,951
                                         -----      ------       -----       ------        --------        --------

       TOTAL .......................     3,422      36,006       1,299       31,706        $ 91,541        $ 44,044
                                         =====      ======       =====       ======        ========        ========
</TABLE>

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

(a)   Based on year-end oil and gas prices. Discounted estimated future net
      revenues from proved reserves decreased 74% from year-end 2000 to 2001,
      primarily because of a 76% decrease 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 (and the tax benefit of the estimated coal seam tax
      credit) since future net revenues are not subject to taxation at the trust
      level.

                                                                               5

<PAGE>

TRUSTEE'S DISCUSSION AND ANALYSIS
- ---------------------------------

Years Ended December 31, 2001, 2000 and 1999

Net profits income for 2001 was $14,389,316, as compared with $11,660,510 for
2000 and $6,691,336 for 1999. The 23% increase in net profits income from 2000
to 2001 was because of higher product prices partially offset by higher
development costs and increased production and property taxes associated with
increased revenues. The 74% increase in net profits income from 1999 to 2000 was
also because of higher product prices. During 2001, 2000 and 1999, 77%, 64% and
79%, respectively, of net profits income was derived from gas sales.

Trust administration expense was $198,482 in 2001 as compared to $185,624 in
2000 and $152,631 in 1999. Interest income was $19,050 in 2001, $27,228 in 2000
and $11,098 in 1999.

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:

     o  oil and gas sales volumes,
     o  oil and gas sales prices, and
     o  costs deducted in the calculation of net profits income.

Volumes

Oil. Underlying oil sales volumes increased 2% from 2000 to 2001, as compared to
a 1% decrease from 1999 to 2000. Sales volume increases in 2001 were because of
the timing of cash receipts partially offset by production decline. Sales volume
decreases in 2000 were related to natural production decline and timing of cash
receipts and were offset by increased production from properties underlying the
Texas 75% and 90% net profits interests.

Gas. Underlying gas sales volumes decreased 5% from 2000 to 2001 as compared to
a 15% decrease from 1999 to 2000. Lower 2001 gas sales volumes were primarily
because of coal seam gas production decline. Lower 2000 gas sales volumes were
primarily because of timing of cash receipts and coal seam gas production
decline.

Prices

Oil. The average oil price for 2001 was $24.99 per Bbl, 9% lower than the 2000
average oil price of $27.49, which was 85% higher than the 1999 average price of
$14.88. After OPEC members and other oil producers agreed to production cuts in
March 1999, oil prices climbed through the remainder of 1999 and first quarter
2000. Despite OPEC production increases in 2000, increased demand sustained
higher prices. The West Texas Intermediate ("WTI") posted price reached $34.25
per Bbl in September 2000, its highest level in ten years. Lagging demand in
2001, resulting from a worldwide economic slowdown, caused oil prices to
decline. OPEC members agreed to cut daily production by one million barrels in
April and an additional one million barrels in September to adjust for weak
demand and excess supply. The economic decline was accelerated by the terrorist
attacks in the United States on September 11, 2001, placing additional downward
pressure on oil prices. In December, OPEC announced additional production cuts
of 1.5 million barrels per day effective January 1, 2002, for six months. The
average WTI posted price for January and February 2002 was $17.06, compared with
$22.87 for the year 2001 and $17.26 for fourth quarter 2001. Oil prices have
risen in March to an average WTI posted price of about $21.00 through March 25.
Recent trust oil prices have averaged approximately $0.70 higher than the WTI
posted price.

Gas. The 2001 average gas price was $5.09 per Mcf, a 53% increase from the 2000
average gas price of $3.32, which was a 67% increase from the 1999 average price
of $1.99. Gas prices were lower in 1999 primarily because of the abnormally warm
winter of 1998-1999 across the United States that resulted in higher levels of
gas storage. Gas prices began to increase in May 1999 and, after declining
briefly at year end, strengthened in 2000, reaching a record high of $10.10 per
MMBtu in December 2000 as winter demand strained gas supplies. Gas prices
declined during 2001 because of fuel switching due to higher prices, milder
weather and a weaker economy which has reduced the demand for gas and resulted
in sharply increased gas storage levels. The average NYMEX price for January and
February 2002 was $2.23 per MMBtu. Gas prices have risen in March to an average
NYMEX posted price of $2.93 through March 25. The trust's recent gas prices have
averaged $0.25 per MMBtu lower than the NYMEX price.

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 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.

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)
                                -----------------------------------------         ------------------------
                                   2001            2000          1999                2001         2000
                                ------------   ------------  ------------         -----------  -----------
<S>                             <C>            <C>           <C>                  <C>          <C>

Sales Volumes
   Oil (Bbls) (b)
     Underlying properties ....      350,691        344,123       348,609              98,786       81,865
          Average per day .....          961            940           955               1,074          890
     Net profits interests ....      145,678        163,219        97,677              49,341       41,264

   Gas (Mcf) (b)
     Underlying properties ....    2,932,203      3,080,601     3,643,023             776,281      683,897
          Average per day .....        8,033          8,417         9,981               8,438        7,434
     Net profits interests ....    2,552,207      2,689,259     3,162,942             669,272      598,457

Average Sales Price
   Oil (per Bbl) ..............  $     24.99   $      27.49  $      14.88         $     22.74  $     31.18
   Gas (per Mcf) ..............  $      5.09   $       3.32  $       1.99         $      3.00  $      4.33

Revenues
   Oil sales .................. $  8,763,283   $  9,459,575  $  5,189,030         $ 2,246,178  $ 2,552,251
   Gas sales ..................   14,922,881     10,231,063     7,260,100           2,329,339    2,959,679
                                ------------   ------------  ------------         -----------  -----------
     Total Revenues ...........   23,686,164     19,690,638    12,449,130           4,575,517    5,511,930
                                ------------   ------------  ------------         -----------  -----------

Costs
   Taxes, transportation
      and other ...............    3,298,631      2,566,816     1,606,058             691,398      640,856
   Production expense (c) .....    2,908,305      2,520,954     2,390,818             731,502      658,350
   Development costs ..........    1,133,869        738,605       736,060             163,208      230,765
   Excess costs ...............       -              -           (432,789)             -            -
   Recovery of excess costs
     and accrued interest .....       -             383,836       634,277              -            -
                                ------------   ------------  ------------         -----------  -----------
     Total Costs ..............    7,340,805      6,210,211     4,934,424           1,586,108    1,529,971
                                ------------   ------------  ------------         -----------  -----------

Net Proceeds .................. $ 16,345,359   $ 13,480,427  $  7,514,706         $ 2,989,409  $ 3,981,959
                                ============   ============  ============         ===========  ===========
Net Profits Income ............ $ 14,389,316   $ 11,660,510  $  6,691,336         $ 2,609,358  $ 3,436,186
                                ============   ============  ============         ===========  ===========
</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, 2001, this fee was $23,925 per month and is subject to
          adjustment each May based on an oil and gas industry index.

                                                                               7

<PAGE>

Before adjustment for excess costs (see "Excess Costs" below), total costs
deducted in the calculation of net profits income were $7,340,805 in 2001,
$5,826,375 in 2000 and $4,732,936 in 1999. The 26% increase in costs from 2000
to 2001 and the 23% increase in costs from 1999 to 2000 are primarily
attributable to increased production and property tax and other purchaser
deductions associated with higher revenues. 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

At the beginning of 1999, accumulated excess costs and accrued interest for the
Texas 75% net profits interests totaled $519,817. During 1999, costs exceeded
revenues for properties underlying the Texas 75% net profits interests by
$327,318 and for the properties underlying the Oklahoma 75% net profits
interests by $105,471. Excess costs for the Texas 75% net profits interests were
primarily the result of low oil prices and increased development costs for a
1998 carbon dioxide injection project, while excess costs for the Oklahoma 75%
net profits interests were primarily because of low oil prices and reduced oil
sales volumes related to mechanical complications on one of the underlying
properties.

With improved oil prices, recoveries of excess costs and accrued interest
totaled $911,223 for the Texas 75% net profits interests and $106,890 for the
Oklahoma 75% net profits interests in the last half of 1999 and first half of
2000. Excess costs and accrued interest were fully recovered for the Texas 75%
net profits interests in May 2000 and for the Oklahoma 75% net profits interests
in October 1999. There were no excess costs in 2001.

In February and March 2002, total excess costs and accrued interest of $71,006
were incurred on the Texas 75% net profits interests as a result of lower oil
prices and increased development costs. These costs must be recovered from the
properties underlying the Texas 75% net profits interests before they can again
contribute to trust net profits income.

See Note 5 to Financial Statements.

Fourth Quarter 2001 and 2000

During the quarter ended December 31, 2001, the trust received net profits
income totaling $2,609,358, compared with fourth quarter 2000 net profits income
of $3,436,186. The 24% decrease in net profits income from fourth quarter 2000
to 2001 was primarily because of lower product prices.

Administration expense was $27,285 and interest income was $1,299, resulting in
fourth quarter 2001 distributable income of $2,583,372, or $0.430562 per unit.
Distributable income for fourth quarter 2000 was $3,430,356 or $0.571726 per
unit. Distributions to unitholders for the quarter ended December 31, 2001 were:

              Record Date               Payment Date              Per Unit
           -----------------          -----------------          ----------
           October 31, 2001           November 15, 2001          $ 0.137660
           November 30, 2001          December 14, 2001            0.150764
           December 31, 2001          January 15, 2002             0.142138
                                                                 ----------
                                                                 $ 0.430562
                                                                 ==========

Volumes

Fourth quarter 2001 underlying oil sales volumes were 98,786 Bbls, or 21% higher
than 2000 levels. Underlying gas sales volumes were 776,281 Mcf, or 14% higher
than 2000 levels. Volumes increased primarily because of the timing of cash
receipts.

Prices

The average fourth quarter 2001 oil price was $22.74 per Bbl, 27% lower than the
fourth quarter 2000 average price of $31.18. The average fourth quarter gas
price was $3.00 per Mcf in 2001, 31% lower than the fourth quarter 2000 average
price of $4.33. For further information about oil and gas prices, see "Years
Ended December 31, 2001, 2000 and 1999 - Prices" above.

Costs

Costs deducted in the calculation of fourth quarter 2001 net profits income
increased $56,137, or 4%, from fourth quarter 2000. This was the result of
increased property tax partially offset by lower development costs primarily
related to a carbon dioxide project on one of the properties underlying the
Texas 75% net profits interests.

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
                                                                 -------------------------------------
                                                                      2001                 2000
                                                                 ---------------      ----------------
<S>                                                              <C>                  <C>
Assets

  Cash and short-term investments ...........................    $       852,349      $     1,048,031

  Interest to be received ...................................                479                3,307

  Net profits interests in oil and gas properties - net
    (Notes 1 and 2) .........................................         28,895,086           30,755,456
                                                                 ---------------      ---------------

                                                                 $    29,747,914      $    31,806,794
                                                                 ===============      ===============

Liabilities and Trust Corpus

  Distribution payable to unitholders .......................    $       852,828      $     1,051,338

  Trust corpus (6,000,000 units of beneficial
     interest authorized and outstanding) ...................         28,895,086           30,755,456
                                                                 ---------------      ---------------

                                                                 $    29,747,914      $    31,806,794
                                                                 ===============      ===============
</TABLE>

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

STATEMENTS OF DISTRIBUTABLE INCOME

<TABLE>
<CAPTION>
                                                             Year Ended December 31
                                            ----------------------------------------------------------
                                                  2001                2000                 1999
                                            ---------------      ---------------      ---------------
<S>                                         <C>                  <C>                  <C>
Net profits income ......................   $    14,389,316      $    11,660,510      $     6,691,336

Interest income .........................            19,050               27,228               11,098
                                            ---------------      ---------------      ---------------

  Total income ..........................        14,408,366           11,687,738            6,702,434

Administration expense ..................           198,482              185,624              152,631
                                            ---------------      ---------------      ---------------

  Distributable income ..................   $    14,209,884      $    11,502,114      $     6,549,803
                                            ===============      ===============      ===============

  Distributable income per unit
    (6,000,000 units) ...................   $     2.368314       $      1.917019      $     1.091635
                                            ==============       ===============      ==============
</TABLE>

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

STATEMENTS OF CHANGES IN TRUST CORPUS

<TABLE>
<CAPTION>
                                                             Year Ended December 31
                                            ---------------------------------------------------------
                                                  2001                  2000               1999
                                            ---------------       ---------------     ---------------
<S>                                         <C>                   <C>                 <C>
Trust corpus, beginning of year .......     $    30,755,456       $    33,005,334     $    36,024,941

Amortization of net profits
  interests ...........................          (1,860,370)           (2,249,878)         (3,019,607)

Distributable income ..................          14,209,884            11,502,114           6,549,803

Distributions declared ................         (14,209,884)          (11,502,114)         (6,549,803)
                                             --------------        --------------     ---------------

TTrust corpus, end of year ............      $   28,895,086        $   30,755,456     $    33,005,334
                                             ==============        ==============     ===============
</TABLE>

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

See Accompanying Notes to Financial Statements.


                                                                               9

<PAGE>

Cross Timbers Royalty Trust
- --------------------------------------------------------------------------------

NOTES TO FINANCIAL STATEMENTS

1.   Trust Organization and Provisions

     Cross Timbers Royalty Trust was created on February 12, 1991 by
predecessors of XTO Energy, 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 $32,205,363 as of December 31, 2001 and was
$30,344,993 as of December 31, 2000.

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.


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 $1.08 per MMBtu
($0.107183 per unit) in 2001, $1.06 per MMBtu ($0.120389 per unit) in 2000 and
$1.02 per MMBtu ($0.157564 per unit) in 1999. Such credit, based on the
unitholder's pro rata share of qualifying production, may not reduce the
unitholder's

                                                                              10

<PAGE>

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 is considering an extension of existing energy tax credits beyond
the scheduled December 31, 2002 expiration date, as well as the creation of
similar new tax credits. During 2001, the U.S. House passed a bill that would
extend existing Section 29 tax credits on certain production, while the U.S.
Senate is considering a separate bill to address energy tax credits, including
Section 29. The potential effect of any final legislation of unitholders in
unknown.

5.   Excess Costs

     XTO Energy has advised the trustee that costs exceeded revenues from the
underlying properties of the 75% net profits interests during 1998 and 1999,
which were recovered during 1999 and 2000. 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.
The following is a summary of changes in excess costs and recoveries by
conveyance during 1999 and 2000.

<TABLE>
<CAPTION>
                                                                     Year Ended December 31,
                                                            ----------------------------------------
                                                                2000                  1999
                                                            -----------     ------------------------
                                                                Texas          Texas      Oklahoma
                                                            -----------     -----------  -----------
<S>                                                         <C>             <C>          <C>
Excess costs and accrued interest - beginning of period ..  $   375,802     $   519,817  $       -
Excess costs .............................................          -           327,318      105,471
Accrued interest .........................................        8,034          56,054        1,419
Recovery of excess costs and accrued interest ............     (383,836)       (527,387)    (106,890)
                                                            -----------     -----------  -----------

Excess costs and accrued interest - end of period ........  $       -       $   375,802  $       -
                                                            ===========     ===========  ===========

Net to trust (75%) .......................................  $       -       $   281,852  $       -
                                                            ===========     ===========  ===========
</TABLE>

     In February and March 2002, total excess costs and accrued interest of
$71,006 were incurred on the Texas 75% net profits interests as a result of
lower oil prices and increased development costs.

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, 2001 was $23,925 per
month, or $287,100 annually (net to the trust of $17,944 per month or $215,325
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 1, 2002, 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 2001 and 2000:

<TABLE>
<CAPTION>
                                                                          Distributable
                                      Net Profits     Distributable          Income
                                        Income            Income            per Unit
                                    -------------     --------------     ---------------
<S>                                 <C>               <C>                <C>
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
                                    =============     ==============     =============
2000
- ----
First Quarter ..................    $   2,352,880     $    2,300,796     $    0.383466
Second Quarter .................        2,477,134          2,424,630          0.404105
Third Quarter ..................        3,394,310          3,346,332          0.557722
Fourth Quarter .................        3,436,186          3,430,356          0.571726
                                    -------------     --------------     -------------
                                    $  11,660,510     $   11,502,114     $    1.917019
                                    =============     ==============     =============
</TABLE>

                                                                              11

<PAGE>

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
- --------------------------------------------------------------------------------

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

                                                                              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.

AUDITORS
- --------

Arthur Andersen LLP
Fort Worth, Texas

LEGAL COUNSEL
- -------------

Thompson & Knight L.L.P.
Dallas, Texas

TAX COUNSEL
- -----------

Winstead Sechrest & Minick P.C.
Houston, Texas

TRANSFER AGENT AND REGISTRAR
- ----------------------------

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

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23.1
<SEQUENCE>4
<FILENAME>dex231.txt
<DESCRIPTION>CONSENT OF ARTHUR ANDERSEN LLP
<TEXT>
<PAGE>

                                                                    EXHIBIT 23.1

                     INDEPENDENT PUBLIC ACCOUNTANTS' CONSENT

Cross Timbers Royalty Trust
Dallas, Texas

As independent public accountants, we hereby consent to the incorporation by
reference in Amendment No. 2 to Registration Statement No. 333-56983 on Form S-3
of XTO Energy Inc. and Cross Timbers Royalty Trust and in the Post-Effective
Amendment No. 1 to the Registration Statement No. 33-55784 on Form S-8 of XTO
Energy Inc. of our report dated March 19, 2002, included in the Annual Report on
Form 10-K of Cross Timbers Royalty Trust for the year ended December 31, 2001.




ARTHUR ANDERSEN LLP

Fort Worth, Texas
March 27, 2002


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23.2
<SEQUENCE>5
<FILENAME>dex232.txt
<DESCRIPTION>CONSENT OF MILLER AND LENTS, LTD
<TEXT>
<PAGE>


                                                                    EXHIBIT 23.2

               [LETTERHEAD OF MILLER AND LENTS, LTD. APPEARS HERE]

                                                       March 27, 2002

Cross Timbers Royalty Trust
P.O. Box 830650
Dallas, TX 75283-0650

           Re:   Cross Timbers Royalty Trust
                 2001 Annual Report on Form 10-K

Gentlemen:

           The firm of Miller and Lents, Ltd., consents to the use of its name
and to the use of its report dated March 21, 2002, regarding the Cross Timbers
Royalty Trust Proved Reserves and Future Net Revenues as of January 1, 2002, in
the 2001 Annual Report on Form 10-K.

           Miller and Lents, Ltd., has no interests in the Cross Timbers Royalty
Trust or in any affiliated companies or subsidiaries and is not to receive any
such interest as payment for such reports and has no director, officer, or
employee otherwise connected with Cross Timbers Royalty Trust. We are not
employed by Cross Timbers Royalty Trust on a contingent basis.

                                                       Yours very truly,

                                                       MILLER AND LENTS, LTD.


                                                     By    /s/ James C. Pearson
                                                         -----------------------
                                                         James C. Pearson
                                                         Chairman

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99.1
<SEQUENCE>6
<FILENAME>dex991.txt
<DESCRIPTION>ASSURANCE LETTER REGARDING ARTHUR ANDERSEN LLP
<TEXT>
<PAGE>

                                                                    EXHIBIT 99.1


                  [LETTERHEAD OF BANK OF AMERICA APPEARS HERE]


March 27, 2002

Securities and Exchange Commission
450 Fifth Street, NW
Washington, DC 20549


Ladies and Gentlemen:

Arthur Andersen LLP (Andersen) has audited the financial statements of Cross
Timbers Royalty Trust as of December 31, 2001, and Andersen has represented to
Bank of America, N.A., Trustee, that:

   .    the audit was subject to Andersen's quality control system for the U.S.
        accounting and auditing practice to provide reasonable assurance that
        the engagement was conducted in compliance with professional
        standards, and

   .    there was appropriate continuity of Arthur Andersen personnel working
        on the audit, and

   .    there was availability of national office consultation to conduct the
        relevant portions of the audit.

Sincerely,


/s/ RON E. HOOPER
- ----------------------------------
Ron E. Hooper
Senior Vice President

</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
-----END PRIVACY-ENHANCED MESSAGE-----
